MIRANT CORP - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

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

FOR THE TRANSITION PERIOD FROM TO

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MIRANT CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 001-16107 58-2056305
(State or other jurisdiction of (Commission File Number) (I.R.S. Employer
Incorporation or Organization) Identification No.)

1155 PERIMETER CENTER WEST, SUITE 100, 30338
ATLANTA, GEORGIA (Zip Code)
(Address of Principal Executive Offices)

(678) 579-5000 WWW.MIRANT.COM
(Registrant's Telephone Number, Including Area Web Page
Code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Act). Yes [X] No [ ]
Aggregate market value of voting stock held by non-affiliates of the
registrant was approximately $2,934,000,000 on June 28, 2002 (based on $7.30 per
share, the closing price in the daily composite list for transactions on the New
York Stock Exchange for that day).
Aggregate market value of voting stock held by non-affiliates of the
registrant was approximately $1,256,602 on April 28, 2003, (based on $3.11 per
share, the closing price in the daily composite list for transactions on the New
York Stock Exchange for that day). As of April 28, 2003, there were 404,052,225
shares of the registrant's Common Stock, $0.01 par value per share outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Report, to the extent not set
forth herein, is incorporated by reference from the Registrant's definitive
proxy statement relating to the annual meeting of shareholders to be held in
2003, which statement shall be filed with the Securities and Exchange Commission
within 120 days after the end of the fiscal year to which this Report relates.
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TABLE OF CONTENTS

1

DEFINITIONS

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PART I

ITEM 1. BUSINESS

OVERVIEW

We are an international energy company, incorporated in Delaware on April
20, 1993, that produces and sells electricity in the United States, the
Philippines and the Caribbean. As of December 31, 2002, we owned or controlled
through operating agreements more than 21,800 MW of electric generating capacity
around the world, of which more than 18,000 MW was located in the United States.
We expect to complete construction of approximately 990 MW of generating
capacity by December 2003. In North America, we also have rights to
approximately 3.1 billion cubic feet per day of natural gas production, more
than 2.1 billion cubic feet per day of natural gas transportation and almost
13.4 billion cubic feet of natural gas storage as of December 31, 2002.

In addition, in North America we use derivative financial instruments
primarily to hedge and optimize our generating assets, and we also take
proprietary commodity positions. In the Philippines, most of our generation
output is sold under long-term contracts. Our operations in the Caribbean
include fully integrated electric utilities, which generate power sold to
residential, commercial and industrial customers.

We manage our business through two principal operating segments. Our North
America segment consists of generation capacity and commodity trading operations
managed as a combined business and our International segment includes generation
businesses in the Philippines, Curacao and Trinidad and integrated utilities in
the Bahamas and Jamaica. In 2002, we closed our European trading operations and
sold our distribution and generation assets in Europe and Asia. Prior to the
sale of these assets, they are reflected in the International segment. The other
reportable business segment is Corporate.

We have incurred substantial indebtedness on a consolidated basis to
finance our business. As of December 31, 2002, our total consolidated
indebtedness was $8.9 billion (approximately $4.4 billion of which was recourse
to Mirant Corporation). We are working on a restructuring plan pursuant to which
we will ask certain of our creditors to defer repayments of principal. We refer
you to the discussions of certain risks relating to our restructuring in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Factors That Could Affect Future Performance" and the notes to our
consolidated financial statements.

The annual, quarterly, and current reports, and any amendments to those
reports, that we file with or furnish to the SEC are available free of charge on
our website at www.mirant.com as soon as reasonably practicable after they are
electronically filed with or furnished to the SEC. 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.

THE MARKETS

The power industry is one of the largest industries in the United States
and has influence on practically every aspect of our economy, with an estimated
market of approximately $250 billion of electricity sales in 2002, according to
the Energy Information Administration. Historically, the power generation
industry has been characterized by electric utility monopolies selling to a
franchised customer base. In response to increasing customer demand for access
to low-cost electricity and enhanced services, new regulatory initiatives have
been adopted to increase wholesale competition in the power industry. For the
past decade, the power industry has been deregulated at the wholesale level,
allowing generators to sell directly to load serving entities.

Cambridge Energy Research Associates estimates that over the past five
years competitive generation grew from almost nothing to 40% of total generation
in the United States. This rapid growth in competitive generation, coupled with
economic slowdown and regional market uncertainty in certain

3

regions, has contributed to the fall of wholesale power prices and the rise of
reserve margins over the majority of the country. The North American Electric
Reliability Council ("NERC") estimates summer regional reserve margins in excess
of 20% for most regions. In response to these indications, companies have made
large-scale cancellations of power projects across the country. According to
NERC, over 47,000 MW of proposed additions are expected to be cancelled from
2002 to 2004.

In addition to increased reserve margins and cancelled power projects, the
industry has experienced a great deal of turmoil associated with the exit of
prominent energy traders, corporate scandals and uncertainty in the sanctity of
contracts. Combined with an economic slowdown and a decline in wholesale power
prices, these factors have contributed to a loss of confidence in the
competitive power industry.

STRATEGY

Mirant owns and operates power generation plants in the United States, the
Philippines and the Caribbean. As of March 31, 2003, in the Philippines and the
Caribbean, Mirant owned approximately 3,277 MW in generation plants whose output
is sold on a long-term basis through contracts or through franchise businesses.
In the United States, Mirant owned or controlled through operating agreements
approximately 17,717 MW of generation capacity, of which the majority is located
in the proximity of major metropolitan areas in the Northeast, Mid-Atlantic
region and California. Over 35% of Mirant's existing United States generating
capacity has dual-fuel capabilities, giving Mirant added flexibility from its
portfolio. We optimize our North American assets through an integrated risk
management platform which dispatches the units, purchases fuels and sells the
electricity generated to consumers either in the wholesale market or through
long-term contracts. We use the flexibility of our generating units to maximize
the benefit to our customers and us.

Due to recent industry events, we have adopted near-term strategic
objectives that will guide our activities until market fundamentals improve.
These include:

- Successfully complete the restructuring of our debt;

- Reduce uncertainty associated with our business in California;

- Focus on core markets internationally and in North America;

- Enhance our liquidity position through asset divestitures and reductions
in posted collateral;

- Reduce capital expenditures;

- Continue to lower overhead cost; and

- Realize operating efficiency in our United States generation portfolio.

We view our power generation and risk management as an integrated business.
In this respect, we closely coordinate the dispatch of our power plants, the
purchase of fuels and the sale of electricity between our generating plants and
our risk management unit. We use our risk management organization to manage
price and volume risk associated with selling power and purchasing fuels in the
markets in which we operate. Although we continue to see decreasing liquidity in
the energy markets on a longer-term basis, we still see liquidity on a
short-term basis to adequately manage our business.

COMPETITION

As an international competitive energy company, we face competition both in
the United States and in international markets. In the power generation markets,
we compete in the development and operation of energy-producing projects, and
our competitors in this business include various utilities, industrial companies
and independent power producers (including affiliates of utilities).

The following summarizes our competitive position in our key markets:

- North America: We were ranked as the tenth and fifth-largest competitive
power company in net equity ownership of generation capacity in July 2002
and July 2001, respectively, according to the

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Platts "Global Power Report." As of March 31, 2003, we owned or
controlled through operating agreements 17,717 MW of capacity in the
United States, of which approximately 12,000 MW of generating capacity is
located in close proximity to major metropolitan areas. Our generation
units consume a variety of fuels, and we have the flexibility to consume
multiple types of fuels in over 35% of our United States generating
plants.

- Philippines: As of March 31, 2003, we had a net ownership interest in
approximately 2,263 MW of generation capacity in the Philippines, and we
are the largest private producer of electricity in that country. In
general, our coal-fired and gas-fired plants in the Philippines are among
the lowest operating cost plants in their market.

- The Caribbean: We have ownership interests in electric utilities, power
plants and transmission facilities in the Caribbean, which are located in
the Bahamas, Trinidad and Tobago, Jamaica and Curacao. Our generation
investments in Trinidad and Curacao (Curacao Utilities Company) have
long-term power purchase agreements and our investments in the Bahamas,
Jamaica and Curacao (Aqualectra) are franchise utilities with exclusive
rights to serve their respective customer bases.

Because each company may employ widely differing strategies in their fuel
supply and power sales contracts with regard to pricing, terms and conditions,
it can be difficult for us to assess our position versus the position of
existing power providers and new entrants. Additionally, many states and
countries are considering or implementing different types of regulatory and
privatization initiatives that are aimed, in some instances, at increasing and,
in other instances, decreasing competition in the power industry. Increased
competition that has resulted from some of these initiatives has already
contributed to a reduction in electricity prices and put pressure on electric
utilities to lower their costs, including the cost of purchased electricity.

In general, we believe that our regional generating presence combined with
our risk management expertise will allow us to remain competitive during
volatile or otherwise adverse market circumstances. Over the past year, we have
modified our business strategy, limiting our business to our current North
America, Philippines and Caribbean operations. This includes the sale of our
investments in China, Europe, South America and Guam, the closure of our trading
operations in Europe and the reduction of physical gas volumes in North America.
However, our focus on optimizing our generation portfolio through our integrated
business in the United States remains central to our strategy.

BUSINESS SEGMENTS

For selected financial information about our business Segments and
information about geographic areas, see Note 20 to our consolidated financial
statements. See "Item 2 Properties" for a complete asset list.

NORTH AMERICA

Through various subsidiaries, we own or control under operating agreements
power generation assets and natural gas pipeline capacity in the United States
and Canada, which we seek to optimize by our commodity trading operations.

In the United States, as of December 31, 2002, we own, lease or control,
through contracts, over 18,000 MW of generation capacity in the major markets we
have strategically targeted. In the United States and Canada, we also controlled
access, through contracts, to approximately 3.1 billion cubic feet per day of
natural gas production, more than 2.1 billion cubic feet per day of natural gas
transportation and almost 13.4 billion cubic feet of natural gas storage as of
December 31, 2002. Our commodity trading subsidiaries, Mirant Americas Energy
Marketing, L. P. ("Mirant Americas Energy Marketing") and Mirant Canada Energy
Marketing, Ltd. ("Mirant Canada Energy Marketing"), operate 24-hours a day and
Mirant Americas Energy Marketing is one of the leading electricity and gas
marketers in the United States markets. Our commodity trading operations trade
energy and energy-linked commodities, consisting primarily of electricity, gas,
coal and oil. In 2002, we produced 73 million megawatt-hours of electricity,

5

sold 312 million megawatt-hours of electricity and sold or marketed an aggregate
average of 21 billion cubic feet per day of natural gas.

In 2002, we completed construction of over 1,700 MW of additional
generation capacity. In addition, during 2002 we sold or announced sales of
approximately 900 MW of generation capacity related to operations in
non-strategic markets and sold Mirant Americas Production Company, which held
the assets and operations we acquired from Castex LaTerre, Inc. ("Castex") in
2001. In March 2003, we completed the sale of Mirant Americas Energy Capital, LP
("Mirant Americas Energy Capital"), which provided secured financing to
independent oil and gas producers for the purpose of developing, acquiring and
producing oil and gas properties in North America in exchange for the rights to
market those commodities.

We attempt to create value by integrating commodity trading with our asset
management skills. This strategy combines our risk management and energy
marketing expertise with the generation capacity we control and our access to
natural gas to maximize opportunities existing in the power and natural gas
markets. This integration of our strategically located generation capacity, our
access to natural gas and our commodity trading operations allows us to
capitalize on arbitrage opportunities across energy products, between regions
and over time.

We believe our operations provide national market access and intelligence,
and commodity trading opportunities, as well as logistics expertise in power and
various types of fuels used to generate electricity. This, coupled with our
reliable power supply, gives us a wide range of opportunities to create value
through structured contracts for power and natural gas as well as the ability to
capitalize on market volatility. Our current development plan, in light of the
current environment in our industry, is to complete the construction of
approximately 925 MW related to existing projects scheduled to begin commercial
operation in 2003 and to postpone or cancel projects scheduled for completion
beyond 2003. See "Item 2 Properties" for a list of the projects under
development.

INTERNATIONAL

Through various subsidiaries, we own or control under operating agreements
various generation, transmission and distribution operations in the Philippines
and the Caribbean. During 2002, as part of our restructuring, we completed the
sale of our international investments in Germany, the United Kingdom, China,
Brazil, Australia and Korea. In 2002, we also closed our European trading
operations. For 2002, in our International segment, we added approximately 445
MW of additional generation capacity to our portfolio through construction and
acquisition. A complete list of our international properties is contained in
"Item 2 Properties."

ASIA-PACIFIC

Philippines

We had a net ownership interest in eight plants in the Philippines with
approximately 2,422 MW of generating capacity as of December 31, 2002. We sell
electricity from our plants through long-term energy conversion agreements with
the government-owned National Power Corporation ("NPC") for the majority of our
available capacity. Under the energy conversion agreements, we accept fuel from
NPC and convert that fuel to electricity. In addition to our energy conversion
agreements, we have joint marketing agreements with NPC for the 218 MW and 35 MW
of excess capacity from our Sual and Pagbilao plants, respectively. Currently,
electricity from the excess Sual capacity is provided to select markets such as
economic zones, industries and private electric distribution companies and
cooperatives.

Under the energy conversion agreements, we receive both fixed capacity fees
and variable energy fees. The energy conversion agreements are executed under
the government's build-operate-transfer program. At the end of the term of each
energy conversion agreement, the associated plant is required to be transferred
to NPC, free from any lien or payment of compensation. The agreements end in
October 2024 for Sual and August 2025 for Pagbilao. NPC acts as both the fuel
supplier and the energy off-taker under the

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energy conversion agreements. NPC procures all of the fuel necessary for each
plant, at no cost to Mirant's subsidiaries and has accepted substantially all
fuel risks and fuel related obligations other than each plant's actual fuel
burning efficiency. Over 90% of the revenues are expected to come from fixed
capacity charges that are paid without regard to the dispatch level of the
plant. Nearly all of the capacity fees are denominated in United States dollars.
The energy fees have both United States dollar and Philippine Peso components
that are both indexed to inflation.

The energy conversion agreements contain a provision under which NPC bears
most of the financial risks for both political force majeure and change of law.
The majority of NPC's obligations under the energy conversion agreements are
guaranteed by the full faith and credit of the Philippine government.

The majority of the projects in the Philippines have been granted preferred
or pioneer status that, among other things, have qualified them for income tax
abatements of three to six years. The abatement for the Pagbilao plant expired
in 2002, and the abatement for the Sual plant expires in October 2005.

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. Within
three years from its effectiveness, competition in the retail supply of
electricity and open access to the transmission and distribution systems is
planned. Prior thereto, concerned government agencies are required 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 March 2003, most
of these changes have started but are considerably behind the schedule set by
the Department of Energy.

A significant component of this legislation is the mandate to privatize the
assets of NPC, including its generation and transmission assets, as well as
contracts with the Independent Power Producers ("IPP"). Under the EPIRA, NPC's
generation assets will be sold through transparent, competitive public bidding,
while all transmission assets will be transferred to the Transmission Company
("TRANSCO") -- initially a government-owned entity that will eventually be
privatized.

The EPIRA also mandates the creation of the Power Sector Assets and
Liabilities Management Corporation ("PSALM"), which is to accept transfer of all
assets and assume all outstanding obligations of NPC, including its obligations
to the IPP. One of PSALM's responsibilities is to manage these IPP contracts
after NPC's privatization. PSALM is also responsible for privatizing at least
70% of all the transferred generating assets and IPP contracts no later than
three years from the effective date of the law. Consistent with the announced
policy of the government, the law contemplates continued payments of NPC's
obligations under its energy conversion agreements. The energy conversion
agreements of Mirant Asia-Pacific Ventures, Inc. ("Mirant Asia-Pacific") are not
involuntarily assignable. Mirant Asia-Pacific is in continuing discussions with
NPC and PSALM on a proposal to add PSALM as an additional obligor under our
existing IPP contracts.

Additionally, the Republic of the Philippines issued performance
undertakings (the "Undertakings") to guarantee the performance of NPC's
obligations under our energy conversion agreements. The EPIRA does not expressly
repeal the Undertakings but the ultimate effect of the privatization efforts on
our operations, our contracts or the Undertakings cannot now be absolutely
determined.

The deregulation of the Philippine electricity industry and the
privatization of NPC have been long anticipated, and the reform law is not
expected to have a material impact on the existing assets and operations of
Mirant Asia-Pacific.

Philippines IPP Review

Pursuant to the Electric Power Industry Reform Act of 2001, a governmental
inter-agency committee reviewed IPP contracts and reported that some contracts
had legal or financial issues requiring further review or action. These included
several of Mirant's contracts. Subsequently, Mirant Philippines, the

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PSALM, the Department of Energy, and the Department of Justice entered into a
letter agreement establishing a general framework ("Framework Agreement") for
resolving all outstanding issues raised by the committee about Mirant's IPP
contracts. The key terms of the new agreements are: Pagbilao will no longer
nominate capacity beyond the plant's nominal capacity; Pagbilao will agree to
settle certain issues on interpretation of its ECA relating to penalties
resulting from forced outages and waive past claims relating thereto; the ECA
for Navotas II will be terminated and Mirant will acquire rights to the Navotas
II plant in return for a net payment of approximately $6 million; Mirant will be
free to sell Navotas II and excess Pagbilao energy output in the open market;
and Sual and Pagbilao will waive their claims to be reimbursed for local
business taxes. Any issue with respect to Ilijan is outside the terms of the
Framework Agreement.

In March 2003, the conditions precedent for the Sual and Pagbilao
components of the Framework Agreement were satisfied and the implementing
agreements relating to both became effective. Navotas I was taken out of the
coverage of the Framework Agreement as the "cooperation period" had ended, while
the period for meeting the conditions precedent for Navotas II was extended to
May 12, 2003. The benefits to Mirant are confirmation that the original
contracts for Sual and Pagbilao remain intact and will be reaffirmed; no
resultant material net income impact; reduction in potential penalty payments
due to outages at Pagbilao; acquisition of ownership rights of Navotas II plant;
and facilitation of further energy sales from Sual, Pagbilao and Navotas II.

Clean Air Act

In July 1999, the Philippines enacted legislation, Republic Act No. 8749,
otherwise known as the Philippine Clean Air Act of 1999 (the "Clean Air Act"),
which applies to stationary emission sources and other operating plants. The
Department of Environment and Natural Resources has promulgated Administrative
Order No. 2000-81, the Act's Implementing Rules and Regulations ("IRRs"), which
took effect on November 25, 2000 and are in the process of being implemented.
Provisions of the Clean Air Act affect the compliance of operating plants and
their ability to serve as base load capacity for the grid. However, the IRRs
provided regulatory flexibility for existing stationary sources which have
difficulty complying with the requirements of the Clean Air Act to achieve full
compliance by July 2004.

The provisions of the Clean Air Act and past practice of the Department of
Environment and Natural Resources suggest potential for increasingly stringent
standards in emissions from all sources to maintain and/or improve the air
quality. This may require additional controls or equipment on some of Mirant
Asia-Pacific's plants in order to comply with the emission reduction goals and
targets set forth in the Clean Air Act.

We believe that the Sual plant and the Ilijan plant can comply with the
current requirements of the Clean Air Act and the IRRs. Some additional
pollution controls or other expenditures may be required for the Pagbilao,
Mindoro and Bulacan plants to comply with the IRRs. We do not expect these
expenditures to be material. We believe that the Navotas II plant will not be
affected significantly by the Clean Air Act and the IRRs. Mirant Asia-Pacific
has been closely following the development of the IRRs and is making contingency
plans, which are capable of meeting the standards under the IRRs within the
timeframe of the implementation of the IRRs.

Guam

Mirant Guam (Tanguisson) Corp. operates the 50 MW Tanguisson power plant in
Guam, a territory of the United States. The Tanguisson power plant sells power
to the Guam Power Authority under a 20-year energy conversion agreement, which
ends in 2017. In April 2003, Mirant completed the sale of its Tanguisson power
plant for $16 million.

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CARIBBEAN

Grand Bahama Power Company ("Grand Bahama Power")

We own a 55.4% interest in Grand Bahama Power, an integrated utility that
generates, transmits, distributes and sells electricity on Grand Bahama Island.
Grand Bahama Power operates generation facilities and 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, the state-owned transmission and distribution monopoly, which serves
nearly 300,000 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 Trinidad and
Tobago Electricity Commission, which expires in 2009 and is unconditionally
guaranteed by the government of Trinidad and Tobago. The fuel is provided by the
Trinidad and Tobago Electricity Commission.

Jamaica Public Service Company Limited ("JPSCo")

We own an 80% interest in JPSCo, a fully integrated electric utility on the
island of Jamaica. JPSCo operates under a 20-year All-Island Electric License
that expires in 2021 and is subject to monitoring and rate regulation by the
Office of Utilities Regulation. JPSCo operates generation facilities and
supplies energy to approximately 517,000 residential, commercial and industrial
customers in Jamaica. The Company is regulated under a rate of return model at
present with annual adjustments for inflation and foreign exchange movements.
Starting with the next rate case in 2004, JPSCo will be regulated under a price
cap model with rate cases held every five years.

Curacao Utilities Company ("CUC")

We own a 25.5% interest in the CUC project under construction at the Isla
Refinery in Curacao, Netherlands Antilles. The 134 MW facility will provide
electricity, steam, desalinated water and compressed air to the refinery, and up
to 50 MW of electricity to the Curacao national grid. The facility is expected
to be completed in the second quarter of 2003. We will operate and manage the
facility through our wholly owned subsidiary, Curacao Utility Operating Company.

Aqualectra

We own a $40 million 16.75% convertible preferred equity interest in
Aqualectra, an integrated water and electric company in Curacao, Netherlands
Antilles. Aqualectra has electric generating capacity of 235 MW and drinking
water production capability of 69,000 cubic meters per day. Aqualectra serves
approximately 60,000 electricity customers and 62,000 water customers.
Aqualectra has a call option and Mirant has a put option related to this
investment. The options are exercisable by the earlier of three years from
December 2001 or privatization and expire three years after this trigger date.
Mirant can convert its preference shares to common shares during the vesting
period.

REGULATORY ENVIRONMENT

INTERNATIONAL REGULATION

Our international operations are subject to regulation by various foreign
governments and regulatory authorities. The laws and regulations that apply to
each of our international projects are more fully discussed under the
description of the particular project listed above.

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UNITED STATES PUBLIC UTILITY REGULATION

The United States electric industry is subject to comprehensive regulation
at the federal and state levels. Under the Federal Power Act ("FPA"), the
Federal Energy Regulatory Commission ("FERC") has the exclusive jurisdiction
over sales of electricity at wholesale and the transmission of electricity in
interstate commerce. Except for those subsidiaries that either own a qualifying
facility or that own generation or sell electricity wholly within the Electric
Reliability Council of Texas ("ERCOT"), Mirant's subsidiaries that own
generating facilities or sell electricity at wholesale in the United Sates are
public utilities subject to the FERC's jurisdiction under the FPA and must file
rates with the FERC applicable to their wholesale sales. The FERC has accepted
for filing tariffs for the sale of energy and capacity at wholesale based on
market-based rates for each of those Mirant subsidiaries. Some Mirant
subsidiaries have also received authority from the FERC under the FPA to sell
ancillary services at market-based rates. The majority of the output of our
generation facilities in the United States is sold at market prices under
market-rate authority granted by the FERC. Certain of our facilities, however,
are subject to reliability- must-run ("RMR") agreements that under some
circumstances dictate the price at which electricity is sold from such
facilities. Our subsidiaries that are public utilities under the Federal Power
Act are also subject to regulation by the FERC relating to accounting and
reporting requirements, as well as oversight of mergers and acquisitions,
securities issuances and dispositions of facilities.

In granting authority to Mirant's subsidiaries to sell electricity at
wholesale at market-based rates, the FERC has reserved the right to revoke or
limit that market-based rate authority if the FERC subsequently determines that
a Mirant subsidiary receiving such authority or any of its affiliates possesses
excessive market power. If the FERC were to revoke the market-based rate
authority of Mirant's subsidiaries, those subsidiaries would have to file, and
obtain the FERC's approval of, cost-based rate schedules for all or some of
their sales of electricity at wholesale.

State or local authorities have historically overseen and regulated the
distribution and sale of retail electricity to the ultimate end user. They have
also had regulatory authority with respect to siting, permitting, and the
construction of generating and transmission facilities. Where individual states
have allowed for retail access, state and local authorities will normally
establish the bidding rules for default service to customers who choose to
remain with their regulated utility suppliers. As a result, our existing
generation may be subject to a variety of state and local regulations regarding
maintenance and expansion of our facilities and financing capital additions
depending upon whether the law of the state in which such generation is located
provides for state public service commission regulation of such activities by
entities that produce electricity for sale at wholesale. Outside of ERCOT, the
terms and conditions of wholesale power sales by Mirant's subsidiaries owning
generation or selling power at wholesale are subject exclusively to FERC
regulation under the FPA and to tariff requirements of such entities as regional
transmission groups and independent system operators as authorized by the FERC
under the FPA.

We are not subject to the Public Utility Holding Company Act of 1935, as
amended ("PUHCA") unless we acquire the securities of a public utility company
or public utility assets that are not exempt as an exempt wholesale generator,
foreign utility company or qualifying facility. Currently, all of Mirant's
subsidiaries owning generation in the United States are exempt wholesale
generators under the PUHCA and all of our subsidiaries owning generation outside
the United States are either foreign utility companies or exempt wholesale
generators. Our 50% owned nonconsolidated Birchwood Power Partners, L.P.
("Birchwood") facility is also a qualifying facility under the Public Utility
Regulatory Policies Act of 1978, as amended ("PURPA"). As a qualifying facility,
Birchwood is exempt from most provisions of the FPA and state laws relating to
securities, rate and financial regulation. PURPA requires electric utilities (i)
to purchase electricity generated by qualifying facilities at a price based on
the utility's avoided cost of purchasing electricity or generating electricity
itself, and (ii) to sell supplementary, back-up, maintenance and interruptible
power to qualifying facilities on a just, reasonable and non-discriminatory
basis. To qualify for qualifying facility status, the Birchwood facility must
satisfy requirements regarding the production of useful thermal energy as well
as limitations on the extent of ownership by utilities or utility affiliates.

10

In emergency conditions, such as those that occurred in California in 2000
and 2001, our public utility operations may be subject to extraordinary and
costly emergency service requirements. For example, the United States Department
of Energy exercised its emergency authority between 2000 and 2001 to require
interconnections and sales of power into the California market. Future orders of
this nature may be issued with respect to any market in the event the Department
of Energy deems emergency conditions to exist and could have a materially
negative impact on our operations.

Beginning in 1996 and continuing over the last several years, the FERC has
issued transmission initiatives that require electric transmission services to
be offered on an open-access basis unbundled from commodity sales. In December
1999, FERC issued Order No. 2000, which provided for the development of Regional
Transmission Organizations ("RTO") to control the transmission facilities within
a certain region. Compliance by transmission-owning utilities has been
inconsistent and the order has been met with significant political resistance on
the part of state public utility commissions and state governments in certain
regions of the country. For example, recently, the Virginia legislature passed a
law that bars American Electric Power ("AEP") or any other Virginia transmission
owner from joining any regional grid until after June 2004.

In addition, in July 2002 FERC initiated its Standard Market Design ("SMD")
and Interconnection rule-making proceedings. FERC's intention under the SMD
proceedings is to eliminate discrimination in transmission service, to
standardize electricity market design nationally, and to strongly encourage the
creation of RTOs. While the SMD is viewed as a positive step in the evolution of
the wholesale electric market, there is significant opposition to SMD. We cannot
predict at this time whether the SMD will be adopted as proposed or what changes
will be implemented prior to adoption.

While RTO participation by transmission-owning public utilities has been
and is expected to continue to be voluntary, the majority of such public
utilities have either joined or indicated that they will join the proposed RTO
for their region. Currently there are approximately nine proposed RTO's covering
the majority of the United States. In addition, large portions of the nation's
transmission system are currently operated by an independent entity. In each of
the following markets in which we own and operate generation facilities, the
RTO's and Independent System Operators ("ISOs") in our areas of operation
establish valid pricing and provide markets and thus liquidity. Large open
markets with clear established rules are beneficial to mitigating and hedging
against risk:

Mid-Atlantic -- The Company's Mid-Atlantic assets sell power into the
Pennsylvania-New Jersey-Maryland Interconnection ("PJM") market. PJM was
certified by the FERC as an ISO in 1997, and as an RTO in December 2002. It
is the nation's first fully functioning RTO. PJM's stated objectives are to
ensure reliability of the bulk power transmission system and to facilitate
an open, competitive wholesale electricity market. To achieve these
objectives, PJM manages the PJM Open Access Transmission Tariff (the first
power pool open access tariff approved by FERC), which provides comparable
pricing and access to the transmission system. PJM operates the PJM
Interchange Energy Market, which is the region's spot market (power
exchange) for wholesale electricity. PJM also provides ancillary services
for its transmission customers and performs transmission planning for the
region. To account for transmission congestion and losses, energy prices in
PJM are determined through a locational-based marginal pricing model and
dispatch is on a security constrained least cost basis. PJM has been
expanding its geographical boundaries to the south and west and has entered
into negotiations with the MISO to establish a common and seamless market.
This expansion was viewed favorably by the Company as it would extend the
scope and footprint of the PJM market, which would increase the market size
and liquidity of PJM. We cannot predict when PJM will be able to complete
the expansion and improve the market in its region, or when or precisely
how such expansion will impact our earnings. PJM protocols allow energy
demand to respond to price changes under locational marginal pricing.
Currently PJM has set a $1,000/MWh cap on prices for energy and a
mitigation process in designated transmission constrained areas that
provide for revenues that allow for recovery of incremental cost plus 10%.
PJM's working groups and market monitor are reviewing other energy price
mitigation measures. We cannot predict what other

11

modifications to protocols PJM may develop or precisely how such protocols
could impact our future earnings.

In the Mid-Atlantic region, our Chalk Point power plant located in
Prince George's County Maryland and our Morgantown Power Plant located in
Charles County Maryland rely on an underground oil pipeline for delivery of
number six fuel oil supply. Recently, the Maryland Public Service
Commission staff considered, but did not act on, policies that could
substantially restrict the operations of the pipeline. We cannot predict if
such regulatory actions will be reconsidered in the future. However, since
the cycling units at Chalk Point and the base load units at Morgantown are
dual fuel capable, such a potential regulatory action would not fully halt
operations, although it could potentially increase the cost of fuel oil
delivery to operate the units.

Northeast -- The Company's New York plants participate in a market
controlled by the New York Independent System Operator ("NYISO"). The NYISO
was formed to replace the New York Power Pool ("NYPP") structure in order
to comply with FERC Orders 888 and 889. Under the FERC-approved structure
for the New York markets, the NYISO coordinates the generation and
transmission system and the interfaces with neighboring market control
areas. The NYISO also provides statewide transmission service in New York
under a single tariff. To account for transmission congestion and losses,
energy prices are determined through a locational-based marginal pricing
model similar to the existing structure in the PJM market and the new
structure in New England. NYISO also administers a spot market for energy
and markets for installed capacity, operating reserves and regulation. The
Management Committee of the NYISO has recently endorsed a new methodology
for capacity payments to generators, which is known as the Demand Curve.
This methodology would provide an assured floor for existing capacity, and
appropriate price signals to incent new construction when market conditions
so dictate. The Demand Curve is currently before FERC for approval and we
cannot predict when or if it will be approved by FERC. In New York, the
FERC approved an Automated Mitigation Procedure ("AMP"), administered by
the NYISO, which caps energy bid prices in circumstances where the bidder
is perceived to have market power based on cost characteristics. When
energy bids fail the AMP test (the specific rules which are used to define
market power) they are replaced by reference bids (cost based energy prices
without any allowance for scarcity value) on a locational basis and this
new set of bids is used to determine the day-ahead prices and schedules. In
an order issued in May 2002, the FERC modified and extended the AMP
proposal indefinitely, until the NYISO implements the FERC's standard
market design rules. We cannot provide assurance if or when the FERC will
approve the Demand Curve proposal, or that the NYISO could not implement or
revert to a more restrictive AMP such as the original AMP that was imposed
prior to May 2002. In the event that a more restrictive AMP is imposed, our
earnings could be adversely affected.

Also in the Northeast, the Company's New England plants participate in
a market controlled by the Independent System Operator of New England
("ISO-NE"). In the ISO-NE markets, NEPOOL is the voluntary association of
electric utilities and other market participants in Massachusetts,
Connecticut, Maine, New Hampshire, Rhode Island, and Vermont that has
existed for more than 25 years. NEPOOL is the body that makes the rules
that govern the ISO-NE's operation of transmission systems and
administration and settlement of the wholesale electric energy, capacity,
and ancillary services markets for most of the New England region. In New
England, price mitigation is imposed in Designated Congestion Areas ("DCA")
that have transmission constrained areas. New England utilizes a
"Combustion Turbine Proxy" approach to simulate a new entrant price for
mitigation in the DCA. The ISO-NE Board initiated a new regional revision
of standard market design on March 1, 2003. The move replaced a single New
England-wide wholesale market with eight regional markets, three in
Massachusetts and five others covering each New England state. The new
system is intended to let market prices determine where new power plants
and transmission lines are most needed. The new design is being opposed by
the attorney generals of both Massachusetts and Connecticut who are
concerned about the removal of subsidies paid by rural New Englanders and
the subsequent increase in prices in the metropolitan Boston area and in
Fairfield County, Connecticut.

12

As with all Northeast markets, the ISO-NE has committees of market
participants collaboratively working to improve market rules. We cannot
predict which rules may be changed or what the impact on our earnings could
be if market rules were modified and approved by both the ISO-NE board and
FERC.

Mid-Continent -- The Company's Mid-Continent business unit covers the
Mid-west and Southeast markets and the ERCOT market in Texas. The Company's
Mid-west plants participate in a market controlled by the MISO. MISO is the
nation's first voluntary non-profit RTO and was approved by the FERC on
December 20, 2001. Beginning in March of 2004, MISO will enter a new phase
of market design similar to the successful markets in PJM. The market
features locational marginal pricing for energy and associated financial
transmission rights for market participants to manage their locational
energy risk. In addition, the market includes both a day-ahead, financial
settlement of the energy market, as well as a real-time settlement of
physical supply and demand. With the implementation of its market design,
the MISO will also have mitigation rules similar to those in place in New
York utilizing an AMP type process. The MISO and PJM are in the process of
developing a joint and common wholesale energy market with a three-stage
implementation process that should have the entire MISO/PJM footprint under
a common wholesale market by May 2005. The final market structure for the
MISO remains unsettled. MISO and the Southwestern Power Pool ("SPP") had
planned to merge regions to expand their scope and achieve operating
synergies, but recently announced that they would not merge into a single
market. We cannot predict when the final market structure in the Mid-West
will be resolved or what the ultimate impact on our earnings until the
market design is submitted to and approved by the FERC.

The Company's Texas plants participate in a market controlled by the
ERCOT, which manages a major portion of the state's electric power grid.
ERCOT oversees the transactions associated with the newly restructured
electric market and protects the overall reliability of the grid. ERCOT
represents a bulk electric system located totally within the state of
Texas. ERCOT is the only RTO that covers both the wholesale and retail
market operations. ERCOT is regulated by the Public Utility Commission of
Texas ("PUCT"). Market monitoring is done within ERCOT by the PUCT.
Mitigation measures include a $1000 price cap on bids for sale of energy
and RMR type contracts for congested areas. To improve congestion on the
local grid, the PUCT of Texas has recently established a Rulemaking
Proceeding on Wholesale Market Design Issues that will focus on adding a
nodal congestion management mechanism similar to PJM and a day-ahead
market. The company believes this change to be a positive one for the
wholesale market in ERCOT. The proceeding is expected to be completed and
revised market design in place by 2005. As with other evolving market
structures we cannot provide assurance when the enhancements will be
completed and implemented nor what the impact on our earnings will be in
the ERCOT market.

In the Southeast there are two proposed RTO's, GridFlorida and
SeTrans. Neither of these RTO's are yet functioning. We currently sell
electric energy and capacity from our facilities in these markets under
bilateral contracts that contain terms and conditions that are not
standardized and that have been negotiated on an individual basis.
Customers who participate in power transactions in this region include
investor-owned, fully integrated utilities, municipalities and electric
cooperatives.

West -- California accounts for roughly 40% of the energy consumption
in the Western Interconnection. Approximately 75% of the California's
demand is served from facilities, including Mirant's facilities, under the
administration of the California Independent System Operator ("CAISO"). The
CAISO performs control area functions, schedules transmission assets for
usage, arranges for necessary ancillary services on a day-ahead basis, and
administers a real-time balancing energy market.

The majority of our assets in California are subject to RMR agreements
with the CAISO. These agreements require certain of Mirant's subsidiaries,
under certain conditions, to run the acquired generation assets at the
request of the CAISO in order to support the reliability of the California
electric transmission system. Under the RMR agreements, Mirant recovers
either a portion

13

(Condition 1) or all (Condition 2) of the annual fixed revenue requirement
(the "Annual Requirement") of the generation assets through fixed charges
to the CAISO. If Mirant's California generation assets subject to RMR
agreements are under Condition 1, then Mirant depends on revenues from
sales of the output of the units at market prices to recover the remainder.
The Annual Requirement is subject to the FERC's review and approval. See
Note 15 to our consolidated financial statements for discussion concerning
the Company's RMR litigation regarding the Annual Requirement.

Under the FERC approved CAISO comprehensive market design, also known
as MD02, the CAISO imposes a $250/MWh cap on prices for energy and
ancillary services, implements an AMP similar to that in place in the
NYISO, and requires owners of non-hydroelectric generation in California,
such as Mirant, to offer power in the CAISO's spot markets to the extent
the output is not scheduled for delivery in the hour. For the remainder of
Mirant's units located outside of California, but within the Western
Interconnection, there is no single entity responsible for a centralized
bid-based clearing market. The primary markets in the West today are
bilateral and adhere to the reliability standards of the Western
Electricity Coordinating Council ("WECC"). The WECC is the regional
reliability organization responsible for development and enforcement of
rules to ensure the security of the bulk power electric systems in the
western United States. The purpose of these rules is to ensure system
stability and reliability. The WECC region is divided into four
sub-regions: California, NWPA (Northwest Power Area), DSW (Desert
Southwest), and RMPA (Rocky Mountain Power Area). Although the Company is
an active participant in all the developing western markets, we cannot
predict when the final revisions and modifications will be complete, or
when market designs will gain the necessary regional and national
approvals. We therefore cannot predict if the outcomes will have a positive
or negative impact on future earnings from our Western assets.

FEDERAL AND STATE LEGISLATION

Congress is currently considering legislation to modify federal laws
affecting the electric industry. Certain provisions in the bills under
consideration could effect FERC jurisdiction over interstate transmission.
Additional provisions in the bills under consideration propose to repeal or
modify both PURPA and the PUHCA. As with other bills before the Congress we
cannot predict the outcome or the impact on our business.

In addition, various states have either enacted or are considering
legislation designed to deregulate the production and sale of electricity in
order to provide for the further development of a competitive wholesale and/or
retail marketplace. Although the legislation and regulatory initiatives vary,
common themes include the availability of market pricing, retail customer
choice, recovery of stranded costs and separation of generation assets from
transmission, distribution and other assets. The impetus for enacting state
driven legislation to deregulate the sale of electricity within individual
states has slowed significantly over the last few years. Proposed reforms to
state-mandated deregulatory measures have also included the repeal of measures
implementing retail competition, although the state of California is the only
jurisdiction in which such a proposal is active. Reforms of this type would have
a negative impact on the competitive wholesale electricity market and could
adversely impact our earnings.

ENVIRONMENTAL REGULATION

Our projects, facilities, and operations are subject to extensive federal,
state, local and foreign laws and regulations relating to environmental
protection and human health, including air quality, water quality, waste
management, and natural resources protection. Our compliance with these
environmental laws and regulations necessitates significant capital and
operating expenditures, including costs associated with monitoring, pollution
control equipment and mitigation of other environmental impacts, emission fees,
reporting, and permitting at our various operating facilities. Our expenditures,
while not prohibitive in the past, are anticipated to increase in the future
along with the increase in stricter standards, greater regulation, and more
extensive permitting requirements. We cannot provide assurance that future

14

compliance with these environmental requirements will not have a material
adverse effect on our operations or financial condition.

The environmental laws and regulations in the United States illustrate the
comprehensive environmental requirements that govern our operations. Our most
significant environmental requirements in the United States arise under the
federal 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, and San Francisco, which are classified by the United States
Environmental Protection Agency ("EPA") as not achieving federal ambient air
quality standards. This regulatory classification of these areas subjects our
operations to more stringent air regulation requirements.

In the future, we anticipate increased regulation of our 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 recently promulgated new regulations (known as the
"Section 126 Rule" and "NOx SIP Call") which establish emission caps for
nitrogen oxide ("NOx") emissions from electric generating units in most of the
eastern states that will be implemented beginning May 2004. Under either rule, 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 are already subject to a similar state and regional NOx emission
cap program, which will become a part of the EPA NOx cap 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 is
expected to 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 is also developing regulations to govern mercury emissions from
power plants, which are scheduled to be finalized in 2004 and go into effect in
2007. These mercury regulations are likely to require significant emission
reductions from coal-fired power plants in particular. Also, during the course
of this decade, the EPA will be implementing new, more stringent ozone and
particulate matter ambient air quality standards and will address regional haze
visibility issues, which will result in new regulations that will likely require
more emission reductions from power plants, along with other emission sources
such as vehicles. These future regulations will increase compliance costs for
our operations and will likely require emission reductions from some of our
power plants, which could necessitate significant expenditures on emission
controls or have other impacts on operations. However, these rulemakings are at
a preliminary stage, and we cannot opine at this time on specific impacts or
whether the regulations will have a material adverse effect on our financial
condition, cash flows and results of operations.

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 nitrogen oxide and sulfur dioxide emissions from certain power
plants and to regulate carbon dioxide emissions for the first time. These
regulations, which become effective in the 2004-2008 timeframe, will apply to
our oil-fired Canal plant in the state and will increase our operating costs and
could necessitate the installation of additional emission control technology.

Also, the San Francisco Bay Area where we own power plants has increasingly
more stringent NOx emission standards which will become applicable to our plants
in the coming years, culminating in 2005.

15

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 some of our higher NOx emitting units.

Additionally, on March 26, 2003, the State of New York has approved air
regulations that significantly reduce NOx and sulfur dioxide ("SO(2)") emissions
from power plants through a year round 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 SO(2) 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 our operations.

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

In 1999, the United States Department of Justice ("DOJ") commenced
litigation against seven electric utilities for alleged violations of the new
source review regulations promulgated under the Clean Air Act ("NSR"), and the
EPA also issued an administrative order to the Tennessee Valley Authority
alleging similar violations at seven of its coal-fired power plants. Since then,
the EPA has added additional power generators to the litigation, and the EPA has
also issued administrative notices of violation alleging similar violations at
other coal-fired power plants. These enforcement actions concern maintenance,
repair and replacement 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. The
power generation industry disagrees with the EPA's positions in the lawsuits.
Trials in certain of the cases are scheduled to occur in 2003. To date, no
lawsuits or administrative actions alleging similar violations have been brought
by the EPA against us, our subsidiaries or any of our power plants, but the EPA
has requested information concerning some of our Mid-Atlantic business unit
plants covering a time period that predates our ownership. Also, the State of
New York has issued a notice of violation to the previous owner of our Lovett
plant alleging similar violations from operations that predate our ownership.
For more information about these matters, see "Legal Proceedings." We cannot
provide assurance that lawsuits or other administrative actions against our
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,
this could require substantial expenditures to bring our power plants into
compliance and could have a material adverse effect on our financial condition,
results of operations or cash flows.

There are several other environmental laws in the United States, in
addition to air quality laws, which also affect our operations. For example, 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, the EPA has issued a new rule that imposes more stringent standards
on the cooling water intakes for new plants and has proposed a similar
regulation for intakes on existing plants. We expect to incur additional
compliance costs if this proposed water regulation is adopted; however, based on
the currently proposed regulation, we do not expect these costs to be material.

Our facilities are also 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 our current waste

16

management practices at some facilities and incur additional costs for increased
waste management requirements.

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. We do not expect any corrective actions to require significant
expenditures.

Some of our international operations are subject to comprehensive
environmental regulation similar to that in the United States, and these
regulations are expected to become more stringent in the future. For example, as
discussed in the regulatory discussion for our business in the Philippines, the
government in the Philippines enacted comprehensive clean air act legislation
which governs power plants and other sources. Additionally, other countries in
which we have operations, such as Trinidad, have proposed 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 of whether to regulate 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 other
developed countries ratified the Kyoto Protocol, an international treaty
regulating GHGs, which makes the implementation of the treaty in certain
countries more likely. The current United States Administration is opposed to
the treaty, and the United States has not ratified and is not expected to ratify
the treaty. Therefore, the United States would not be bound by the treaty if it
goes into effect in the future in countries that have ratified it. None of the
countries in which we presently own or operate power plants would have any
binding obligations under the treaty, if it does go into effect in the future in
the countries that have ratified it, and none presently have enacted any law or
regulation governing GHGs emissions from power plants. However, we cannot
provide assurances that no such law or regulation would be enacted in the future
in a 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.

We believe we are in compliance in all material respects with applicable
environmental laws. While we believe our operations and facilities comply with
applicable environmental laws and regulations, we cannot provide assurances that
additional costs will not be incurred as a result of new interpretations or
applications of existing laws and regulations.

EMPLOYEES

At December 31, 2002, our corporate offices and majority owned or
controlled subsidiaries employed approximately 7,000 persons. This number
includes approximately 1,100 employees in the corporate and North American
headquarters in Atlanta and approximately 5,900 employees at operating
facilities. Approximately 1,000 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. Approximately 2,100 of our employees in international business units
belong to unions. These unions include:

- the Managers' Association, the Union of Technical Administrative and
Supervisory Personnel, the National Workers' Union and the Bustamante
Industrial Trade Union in Jamaica; and

- Bahamas Industrial Engineers, Managerial and Supervisory Union and the
Commonwealth Electrical Workers Union in the Bahamas.

We are currently negotiating new labor agreements at JPSCo, Trinidad, New
York and Mid-Atlantic. At each location, we hope to reach a new labor contract
with each of its existing unions. However, there is a substantial risk that new
labor agreements will not be reached without a strike or other form of adverse
collective action by one or more of our unions. If a strike were to occur, there
is a risk that such action would significantly disrupt our ability to produce
and/or distribute energy.

17

To mitigate and reduce the risk of disruption as described above, we have
engaged 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 controlled through operating
agreements as of December 31, 2002.

- ---------------

(1) Amounts reflect Mirant's percent economic interest in the total MW.

(2) MW amounts reflect net dependable capacity.

(3) Substantially all of these development projects have been suspended.

(4) Total MW reflects a 1.4% ownership interest, or 9 MW, in the 614 MW Wyman
plant.

(5) The Neenah facility was sold in January 2003.

(6) Amount includes 732 MW of controlled capacity under the Potomac Electric
Power Company ("PEPCO") power purchase agreements.

(7) This project has been suspended indefinitely.

(8) Mirant has tolling agreements for net dependable capacity. See Note 16 to
our consolidated financial statements for additional information related to
the agreements with Brazos and Perryville.

(9) Mirant acquired an additional 4.26% ownership interest in the Pagbilao
project in the first quarter of 2003, bringing our ownership interest to
91.5%.

(10) In March 2003, the energy conversion agreement related to Navotas 1 expired
and the plant and equipment were transferred back to NPC.

(11) The Guam facility was sold in April 2003.

(12) In a letter dated April 24, 2003, Mirant informed the CAISO of its intent
to permanently retire from service the generating units commonly known as
Pittsburg Units 1, 2, 3 and 4 (595 MW) as of October 1, 2003. None of these
units are subject to RMR Agreements.

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

ITEM 3. LEGAL PROCEEDINGS

With respect to each of the following matters, the Company cannot currently
determine the outcome of the proceedings or the amounts of any potential losses
from such proceedings.

19

Provision for California Contingencies: Mirant is subject to a variety of
lawsuits and regulatory proceedings related to its activities in California and
the western power markets and the high prices for wholesale electricity and
natural gas experienced in the western markets during 2000 and 2001. As
described below in Potential FERC Show Cause Proceedings Arising Out of Its
Investigation of Western Power Markets, Western Power Markets Price Mitigation
and Refund Proceedings, California Attorney General Litigation, California Rate
Payer Litigation, Oregon Rate Payer Litigation, and Washington Rate Payer
Litigation and as set forth in Note 15 to our consolidated financial statements,
various regulatory proceedings and lawsuits have been filed or initiated by the
FERC, the California attorney general and various states' rate payers with the
FERC and in state and federal courts. In addition, civil and criminal
investigations have been initiated by the Department of Justice, the General
Accounting Office, the FERC and various states' attorneys general, as described
below in Western Power Markets Investigations, relating to Mirant's operations
in California and the western power markets. The Company has made a provision of
approximately $295 million for losses related to the Company's operations in
California and the western power markets during 2000 and 2001.

Western Power Markets Investigations: Several governmental entities have
launched investigations into the western power markets, including activities by
Mirant and several of its wholly owned subsidiaries. Those governmental entities
include the FERC, the United States Department of Justice, the California Public
Utilities Commission ("CPUC"), the California Senate, the California State
Auditor, California's Electricity Oversight Board ("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,
have resulted in the issuance of civil investigative demands, subpoenas,
document requests, requests for admission, and interrogatories directed to
several of Mirant's entities. In addition, the CPUC has had personnel onsite on
a periodic basis at Mirant's California generating facilities since December
2000. Each of these civil investigative demands, subpoenas, document requests,
requests for admission, and interrogatories, as well as the plant visits, could
impose significant compliance costs on Mirant or its subsidiaries.

Additionally, 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 forward. Information from this investigation could be
used in any existing or future complaints before the FERC relevant to the
matters being investigated, including the proceedings described below in
Potential FERC Show Cause Proceedings Arising Out of Its Investigation of
Western Power Markets and Western Power Markets Price Mitigation and Refund
Proceedings. On August 13, 2002, the FERC Staff issued an initial report
describing its investigation of the effect on spot electric prices in the West
of trading strategies employed by Enron Corporation and its affiliates ("Enron")
and other entities but stating it could not quantify the exact economic impact.
The report recommended that the natural gas indices used for purposes of
calculating potential refunds in the California refund cases described below in
Western Power Markets Price Mitigation and Refund Proceedings be replaced with
indices at a different location plus a transportation component.

In September 2002, the CPUC issued a report that purported to show 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 report identified two specific days on which Mirant
allegedly had capacity available that was not used or that was on outage and
that if operated could have avoided the system emergency. Mirant has responded
to the report pointing out a number of material inaccuracies and errors that it
believes cause the CPUC's conclusions to be wrong with respect to Mirant. In
January 2003, the CPUC staff issued a supplemental report in which it again
concluded that Mirant and the other four generators did not provide energy when
it was available during the period reviewed.

20

In November 2002, Mirant received a subpoena from the Department of
Justice, 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 requests
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 intends to cooperate fully with the United States
Attorney's office in this investigation.

On March 26, 2003, the FERC Staff issued its final report regarding its
investigation into whether and, if so, the extent to which California and
Western energy markets were manipulated during 2000 and 2001. Although the staff
reaffirmed the FERC's conclusion set forth in its December 15, 2000 order 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, it also found that significant market manipulation had
occurred in both the gas and electricity markets. In addition to its finding
that significant manipulation had occurred in the wholesale gas markets, the
staff found that the gas price indices published by various trade publications
were unreliable due to widespread falsification of the transactional information
reported to such trade press. Based on those findings, the staff recommended
again that the FERC not use gas prices from published price indices in
calculating the market mitigated prices to be used in calculating refund amounts
in the California refund proceedings. Mirant cannot at this time predict what
effect, if any, such misreporting of information to the trade press will have
upon transactions to which a Mirant entity is a party that utilize such
published spot price data as part of the price terms.

The staff further concluded that trading strategies of the type portrayed
in the Enron memos released by the FERC in May 2002 violated provisions of the
CAISO and the California Power Exchange Corporation ("PX") tariffs that
prohibited gaming. It identified Mirant 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 PX and CAISO at prices unrelated to
costs constituted economic withholding and violated the antigaming provisions of
the CAISO and PX tariffs. Mirant was one of the entities identified as engaging
in that bidding practice.

In its final report, the staff also concluded that the artificially high
short-term prices that had resulted from the various instances of market
manipulation identified in its report had affected forward power prices
reflected in longer term contracts negotiated during the period from January 1,
2001 through June 21, 2001, particularly such contracts having a term of one to
two years. Finally, the staff recommended that the FERC remand the proceeding
addressing whether unjust and unreasonable charges had occurred in spot market
bilateral sales in the Pacific Northwest from December 25, 2000 through June 20,
2001 to the administrative law judge ("ALJ") for further proceedings in light of
the findings of market manipulation made by the staff in its final report.

On March 26, 2003, the FERC Staff also issued a separate report addressing
the allegations of physical withholding by Mirant and four other out of state
owners of generation assets in California made by the CPUC in its report issued
in September 2002. The 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 FERC Staff found that the CPUC's calculation of available power
was incomplete and greatly overstated the amount of available power that was not
generated. The staff also indicated, however, that the FERC was continuing to
investigate whether withholding by generators had occurred during 2000 and 2001.

Potential FERC Show Cause Proceedings Arising Out of Its Investigation of
Western Power Markets: On March 26, 2003, the FERC stated at its meeting that it
would consider issuing show cause orders to those entities that the FERC Staff
report issued on March 26, 2003 (described above in Western Power Markets
Investigations) indicated may have engaged in one or more of the trading
strategies of the type portrayed in the Enron memos released by the FERC in May
2002, which would include Mirant. The show cause order, if issued, could require
Mirant to demonstrate why it should not have to disgorge any

21

profits obtained from such practices in the California market from January 1,
2000 through June 20, 2001. The FERC further stated that it would consider
issuing additional show cause orders to those entities, including Mirant, that
the staff report identified as having bid generation resources to the PX and
CAISO at prices unrelated to costs. That show cause order, if issued, could
require Mirant to demonstrate why its bidding behavior in the PX and CAISO
markets from May 1, 2000 through October 1, 2000 did not constitute a violation
of the CAISO and PX tariffs and why it should not be required to disgorge any
profits resulting from such bidding practices.

Western Power Markets Price Mitigation and Refund Proceedings: On July 25,
2001, the FERC issued an order setting out a methodology to be used to determine
the mitigated market clearing prices for sales made to the CAISO or the PX from
October 2, 2000 through June 20, 2001. The order required hearings before an ALJ
to determine the amount of any refunds resulting from the use of such mitigated
market prices as well as amounts owed to sellers by the CAISO and the PX that
had not been paid. Parties have appealed the FERC's July 25, 2001 order to the
United States Court of Appeals for the Ninth Circuit, seeking review of various
issues, including changing the potential refund date to include periods prior to
October 2, 2000 and expanding the sales of electricity subject to potential
refund to include sales made to the California Department of Water Resources
("DWR"). Any such expansion of the refund period or the types of sales of
electricity potentially subject to refund could significantly increase Mirant's
refund exposure in this proceeding.

On December 12, 2002, the ALJ issued an initial decision providing for a
method to implement the FERC's mitigated market clearing price methodology set
forth in its July 25, 2001 order and a preliminary determination of what refunds
would be owed under that methodology. In addition, the ALJ determined the
preliminary amounts currently owed to each supplier in the proceeding. The ALJ
determined that the initial amounts owed to Mirant from the CAISO and the PX
totaled approximately $292 million and that Mirant owed the CAISO and the PX
refunds totaling approximately $170 million. The ALJ recommended that any
refunds owed by a supplier to the CAISO and the PX should be offset against any
outstanding amounts owed to that supplier by the CAISO and the PX. Under this
approach, Mirant would be owed net amounts totaling approximately $122 million
from the CAISO and the PX. The ALJ stressed that the monetary amounts were not
final since they 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. An errata issued by the ALJ to his initial decision indicated that the
amounts identified by the initial decision as being owed to Mirant and other
sellers by the PX 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 by the PX, and the net amount owed
Mirant by the CAISO and the PX after taking into account the proposed refunds,
would increase by approximately $37 million.

On March 3, 2003, the California Attorney General, the California
Electricity Oversight Board, the CPUC, Pacific Gas and Electric, and Southern
California Edison Company (the "California Parties") filed submittals with the
FERC in the California refund proceeding alleging that owners of generating
facilities in California and energy marketers, including Mirant entities, had
engaged in extensive manipulation of the California wholesale electricity market
during 2000 and 2001. With respect to the Mirant entities, the California
Parties asserted that Mirant entities had engaged in a variety of practices
alleged to be improper, including withholding power either by not operating
generating facilities when they could be operated or by offering the power from
such facilities at prices in excess of the Mirant entities' marginal cost and
engaging in various Enron-type trading strategies. The California Parties argued
that the alleged market manipulation by the generators and marketers warranted
the FERC applying its mitigated market prices to require refunds beyond just
transactions done through the CAISO and PX in the period from October 2, 2000
through June 20, 2001. They asserted that the FERC should expand the
transactions subject to the refund proceeding to include short-term and
long-term bilateral transactions entered into by the DWR that were not conducted
through the CAISO and PX and should begin the refund period as of January 1,
2000 rather than October 2, 2000. Expansion of the scope of the transactions
subject to refund in the manner sought by the California Parties could
materially affect the amount of any refunds that

22

Mirant might be determined to owe and any such additional refunds could
negatively impact the Company's consolidated financial position, results of
operations or cash flows. On March 20, 2003, Mirant filed reply comments denying
that it had engaged in any conduct that violated the Federal Power Act or any
tariff provision applicable to its transactions in California. Mirant stated
that the purported evidence presented by the California Parties did not support
the allegations that Mirant had engaged in market manipulation, had violated the
Federal Power Act or had not complied with any applicable tariff or order of the
FERC.

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 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 and therefore to reduce the net
amount that would remain owed to Mirant from the CAISO and 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 by the CAISO and PX to approximately $49 million. The
FERC will 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 intends to demonstrate to the
FERC 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 significantly decrease the $110 million and increase the
resulting net amount owed to Mirant, although the amount of such potential
decrease and the resulting net amount owed to Mirant cannot at this time be
determined. In its March 26, 2003 order, the FERC also ruled that any future
findings of market manipulation resulting from its ongoing review of conduct in
the California market in 2000 and 2001 discussed above in Western Power Markets
Investigations and Potential FERC Show Cause Proceedings Arising Out of Its
Investigation of Western Power Markets would not result in a resetting of the
refund effective date or the mitigated market prices developed for the refund
period. Instead, the remedy for any such market manipulation that is found to
have occurred will be disgorgement of profits and other appropriate remedies and
such remedies could apply to conduct both prior to and during the refund period.
Various parties, including the California Parties, have filed motions with the
FERC seeking rehearing of the FERC's March 26, 2003 order. The amount owed to
Mirant from either the CAISO or the PX, the amount of any refund that Mirant
might be determined to owe to the CAISO or the PX, and whether Mirant 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 the July 25, 2001 order, the FERC also ordered that a preliminary
evidentiary proceeding be held to develop a factual record on whether there have
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 parties (consisting of the California Attorney
General, the CPUC and the EOB) filed to recover certain refunds from parties,
including one of Mirant's subsidiaries, 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 and its subsidiaries
totaled approximately $90 million. A FERC ALJ concluded a preliminary
evidentiary hearing related to possible refunds for power sales in the Pacific
Northwest. In a preliminary ruling issued September 24, 2001, the ALJ indicated
that she would order no refunds because the complainants had failed to prove any
exercise of market power or that any prices were unjust or unreasonable. The
FERC may accept, reject, or modify this preliminary ruling and the FERC's
decision may itself be appealed. On May 13, 2002 and May 24, 2002, the City of
Tacoma, Washington and the City of Seattle, Washington, respectively, filed to
reopen the evidentiary record in this proceeding as a result of the contents of
three internal Enron Power Marketing, Inc. memoranda that had been obtained and
publicly released by the FERC as part of its continuing investigation. On
December 19, 2002, the FERC granted in part the motion to reopen the record,
allowing parties the opportunity to

23

conduct additional discovery through February 28, 2003 (which date was later
extended to March 3, 2003) on claims of purported market manipulation and to
submit directly to the FERC any additional evidence and proposed findings of
fact that they wish the FERC to consider in evaluating the ALJ's initial
decision. On March 3, 2003, the two cities and other parties did make a further
submittal to the FERC asserting that market manipulation by various parties in
the California energy markets and violations of FERC approved tariffs caused
prices for electricity sold at wholesale to be unreasonably high and warranted
refunds. As set out above in Western Power Markets Investigations, the FERC
Staff in its March 26, 2003 report recommended that the FERC remand this
proceeding to the ALJ for further proceedings in light of the findings of market
manipulation made by the staff in its final report. The Company cannot predict
the outcome of these proceedings. If the Company were required to refund such
amounts, its subsidiaries would be required to refund amounts previously
received pursuant to sales made on their behalf during the refund periods. In
addition, its subsidiaries would be owed amounts for purchases made on their
behalf from other sellers in the Pacific Northwest.

California Attorney General Litigation: On March 11, 2002, the California
Attorney General filed a civil suit against Mirant and several of its wholly
owned subsidiaries. The lawsuit alleges that between 1998 and 2001 the companies
effectively double-sold their capacity by selling both ancillary services and
energy from the same generating units, such that if called upon, the companies
would have been unable to perform their contingent obligations under the
ancillary services contracts. The California Attorney General claims that this
alleged behavior violated both the tariff of the CAISO and the California Unfair
Competition Act. The suit seeks both restitution and penalties in unspecified
amounts. Mirant 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 denied the California Attorney General's
motion seeking to have the case remanded to the state court, and the California
Attorney General has appealed that ruling to the United States Court of Appeals
for the Ninth Circuit. This suit has been consolidated for joint administration
with the California Attorney General suits filed on April 9, 2002, and April 15,
2002. The district court on March 25, 2003 granted Mirant's motion seeking
dismissal of this suit. The court ruled that the California Attorney General's
claims under California's Unfair Competition Act are barred by the doctrine of
preemption and the filed rate doctrine, finding that the remedies sought would
interfere with the FERC's exclusive authority to set wholesale electric rates
under the Federal Power Act. The California Attorney General has appealed that
dismissal to the United States Court of Appeals for the Ninth Circuit.

On March 20, 2002, the California Attorney General filed a complaint with
the FERC against certain power marketers and their affiliates, including Mirant
and several of its wholly owned subsidiaries, alleging that market-based sales
of energy made by such generators were in violation of the Federal Power Act in
part because such transactions were not appropriately filed with the FERC. The
complaint requests, among other things, refunds for any prior short-term sales
of energy that are found to not be just and reasonable along with interest on
any such refunded amounts. The FERC has dismissed the California Attorney
General's complaint and denied the California Attorney General's request for
rehearing. The California Attorney General has appealed that dismissal to the
United States Court of Appeals for the Ninth Circuit.

On April 9, 2002, the California Attorney General filed a second civil suit
against Mirant and several of its wholly owned subsidiaries. The lawsuit alleges
that the companies 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. Mirant 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 denied the California Attorney General's
motion seeking to have the case remanded to the state court, and the California
Attorney General has appealed that ruling to the United States Court of Appeals
for the Ninth Circuit. This suit has been consolidated for joint administration
with the California Attorney General suits filed on March 11, 2002 and April 15,
2002. The district court on March 25, 2003 granted Mirant's motion seeking
dismissal of this suit. The court ruled that the California Attorney General's
claims under California's Unfair Competition Act are barred by the doctrine of
preemption and the filed rate doctrine, finding that the remedies sought would
interfere with the

24

FERC's exclusive authority to set wholesale electric rates under the Federal
Power Act. The California Attorney General has appealed that dismissal to the
United States Court of Appeals for the Ninth Circuit.

On April 15, 2002, the California Attorney General filed a third civil
lawsuit against Mirant and several of its wholly owned subsidiaries in the
United States District Court for the Northern District of California. The
lawsuit alleges that Mirant's acquisition and possession of its Potrero and
Delta power plants has substantially lessened, and will continue to
substantially lessen, competition in violation of 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. This suit has been
consolidated for joint administration with the California Attorney General suits
filed on March 11, 2002 and April 9, 2002. On March 25, 2003, the court
dismissed the California Attorney General's state law claims and his claim for
damages under the Clayton Act as barred by the filed rate doctrine but allowed
the California Attorney General to proceed on his claim under the Clayton Act
seeking relief in the form of an order requiring Mirant to divest its California
plants.

California Rate Payer Litigation: A total of sixteen 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 and several of its subsidiaries, engaged in various unlawful and anti-
competitive acts that served to manipulate wholesale power markets and inflate
wholesale electricity prices in California.

Six of those 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 and that if an injunction is not issued, the
state will be required to spend more than $150 million per day purchasing
electricity. The other suits likewise seek treble damages and equitable relief.
One such suit names Mirant Corporation itself as a defendant. A listing of these
six cases is as follows:

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 have appealed
that decision remanding the Six Coordinated Suits to the California

25

state courts to the United States Court of Appeals for the Ninth Circuit, and
the Ninth Circuit has stayed the district court's remand decision until the
Ninth Circuit can act on that appeal.

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 and several
of its subsidiaries, engaged in various unlawful and fraudulent business acts
that served to manipulate wholesale markets and inflate wholesale electricity
prices in California. The suits are related to events in the California
wholesale electricity market occurring over the last three years. 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. These suits
contain allegations of misconduct by the defendants, including the Mirant
entities, that are similar to the allegations made in the previously filed rate
payer suits, and in the suits filed by the California Attorney General on March
11, 2002, and April 15, 2002. 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, 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:

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. Motions to remand have been filed by the plaintiffs in these
cases, and whether the cases will remain in the United States District Court for
the Southern District of California or be remanded to the California state
courts in light of the district court's decision on December 13, 2002 to remand
the Six Coordinated Suits cannot be determined at this time.

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
and its subsidiaries, by Public Utility District No. 1 of Snohomish County,
which is a municipal corporation in the

26

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.
The district court concluded that the effect of the plaintiffs' claims was to
challenge rates for the sale of power at wholesale that were subject to the
exclusive regulation of the FERC under the Federal Power Act, and that those
claims were therefore barred by the filed rate doctrine and federal preemption.
The plaintiff has appealed the dismissal of the Snohomish suit to the United
States Court of Appeals for the Ninth Circuit.

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 the Company and various of its
subsidiaries. The plaintiff in the Bustamante suit alleges 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 seeks, among other things, disgorgement of profits,
restitution, and compensatory and punitive damages.

Oregon Rate Payer Litigation: On December 16, 2002, a class action suit,
Lodewick v. Dynegy, et al., was filed in the Circuit Court for the County of
Multnomah, Oregon, against various owners of electric generation facilities in
California and marketers of electricity and natural gas, including Mirant and
various of its subsidiaries, on behalf of all persons who purchased electricity
or natural gas in Oregon from January 2000. The plaintiff alleges that
defendants engaged in unlawful, unfair, and deceptive practices, including
withholding energy from the market, misrepresenting the amount of energy they
supplied, exercising improper control over the energy market and manipulating
the price of energy. The defendants' unlawful manipulation of the wholesale
energy market, the plaintiff alleges, resulted in supply shortages and
skyrocketing energy prices in the western United States, including Oregon, which
in turn caused drastic rate increases for Oregon consumers. The plaintiff
asserts claims under Oregon's Unfair Trade Practices Act, as well as claims for
negligence and fraud by concealment. The plaintiff seeks injunctive relief,
attorney's fees, and an accounting of the wholesale energy transactions entered
into by the defendants from 1998 and indicates that she will amend her complaint
to seek restitution and damages. The defendants have removed the Lodewick suit
to the United States District Court for the District of Oregon.

Washington Rate Payer Litigation: On December 16, 2002, a class action
suit, Symonds v. Dynegy, et al., was filed in the United States District Court
for the Western District of Washington against various owners of electric
generation facilities in California and marketers of electricity and natural
gas, including Mirant and various of its subsidiaries, on behalf of all persons
who purchased electricity or natural gas in the state of Washington from January
2000. The plaintiff alleges that defendants engaged in unlawful, unfair, and
deceptive practices, including withholding energy from the market,
misrepresenting the amount of energy they supplied, exercising improper control
over the energy market and manipulating the price of energy. The defendants'
unlawful manipulation of the wholesale energy market, the plaintiff alleges,
resulted in supply shortages and skyrocketing energy prices in the western
United States, including the state of Washington, which in turn caused drastic
rate increases for Washington consumers. The plaintiff asserts claims under
Washington's Consumer Protection Act, as well as claims for negligence and fraud
by concealment. The plaintiff seeks treble damages, injunctive relief,
attorney's fees, and an accounting of the wholesale energy transactions entered
into by the defendants since 1998.

27

Shareholder Litigation: Twenty lawsuits have been filed since May 29, 2002
against Mirant and four of its officers alleging, among other things, that
defendants violated Sections 10(b) and 20(a) of the Securities Exchange Act of
1934 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:

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

28

November of 2002. All defendants have filed motions seeking dismissal of the
amended complaint for failure to state a claim upon which relief can be granted.

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.

Shareholder Derivative Litigation: Four purported shareholders' derivative
suits have been filed against Mirant, its directors and certain officers of the
Company. 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 Company
practices complained of in the purported derivative lawsuits largely mirror
those complained of in the shareholder litigation, the rate payer litigation and
the California attorney general lawsuits that have been previously disclosed by
the Company. 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. The
captions of each of the cases follow:

The Kester and White suits were filed in the Superior Court of Fulton
County, Georgia. The Pettingill suit was filed in the Court of the Chancery for
New Castle County, Delaware and the Cichocki suit in the United States District
Court for the Northern District of Georgia. All four of the suits have been
stayed until a decision is rendered on the motions to dismiss or until discovery
begins in the consolidated suits pending in the United States District Court for
the Northern District of Georgia described in Shareholder Litigation above.

ERISA Litigation: On April 17, 2003, a purported class action lawsuit
alleging violations of the Employee Retirement Income Security Act ("ERISA") was
filed in the United States District Court for the Northern District of Georgia
entitled James Brown v. Mirant Corporation, et al., Civil Action No.
1:03-CV-1027 (the "ERISA Litigation"). The ERISA Litigation names as defendants
Mirant Corporation, certain of its current and former officers and directors,
and Southern Company. The plaintiff, who seeks to represent a putative class of
participants and beneficiaries of Mirant's 401(k) plans (the "Plans"), alleges
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 plaintiff seeks
unspecified damages, injunctive relief, attorneys' fees and costs. The factual
allegations underlying this lawsuit are substantially similar to those described
above in California Attorney General Litigation, California Rate Payer
Litigation, and Shareholder Litigation.

Environmental Information Requests: Along with several other electric
generators which own facilities in New York, in October 1999, Mirant New York
received an information request from the State of New York 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 various
repairs and maintenance activities at its Lovett facility. Mirant New York
responded fully to this request and provided all of the information requested by
the State. The State of New York issued notices of violation to some of the
utilities being investigated. The State issued a notice of violation to the
previous owner of the Lovett facility, Orange and Rockland Utilities, alleging
violations associated with the operation of the

29

Lovett facility prior to the acquisition of the plant by Mirant New York. To
date, Mirant New York has not received a notice of violation. Mirant New York
disagrees with the allegations of violations in the notice of violation issued
to the previous owner. The notice of violation does not specify corrective
actions, which the State of New York may require. If a violation is determined
to have occurred at the Lovett facility, Mirant New York may be responsible for
the cost of purchasing and installing emission control equipment, the cost of
which may be material. Under the sales agreement with Orange and Rockland
Utilities for the Lovett facility, Orange and Rockland Utilities is responsible
for fines and penalties arising from any violation associated with historical
operations prior to the sale. If a violation is determined to have occurred
after Mirant New York acquired the plants or, if occurring prior to the
acquisition, is determined to constitute a continuing violation, Mirant New York
would be subject to fines and penalties by the state or federal government for
the period subsequent to its acquisition of the plants, the cost of which may be
material. Mirant New York is engaged in discussions with the State to explore a
resolution of this matter.

In January 2001, the EPA issued a request for information to Mirant
concerning the air permitting and air emission control implications under the
NSR of past repair and maintenance activities at the Company's Potomac River
plant in Virginia and Chalk Point, Dickerson and Morgantown plants in Maryland.
The requested information concerns the period of operations that predates the
Company's ownership of the plants. Mirant has responded fully to this request.
If a violation is determined to have occurred at any of the plants, the Company
may be responsible for the cost of purchasing and installing emission control
equipment, the cost of which may be material. 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 the Company's
acquisition of the plants. If a 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, Mirant would be subject to
fines and penalties by the state or federal government for the period subsequent
to its acquisition of the plants, the cost of which may be material.

The Company cannot provide assurance that lawsuits or other administrative
actions against its power plants will not be filed or taken in the future. If an
action is filed against the Company or its power plants and it is determined to
not be in compliance, such a determination could require substantial
expenditures to bring the Company's power plants into compliance, which could
have a material adverse effect on its financial condition, results of operations
or cash flows.

Securities and Exchange Commission ("SEC") Informal Investigation and
United States Department of Justice and CFTC Inquiries: In August 2002, Mirant
received a notice from the Division of Enforcement of the Securities and
Exchange Commission 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 the issues announced 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. Mirant intends to
cooperate fully with the SEC.

In addition, the Company has been contacted by the United States Department
of Justice regarding the Company's disclosure of accounting issues and energy
trading matters and allegations contained in the amended complaint discussed
above in Shareholder Litigation 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
informal inquiry, and it intends to cooperate fully.

In August 2002, the Commodities Futures Trading Commission ("CFTC") asked
the Company for information about certain buy and sell transactions occurring
during 2001. The Company provided information regarding such trades to the CFTC,
none of which it considers to be wash trades. The CFTC subsequently requested
additional information, including information about all trades conducted on the
same day with the same counterparty that were potentially offsetting during the
period from January 1, 1999 through June 17, 2002, which information the Company
provided. In March 2003, the Company received a subpoena from the CFTC
requesting a variety of documents and information related to the

30

Company'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. Among the documents requested are any
documents previously produced to the FERC, the SEC, the Department of Justice,
any state's Attorney General, and any federal or state grand jury. The Company
intends to cooperate fully with the CFTC.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 4A. EXECUTIVE OFFICERS OF MIRANT CORPORATION

(Identification of executive officers of Mirant Corporation is inserted in
Part I in accordance with Regulation S-K, Item 401(b), Instruction 3.) The ages
of the officers set forth below are as of January 1, 2003.

The executive officers of Mirant Corporation were elected to serve until
their successors are elected and have qualified or until their removal,
resignation, death or disqualification.

33

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

COMMON STOCK

Mirant's stock is listed on the New York Stock Exchange, which is the
principal market in which the securities are traded. The following table
indicates high and low sales prices for common stock of Mirant as reported on
the New York Stock Exchange. As of April 23, 2003, Mirant had 154,541 holders of
record. On April 2, 2001, Southern distributed its remaining 80% interest in
Mirant to Southern's stockholders.

REDEMPTION OF SERIES B PREFERRED STOCK

On March 5, 2001 Southern redeemed its outstanding share of our Series B
preferred stock in exchange for transferring our subsidiaries, SE Finance
Capital Corporation and Southern Company Capital Funding Inc., to Southern.

DIVIDENDS

We currently intend to 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 our
credit facilities, our ability to pay dividends is subject to restrictions.

In 2000, we paid a cash dividend to Southern in the amount of $503 million,
funded by short-term borrowings and commercial paper borrowings. These dividends
were authorized under an order issued by the SEC, which allowed us to pay
dividends out of unearned surplus.

Holders of the preferred securities are entitled to receive cash
distributions at an annual rate of 6 1/4% of the $50 liquidation preference per
preferred security. Distributions are cumulative and began to accumulate on the
date of original issuance of the preferred securities, which was October 2,
2000. Distributions are payable quarterly in arrears on January 1, April 1, July
1 and October 1 of each year beginning January 1, 2001, unless we defer interest
payments on the debentures. In 2001 and 2002, we paid cash distributions of
approximately $22 million in each year. The distributions for these securities
are recorded in minority interest on the consolidated statement of operations.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected consolidated financial
information. The information set forth below should be read together with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our historical consolidated financial statements and the notes
thereto. The selected statement of operations data and balance sheet data are
derived from our consolidated financial statements. The financial information
for the periods prior to our separation from Southern on April 2,

34

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 from January 1, 1998 until August 10, 2000, the date of our
acquisition of Vastar Resources Inc.'s ("Vastar") 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.

As further described in Item 7 "Management's Discussion Analysis of Financial
Condition and Results of Operations", the Company restated its consolidated
financial statements as of December 31, 2001 and 2000, and for the years then
ended.

SELECTED FINANCIAL DATA

- ---------------

(1) The $950 million of preferred securities were issued by special purpose
financing subsidiaries owned by Capital Funding, our capital funding
subsidiary. The proceeds were loaned to Southern in exchange for
subordinated notes from Southern. Southern paid interest on the subordinated
notes issued in favor of the financing subsidiaries, which payments were
used to pay dividends on the preferred securities. Southern guaranteed
payments due under the terms of the preferred securities. In connection with
our separation from Southern, Capital Funding was transferred to Southern on
March 5, 2001.

35

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion should be read in conjunction with the Company's
consolidated financial statements and the related notes, which are included
elsewhere in this report. The accompanying consolidated financial statements of
the Company have been prepared on a going concern basis, which contemplates the
realization of assets and the satisfaction of liabilities in the normal course
of business. As discussed below under "Financial Condition -- Liquidity and
Capital Resources", the Company is currently in discussions with certain of its
lenders regarding the extension of the maturities of a substantial portion of
its indebtedness. If such restructuring efforts are not successful, the Company
would likely be required to seek bankruptcy court or other protection from its
creditors. The Company's consolidated financial statements do not reflect
adjustments that might be required if the Company is unable to continue as a
going concern. See also Note 1 to the Company's consolidated financial
statements included elsewhere in this report.

OVERVIEW AND BACKGROUND

We are an international energy company that produces and sells electricity
in the United States, the Philippines and the Caribbean. In addition, in North
America we engage in trading activities to optimize the financial performance of
our power generation business and for proprietary purposes. Most of our
generating output in the Philippines is sold under long-term contracts. Our
operations in the Caribbean include fully integrated electric utilities in
Jamaica and the Bahamas and generation businesses in Curacao and in Trinidad and
Tobago.

As of December 31, 2002, we owned or controlled through operating
agreements more than 21,800 MW of electric generating capacity around the world
and expect to complete construction of approximately 990 MW of generating
capacity by December 2003. In North America, we also had rights to approximately
3.1 billion cubic feet per day of natural gas production, more than 2.1 billion
cubic feet per day of natural gas transportation and almost 13.4 billion cubic
feet of natural gas storage as of December 31, 2002.

Beginning in late 2001 and continuing through early 2003, there have been
many changes in our business. This is a result of a number of factors, including
uncertainty arising from the collapse of Enron Corporation and the financial
difficulties of our competitors, regulatory and legal investigations of
wholesale energy trading activities, and decreased power prices due to the
construction of additional electric generating facilities in the United States.
These conditions have adversely impacted our liquidity and earnings. Our
earnings decreased by $2.85 billion in 2002 compared to 2001.

Following is a summary of significant factors affecting the Company in
2002:

- The combination of external factors discussed above and changes in our
strategic focus have reduced our estimated future cash flows which
adversely impacted the value of our assets. In 2002, the Company
recognized goodwill impairment charges of $697 million; restructuring and
long-lived asset impairment charges of $973 million; deferred income tax
valuation adjustments of $1,088 million; provisions for income taxes that
were previously unrecognized on accumulated foreign earnings of $468
million; and other impairment charges of $467 million.

- To reduce outstanding debt and in response to changes in the Company's
strategic focus, the Company sold its European, Chinese and selected
United States investments and operations resulting in gains of $370
million in 2002.

- In 2002, we began scaling back the scope of our commodity trading
activities, primarily physical gas, to reduce the impact that commodity
trading has on our liquidity and credit positions. We expect to continue
to reduce our physical natural gas trading activities in 2003. The
Company expects these reductions in its trading activities to result in
lower net trading revenues in 2003 and beyond.

36

- Limited access to capital has caused us to draw down our credit
facilities and maintain substantially higher cash balances throughout the
year resulting in increased interest expense. In addition, we are seeking
to restructure our debt by asking certain of our creditors to defer
repayments of principal. If we are successful in restructuring our debt,
we expect that the terms of such restructured debt will be less favorable
than the terms of our current debt.

- Lower power prices and higher natural gas prices resulted in reduced
"spark spreads" (the difference between the price at which electricity is
sold and the cost of the fuel used to generate it) and resulting lower
gross margins in 2002 compared to unusually high spark spreads in 2001
and 2000.

- In 2002, our reduced credit ratings have caused the Company to provide
additional collateral to market participants to support the Company's
trading operations, which has adversely affected our liquidity.

- In 2002, trading volumes decreased in forward markets for both power and
gas. Trading volumes are expected to decline further as market
participants continue to exit the trading business. We expect these
trends to adversely affect our future net trading revenues.

- Results of operations for 2002 include revenue generated from fixed price
contracts with higher margins than are currently available based on
forward curves. Our inability to enter into contracts with similar
margins is expected to adversely impact our future operating results.

- In 2002, the prices realized under our power sales agreement with the
DWR, which expired in December 2002, were based on the market prices,
which were in place at the time we entered into the agreement. These
prices were approximately $150/MWh and under the new RMR condition 2
construct, we will receive lower revenue from our California properties
in 2003.

- Our earnings include the non-cash effect of amortizing liabilities we
recorded as part of our purchase of certain generating assets from PEPCO.
At the time of the acquisition, we recorded a liability for out-of-market
power sales agreements with PEPCO of approximately $1.735 billion, which
is being amortized to income over the life of the agreements. This
non-cash amortization added $423 million, $417 million and $12 million to
revenues and operating income in 2002, 2001 and 2000, respectively. As of
December 2002, the unamortized balance of this liability is $883 million,
which will be amortized to revenue through January 2005. The liability is
not adjusted for subsequent changes in market prices. As a result, we
expect the amount of amortization recognized as revenue will differ from
the amount required to satisfy the obligation based on market prices at
the time the obligations are satisfied.

RESTATEMENT OF FINANCIAL STATEMENTS

This report contains restated consolidated financial statements of the
Company for the years ended December 31, 2001 and 2000. Prior to filing its
second quarter 2002 Form 10-Q, the Company identified a number of accounting
errors in its previously issued financial statements due to a material weakness
in its accounting controls and organization. As a result, we completed a
comprehensive analysis of our financial statements and accounting records and
identified a number of additional errors. We also engaged our independent
auditors to reaudit our financial statements.

The nature of the errors and the restatement adjustments that the Company
has made to its financial statements for years ended December 31, 2001 and 2000
are set forth in Note 3 to our consolidated financial statements in Item 8 of
this report.

37

The net impact of the adjustments include the following:

- Additional paid-in capital at December 31, 1999 has been adjusted by $6
million primarily to reflect a non-cash transfer of employee obligations
by Mirant to Southern Company. Retained earnings at December 31, 1999 has
been restated to reflect the prior period adjustment in the accompanying
consolidated statements of shareholders' equity, and increased by $53
million, as a result of the restatement adjustments. This increase in the
retained earnings balance is primarily due to $49 million of tax benefits
relating to the devaluation of the Philippine Peso relative to the United
States dollar that occurred in the Philippines from 1997 through 1999 but
were not previously recognized in the consolidated financial statements.

- A $159 million reduction in net income in 2001; and

- A $29 million reduction in net income in 2000.

In addition, the Company has reclassified certain amounts in the 2001 and
2000 consolidated financial statements to reflect the adoption of new accounting
standards. The reclassifications include the net presentation of revenues and
expenses associated with energy trading activities required by Emerging Issues
Task Force ("EITF") Issue No. 02-03, "Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," and the presentation
of the operations of Mirant Americas Production Company, MAP Fuels Limited,
which owned AQC, in Queensland, Australia, and Mirant's State Line generating
facility in Indiana and Neenah generating facility in Wisconsin as discontinued
operations pursuant to Statement of Financial Accounting Standards ("SFAS") No.
144 "Accounting for the Impairment or Disposal of Long-Lived Assets."

INTERIM FINANCIAL INFORMATION

The Company is in the process of restating its interim financial
information for each of the quarterly periods in 2001 and 2002. Upon completion
of the quarterly financial information, the Company expects to prepare and file
amended Forms 10-Q for each of the quarterly periods in 2002.

EFFECTS OF ALLOCATIONS FROM SOUTHERN COMPANY IN 2000

Our 2000 consolidated financial statements include allocations to us of
certain assets and liabilities, including profit sharing, pension and
non-qualified deferred compensation obligations; and corporate expenses,
including engineering services, legal, accounting, human resources and insurance
services, information technology services and other overhead costs. These
amounts have been determined on bases that we and Southern considered to be
reasonable reflections of the utilization of the services provided to us or the
benefit received by us. The expense allocation methods include relative sales,
investment, headcount, square footage, transaction processing costs, adjusted
operating expenses and others. The financial information presented for 2000 may
not be indicative of our consolidated financial position, results of operations
or cash flows would have been had we been a separate, stand-alone entity for
2000.

RESULTS OF OPERATIONS

This discussion of our performance is organized by reportable operating
segment, which is consistent with the way we manage our business.

NORTH AMERICA

Our North America segment consists primarily of power generation and
commodity trading operations managed as a combined business, including
approximately 18,000 MW of generating capacity. The

38

following table summarizes the operations of our North American segment for the
years ended 2002, 2001 and 2000 (in millions):

2002 versus 2001

Operating Revenues. Our operating revenues decreased by $2.1 billion in
2002 compared to 2001. The following factors were primarily responsible for the
decrease in operating revenues:

- Our revenues from the generation of power decreased by $1.9 billion in
2002 compared to 2001. This decrease resulted primarily from lower
revenues in the California market of approximately $2.1 billion. The
average price dropped from approximately $173 per MWh to approximately
$66 per MWh or 62% and our sales volumes dropped from approximately 15.9
million MWhs to approximately 12.2 million MWhs or 23%. This decrease was
partially offset by approximately $250 million from sales of new
generation capacity added in the United States in 2001 and 2002. As of
December 31, 2002 we had a total generation capacity of approximately
18,000 MW in the United States, which included approximately 27% of base
load units, 43% of intermediate units and 30% of peaking units.

- Our net trading revenues decreased by $224 million in 2002 compared to
2001. This decrease was due to a particularly favorable pricing
environment in 2001, which allowed the Company to take advantage of
rising gas prices in the early part of 2001 followed by a sharp decline
in power prices in spring and early summer. We were not able to repeat
this performance in 2002, which had less price volatility due to more
normal weather and the effect of additional generation capacity which
served to temper price volatility.

Operating Expenses. Our operating expenses decreased by $908 million in
2002 compared to 2001. The following factors were responsible for the changes in
operating expenses:

- The cost of fuel, electricity and other products decreased by $1.4
billion in 2002 compared to 2001. This decrease resulted primarily from
lower demand for our facilities and lower prices for purchased power and
natural gas of approximately $1.3 billion in the California market. In
the California market, the average unit price for purchased power
decreased from approximately $199 per MWh in 2001 to approximately $42
per MWh in 2002 or 79% and the average unit price for natural gas

39

decreased from approximately $7.50 per MMBtu in 2001 to approximately $3.10 per
MMBtu in 2002 or 59%. In the California market our purchased power increased by
approximately 28% and our natural gas purchases decreased by approximately 91%
compared to 2001.

- Selling, general and administrative expense decreased by $275 million in
2002 compared to 2001 as a result of cost cutting efforts and
restructuring our business. Incentive compensation expense was
approximately $59 million lower in 2002 due to the lower financial
performance compared to 2001. We reduced expenses related to business
development, consulting and information systems by approximately $63
million to reflect lower expected growth related activities going forward
and reduced travel and other miscellaneous expenses by approximately $20
million. The decrease also resulted from provisions for potential losses
of approximately $112 million recorded in the first quarter of 2001
related to receivables due from both the PX and PG&E. These decreases
were offset in part by higher audit and legal fees.

- Depreciation and amortization expense decreased by $52 million in 2002
compared to 2001. The decrease was primarily as a result of no longer
amortizing goodwill upon our adoption of SFAS No. 142. In addition, we
recorded approximately $12 million less depreciation expense related to
certain assets that were fully depreciated by the end of 2001. These
decreases were partially offset by additional depreciation of
approximately $23 million from assets we acquired throughout 2001, and
from the commencement of operations at new units completed in 2001 and
2002.

- The impairment losses and restructuring charges of $779 million recorded
in 2002 included $248 million related to write-downs of work in progress
and progress payments on equipment, $236 million related to costs to
cancel equipment orders and service agreements, $25 million related to
the severance of approximately 323 employees and other employee
termination-related charges and $10 million related to costs incurred to
suspend construction projects in progress. We also recorded impairment
charges of $77 million related to our suspended Mint Farm construction
project and $44 million associated with one power island that we
originally intended to use as part of a development project in Korea. In
addition, we recorded a write down of $91 million reflecting the fair
market value of our remaining turbines held in storage.

2001 versus 2000

Operating Revenues. Our operating revenues increased by $4.6 billion in
2001 compared to 2000. The following are some of the factors that were
responsible for the increase in operating revenues:

- Our revenues from the generation of power increased by $4.4 billion in
2001 compared to 2000. This increase resulted primarily from unusually
high power prices in the first quarter of 2001 and increased market
demand in the California market. Revenue from the California market
contributed approximately $2.4 billion to the increase. Market prices in
this region increased by approximately 61%. Power sales volumes in this
region increased by approximately 181%. The revenue from the assets we
acquired from PEPCO contributed approximately $1.6 billion to the
increase in revenues. Other capacity additions in the United States also
contributed to the increase in revenues. In addition, the 2000 amounts
reflect provisions recorded for potential refunds related to revenues
from our California operations.

- Our net trading revenues increased by $198 million in 2001 compared to
2000. This increase resulted primarily from the inclusion of 12 months of
revenues in 2001, compared to 5 months in 2000, from Mirant Americas
Energy Marketing which was consolidated in our financial statements
beginning in August 2000. Prior to August of 2000 Mirant Americas Energy
Marketing was accounted for as an equity method investment.

Operating Expenses. Our operating expenses increased by approximately $4.0
billion in 2001 compared to 2000. The following factors were responsible for the
increase in operating expenses:

- The cost of fuel, electricity and other products increased by $3.3
billion in 2001 compared to 2000 primarily due to the combination of
unusually high prices for natural gas in the first quarter of 2001
40

and increased market demand for natural gas and power in the California market.
As noted above, power sales volumes in this region increased by approximately
181%. In the California market, the average price for purchased power and
natural gas increased by approximately 20% and 12%, respectively which
resulted in higher cost of fuel. Additionally, the costs from the net
capacity additions in the United States contributed to higher cost of
fuel, electricity and other products.

- Selling, general and administrative expense increased by $289 million in
2001 as compared to 2000. Our acquisition of the PEPCO assets in December
2000 contributed to the higher selling, general and administrative
expense in 2001. The provisions of $112 million recorded related to
receivables due from both the PX and PG&E, and provisions recorded of $68
million related to amounts due from Enron as a result of its bankruptcy
in December 2001, also contributed to the increase in selling, general
and administrative expense.

- Depreciation and amortization expense increased by $124 million in 2001
compared to 2000. This increase resulted primarily from depreciation
expense related to the plants we acquired in Maryland and Virginia in
December 2000, and the commencement of operations at our Wisconsin plant
in May 2000, at our Michigan plant in June 2001 and at our Texas plant
for the first and second phases in June 2000 and 2001, respectively.

- Maintenance expense increased by $69 million in 2001 as compared to 2000
partly as a result of approximately $36 million in additional expenses
attributable to the plants acquired in the PEPCO acquisition, and the
commencement of operations at our plants in Wisconsin, Michigan and
Texas.

- Other operating expenses increased by $202 million in 2001 compared to
2000 primarily as a result of the inclusion of expenses related to the
PEPCO assets acquired in December 2000.

INTERNATIONAL

Our International segment consists of power generating operations in Asia
and Trinidad and Tobago and our integrated utilities in Jamaica and the Bahamas.
For 2001 and 2000, it includes our operations in South America, and for 2000 it
also includes our distribution operations in Europe. The following table
summarizes the operations of our International businesses for the years ended
2002, 2001 and 2000 (in millions):

41

2002 versus 2001

Operating Revenues. Our operating revenues increased by $43 million in
2002 compared to 2001. The following factors were primarily responsible for the
increase in operating revenues:

- Our revenues from the generation of power increased by $32 million in
2002 compared to 2001 due to approximately $21 million of additional
revenue from our Philippine operations, primarily resulting from
increased sales volumes of excess capacity to new customers.

- Our distribution and integrated utility revenues increased by $10 million
in 2002 compared to 2001. This increase was due to the recognition of
approximately $114 million of additional revenue from 12 months of
operations in 2002 compared to nine months in 2001 related to our
Jamaican operation, which was acquired in March 2001. This was offset by
the reduction of approximately $95 million in revenue as a result of the
sale of our Chilean operations in December 2001.

Operating Expenses. Our operating expenses increased by $736 million in
2002 compared to 2001. The following factors were responsible for the changes in
operating expenses:

- Depreciation and amortization expense decreased by $40 million in 2002
compared to 2001 primarily as a result of no longer amortizing goodwill.
Goodwill amortization was $31 million in 2001. In addition, we recorded
approximately $4 million less depreciation related to certain assets that
were fully depreciated by the end of 2001 or disposed of during 2002.
These decreases were partially offset by additional depreciation of
approximately $2 million from units we acquired or from commencement of
operations from new units completed during 2001.

- Impairment losses and restructuring charges increased by $781 million in
2002 compared to 2001. The increase is primarily due to goodwill
impairment charges of approximately $697 million related to our Asia
operations and impairment charges of approximately $101 million related
to our development projects in Norway and Korea. Additionally, we
recorded restructuring charges of $65 million, which included $51 million
related to costs to cancel equipment orders and service agreements and
$14 million related to the severance of approximately 200 employees and
other employee termination-related charges. In 2001, we recorded an
impairment of $82 million relating to our investment in our Chilean
subsidiary, Empresa Electrica del Norte Grande S.A. ("EDELNOR").

- Gain on sale of assets in 2002 included a $30 million gain on the sale of
our investments in Australia and a $6 million gain on the sale of our
investments in Korea and the UK.

- Other expenses increased by $20 million in 2002 compared to 2001 which
was primarily attributable to a $14 million reclassification of operation
and maintenance integration costs in Asia from selling, general and
administrative expenses, and increased costs from owning JPSCo for a full
year versus nine months during 2001.

2001 versus 2000

Operating Revenues. Our operating revenues decreased by $44 million in
2001 compared to 2000. This decrease was primarily attributable to the
deconsolidation of WPD effective December 2000 offset by additional revenue from
nine months of operations in 2001 related to our Jamaican investment, which was
acquired in March 2001.

Operating Expenses. Our operating expenses increased by $169 million in
2001 compared to 2000. The following factors were responsible for the increase
in operating expenses:

- The increase in cost of fuel, electricity and other products and selling,
general and administrative expense was attributable to the inclusion of
additional expenses related to our Jamaican investment, which was
acquired in March 2001. Selling, general and administrative expense was
higher as a result of lower bad debt expense in 2000 related to the
Shajiao C venture.

42

- Maintenance expense decreased by $29 million in 2001 compared to 2000.
This decrease was primarily due to the deconsolidation of WPD effective
December 2000, offset somewhat by the additional expenses from JPSCo
after our acquisition of an 80% interest in JPSCo in March 2001.

- Impairment loss was $82 million in 2001, which was attributable to the
$82 million impairment of our investment in our Chilean subsidiary,
EDELNOR.

CORPORATE & OTHER

The following table summarizes our corporate expenses and other income and
expenses for the years ended 2002, 2001 and 2000 (in millions):

2002 versus 2001

Selling, general and administrative expense decreased by $21 million for
2002 compared to 2001 as a result of lower compensation expense.

Impairment losses and restructuring charges of $28 million in 2002 related
to the severance of 133 employees and other employee termination-related
charges.

Interest income declined $80 million in 2002 due to lower interest rates in
2002 compared to 2001.

Interest expense declined $119 million in 2002 due to a reduction in debt
stemming from dispositions made in 2002. In 2002 we sold assets that reduced
debt by $847 million, decreasing interest by approximately $79 million.
Capitalized interest increased by $21 million due to construction projects, as
noted in Item 2 "Properties," partially offset by higher interest rates stemming
from a refinancing in Asia.

Gain on sales of investments of $329 million primarily related to our gain
on sales of Bewag of $249 million and Shajiao C of $91 million. See Note 7 to
the accompanying consolidated financial statements for additional discussion.

43

Equity in income of affiliates declined $49 million in 2002 compared to
2001 primarily as the result of the sale of Bewag and WPD.

Impairment loss on minority owned affiliates is discussed in detail in Note
7 to the accompanying consolidated financial statements.

Provision for income taxes increased $693 million primarily due to
providing a valuation allowance of $1,088 million for the company's net deferred
tax assets in the United States. In addition, we provided deferred taxes of $468
million on the unremitted earnings of our foreign subsidiaries as a result of
changes in our plans for reinvestment of those earnings.

2001 versus 2000

Selling, general and administrative expense and other operating expenses
increased by $46 million and $12 million, respectively, compared to 2001. The
increase in selling, general and administrative expenses reflects an increase of
approximately $43 million in compensation and benefits expenses related to Stock
Appreciation Rights and Performance Restricted Stock Units. In addition, legal
and consulting were approximately $18 million higher in 2001. The 2000 amount
includes costs related to transitioning to a publicly traded company.

Equity in income of affiliates decreased by $36 million in 2001 as compared
to 2000. 2000 amounts included 12 months of equity in earnings from Mirant
Americas Energy Marketing prior to its consolidation upon our acquisition of the
remaining 40% minority interest in August 2000.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

We have incurred substantial indebtedness on a consolidated basis to
finance our business. As of December 31, 2002, our total consolidated
indebtedness was $8.9 billion (approximately $4.4 billion of which was recourse
to Mirant Corporation). Although we scaled back our capital expenditure programs
and sold a number of investments and businesses in 2002, we do not expect that
our cash flows from operations will cover all of our capital expenditures,
interest payments and debts as they become due and payable pursuant to their
scheduled maturities.

We are working on a restructuring plan pursuant to which we will ask
certain of our creditors to defer repayments of principal. Those creditors
include holders of approximately $4.5 billion of bank facilities (including our
turbine facility and prepaid gas transaction) and capital markets debt of Mirant
Corporation and approximately $800 million of bank and capital markets debt of
Mirant Americas Generation. The purpose of the restructuring is to enable the
Company to repay in full all of its obligations with interest, including
unsecured long term indebtedness that is not so extended. To reassure creditors
who will be asked to extend maturities, all of whom are currently unsecured, the
Company intends to offer security interests in substantially all of its and its
subsidiaries' unencumbered assets as well as terms more favorable to the
creditors. The Company has been working with its financial advisor to develop a
financial restructuring plan. If this restructuring plan is accepted by
creditors and creditors are ultimately paid in full, the Company believes that
there will be value available for existing shareholders. We note that there can
be no assurances either with respect to the accomplishment of the contemplated
financial restructuring or with respect to the values that may ultimately be
available for creditors or stockholders.

The restructuring of the debt of the Company is part of a broader effort to
refocus the Company and restructure the business of the Company. Our
restructuring activities thus far include:

- The sale of our investments in the United Kingdom (WPD), Germany (Bewag),
China (Shajiao C and SIPD) and others. The proceeds from the sale of
Bewag and Shajiao C and others were used to reduce debt by $847 million.
The net gains from the sale of our investments decreased our 2002 net
loss by $370 million, however, future earnings will be adversely impacted
by the loss of the related income from these investments.

44

- The cancellation or sale of 70 turbines and power islands in order to
reduce future cash expenditures. These actions increased our 2002 net
loss by $549 million, but will reduce future cash expenditures by
approximately $1.9 billion between 2003 and 2005. As of April 22, 2003,
approximately $160 million in additional cash will be required to cancel
the turbines.

- The reduction of our workforce by approximately 655. This action resulted
in a $51 million severance charge, but will result in approximately $78
million of annual payroll savings. We expect to continue to reduce our
workforce as we exit additional activities.

- The purchase of $83 million of TIERS Fixed Rate Trust Certificates for
approximately $51 million. TIERS Certificates represent beneficial
interests in approximately $400 million aggregate principal amount of our
2.5% Convertible Senior Debentures, which are held as the underlying
trust assets of a trust established on June 18, 2001 by Structured
Products Corp., an indirect wholly-owned subsidiary and affiliate of
Salomon Smith Barney Inc. We have no relationship with Structured
Products Corp. The TIERS Certificates mature on June 15, 2004. Pursuant
to the terms of the Call Right Agreement, Citibank was granted the right
to purchase the underlying trust assets from the trustee at any time up
to and including the maturity date. If Citibank does not exercise its
purchase right at least two business days prior to June 15, 2004, the
trustee is obligated to tender the underlying trust assets to Mirant and
Mirant is obligated to purchase all of the underlying trust assets
tendered in accordance with the terms of the indenture governing the 2.5%
Convertible Senior Debentures. This purchase obligation may be settled in
cash or, subject to meeting certain conditions, common stock. We
purchased the TIERS Certificates pursuant to an authorization by our
board of directors to repurchase up to $500 million of the Company's debt
securities as liquidity permits.

- We are currently pursuing various arrangements with multiple third
parties to sell certain of our Canadian assets, to monetize commodity
contracts related to our Canadian business and to restructure our
Canadian business operated by Mirant Canada Energy Marketing, Ltd. and
Mirant Canada Gas Marketing, Ltd. in order to reduce the overall
collateral requirements of the Canadian business while maintaining, on a
reduced scale with a reduced scope, a business presence in Canada.

If we are successful in our restructuring efforts, we expect to meet our
liquidity needs going forward through a combination of cash from operations,
revolving credit facilities, use of our existing cash balances and asset sales.
In addition, the anticipated contractions in the level of our trading and
marketing activities are expected to reduce the need for collateral provided by
letters of credit and cash deposits. If we are not successful in our
restructuring efforts, we would likely be required to seek bankruptcy court or
other protection from our creditors.

Cash Flows

Operating cash flow increased by $440 million in 2002 compared to 2001 due
to favorable changes in working capital in 2002. In 2002 working capital changes
provided $308 million in cash compared to a $535 million use of cash in 2001.
The main cause for the swing stems from the completed sale of our State Line
generating facility and Mirant Americas Production Company.

Cash provided by investing activities was $874 million in 2002 primarily
which included cash generated from asset sales of $2,282 million. This compares
to $2,866 million of cash used in 2001 related to growth activities such as
acquisitions and capital expenditures. The change between years is
characteristic of the repositioning activities that Mirant has engaged in for
most of 2002.

We used $548 million of cash in 2002 to reduce debt consistent with the
asset sale activities discussed above. In 2001 financing activities provided
cash to fund acquisition and growth activities. Similar to investing cash flows,
financing cash flows have changed between years consistent with the
repositioning activities in 2002.

45

The Company has restated its 2001 consolidated statement of cash flows to
reduce operating cash flows and increase financing cash flows by $217 million to
reclassify the proceeds received under a natural gas prepay transaction. See
Note 3 to our consolidated financial statements for additional information.

The cash flows set forth above are presented on a consolidated basis.
However, our operations are conducted primarily by our subsidiaries, and our
cash flow is dependent upon cash dividends and distributions and other transfers
from our subsidiaries. A significant number of our subsidiaries, including
Mirant Americas Generation and its subsidiary Mirant Mid-Atlantic, have
substantial indebtedness or lease obligations. These subsidiaries are restricted
under the terms of their indebtedness or lease obligations in their ability to
pay dividends or make distributions. These limitations generally require that
debt service payments or lease obligations be current, debt service coverage and
leverage ratios be met and that there be no default or event of default existing
under the respective facilities. In the event that such subsidiaries, including
Mirant Americas Generation and Mirant Mid-Atlantic, were unable to make
dividends and distributions to Mirant Corporation for a prolonged period, it
could have a material adverse affect on our liquidity. We note that Mirant
Mid-Atlantic is currently restricted from making dividends and, based on
projected ratio calculations, is expected to remain restricted until at least
the date on which financial statements for the fiscal quarter ended September
30, 2003 are delivered.

Total Cash and Available Credit

We believe that total cash and available credit is an important indication
of our ability to meet our obligations. The following table sets forth total
cash and available credit of Mirant Corporation and its subsidiaries as of April
25, 2003 and December 31, 2002 and 2001, respectively (in millions):

- ---------------

* estimated

(1) The ability of Mirant Americas Generation and Mirant Mid-Atlantic to
distribute cash to Mirant is subject to various covenants under their debt
and lease agreements. We note that Mirant Mid-Atlantic is currently
restricted from making dividends and, based on projected ratio calculations,
is expected to remain restricted until at least the date on which financial
statements for the fiscal quarter ended September 30, 2003 are delivered.

(2) The amount includes an estimated $447 million as of April 25, 2003, $619
million as of December 31, 2002 and $514 million as of December 31, 2001 at
various subsidiaries that either is required for operating, working capital
or other purposes at each respective subsidiary, or the distribution of
which is restricted by the subsidiaries' debt agreements and therefore is
not available for immediate payment to Mirant Corporation. As of April 25,
2003, we estimate that approximately $159 million of the $447 million is not
legally restricted from being used by Mirant Corporation. Total cash is
equal to

46

cash and cash equivalents as of such dates plus funds on deposit and cash
included in assets held for sale as follows (in millions):

Major uses of cash since December 31, 2002 that have resulted in the
decline in cash and availability under our credit facilities include:

- approximately $160 million in capital expenditures, primarily related to
completing the construction of four of our power plant facilities and
ongoing environmental and maintenance expenses;

- $125 million related to turbine cancellation payments;

- $269 million related to increased collateral and other operating
requirements;

- $51 million related to the purchase of TIERs; and

- a $73 million reduction in committed availability under our credit
arrangements.

Since December 31, 2002 we have received $233 million in proceeds from
asset sales.

The schedule below summarizes our bank credit facilities as of April 25,
2003 (in millions).

Our financing arrangements subject us to certain covenants which restrict
our activities and, under certain facilities, require us to maintain certain
financial ratios. As a result of write-downs to reflect the impairment of
goodwill, valuation allowances provided for net deferred tax assets, and
deferred tax liabilities provided with respect to investments in non-United
States subsidiaries, we anticipated that we would not be in compliance with the
recourse debt to recourse capital financial covenant under our bank facilities
(including the Mirant Americas Development Capital, LLC turbine facility) upon
delivery of our financial statements for the year ended December 31, 2002.
Therefore, we sought, and received, a waiver from the required lenders under
such bank facilities for any potential breaches with respect to non-compliance
with the recourse debt to recourse capital financial covenant, any potential
breaches that could arise relating to our historical financial reporting
requirements or representations or the inclusion in its independent auditors'
report on the Company's annual financial statements of an explanatory paragraph
stating that the Company has not presented the selected quarterly financial data
specified by Item 302(a)

47

of Regulation S-K, that the Securities and Exchange Commission requires as
supplementary information to the basic financial statements. The lenders under
such bank facilities have agreed to such waiver through May 29, 2003, subject to
certain terms and conditions, including limiting future use of the bank
facilities to issuances of letters of credit and limiting capital expenditures
and other material payments.(1) Upon expiration or termination of the waiver,
the lenders under the respective bank facilities would be able to restrict the
issuance of additional letters of credit and/or declare an event of default and,
after the applicable cure or grace period, accelerate the indebtedness under
such bank facilities. An acceleration of indebtedness under the Mirant
Corporation bank facilities would cross accelerate approximately $910 million of
Mirant capital markets and other indebtedness. The terms of the waiver provide
for an additional extension, to July 14, 2003, with the prior written consent of
lenders representing a majority of the committed amount under each of the
facilities. However, the Company can provide no assurances either with respect
to whether the waiver will be extended beyond May 29, 2003 or whether the
lenders under each of the Mirant bank facilities will accelerate the loans after
the expiration or termination of the waiver.

The Company has restated its 2000 and 2001 consolidated financial
statements to reflect the impact of discontinued operations and to correct
certain errors made in these periods. Upon delivery of the restated audited
financial statements for the fiscal years ended December 31, 2000 and December
31, 2001, and the audited financial statements for the fiscal year ended
December 31, 2002, and giving effect to the waiver received from the lenders
under our bank facilities, we do not believe that any events of default exist
under our bank facilities or capital markets debt, either with respect to
historical financial statements or otherwise. However, we note that, under their
respective bank facilities, our subsidiaries West Georgia Generating Company,
LLC and Mirant Canada Gas Marketing, Ltd. are required to deliver audited
financial statements of Mirant Corporation (with respect to West Georgia
Generating Company) and Mirant Americas Energy Marketing (with respect to both)
within 120 days of fiscal year end, which financial statements are to be
accompanied by a certification of independent public accountants that, in the
case of West Georgia Generating Company, is not qualified or limited because of
a restricted or limited examination. Although West Georgia Generating Company
and Mirant Canada Gas Marketing will not be able to provide such financial
statements within the 120 day period, we expect that they will be able to
provide the required financial statements within the applicable grace periods
under the respective facilities. Further, we have provided notice to the
trustees with respect to a series of convertible debt and our convertible trust
preferred securities, that we did not file with the trustees within 15 days
after required to be filed with the SEC, a copy of our annual report on Form
10-K. We expect to file the Form 10-K with the trustees within the respective
grace periods provided for under the convertible debt and convertible trust
preferred securities. Finally, we expect to provide the lenders and debt holders
restated interim financial information that are consistent with the restated
audited annual financial statements for the respective historical periods in a
timely manner.

We note that we expect to meet our liquidity needs while we work on
restructuring our debt with cash from operations, issuances of letters of credit
under our existing revolving credit facilities, existing cash balances and
proceeds of asset sales. However, in the event of a default under our respective
bank facilities (including, with respect to Mirant, upon expiration or
termination of the waiver under the Mirant bank facilities), the lenders under
our existing revolving bank facilities could elect to restrict the issuance of
additional letters of credit. In addition, upon a default under our credit
facilities or capital markets debt and the expiration of the applicable cure or
grace periods, the respective lenders and debt holders would have the right to
accelerate the obligations under their respective facilities. Any such
acceleration would trigger cross-acceleration of the otherwise non-defaulted
indebtedness. In the event our lenders or debt holders elect to accelerate our
indebtedness, or materially impact our liquidity by refusing to issue letters of
credit or otherwise, the Company would likely be required to seek bankruptcy
court or other protection.

- ---------------

(1) Pursuant to the requirements of Item 601(a)(4) of Regulation S-K, we will
file a copy of the waiver with the SEC with our Form 10-Q for the quarter
ending June 30, 2003.

48

Credit ratings impact our ability to obtain financing and the cost of such
financing, as well as, the amount of collateral needed to execute our commercial
activities. The majority of our debt is rated by the leading credit rating
agencies, Standard & Poor's ("S&P"), Fitch, Inc. ("Fitch") and Moody's Investors
Service ("Moody's"). As of April 18, 2003, all of the Company's debt was rated
by these agencies as below investment grade. As a result of downgrades of our
credit ratings in 2002, the interest rate on our corporate bank facilities has
increased by 1.05%.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

The Company's debt obligations, off-balance sheet arrangements and
contractual obligations, as discussed in Notes 10, 16 and 17 to our consolidated
financial statements, as of December 31, 2002 are as follows (in millions):

- ---------------

(1) These amounts include interest for certain capital lease obligations.

(2) The majority of these leases relate to Mirant Mid-Atlantic's Morgantown and
Dickerson facilities.

(3) These represent our total estimated commitments under our long-term service
agreements associated with turbines installed or in storage.

(4) The majority of the fuel commitments are related to our contract with BP
p.l.c. ("BP"), in which BP is obligated to deliver and we are obligated to
purchase at current spot prices fixed quantities of natural gas at
identified delivery points.

(5) The amounts represent the estimated commitments under the power purchase
agreements that Mirant assumed in the asset purchase and sale agreement for
the PEPCO generating assets. The estimated commitment is based on the total
remaining MW commitment at contractual prices.

COMMODITY TRADING ACTIVITIES

We provide risk management services through commodity trading to our
customers in North America. These services are provided through a variety of
exchange-traded and over-the-counter ("OTC") energy and energy-related
contracts, such as forward contracts, futures contracts, option contracts and
financial swap agreements. These contractual commitments are reflected at fair
value and 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 determination of fair value considers various factors, including
closing exchange or over-the-counter market price quotations, time value, credit
quality, liquidity and volatility factors underlying options and contractual
commitments. Certain financial instruments that Mirant uses to manage risk
exposure to energy prices for its North American generation portfolio do not
qualify for hedge accounting treatment, typically because they do not meet
strict hedge effectiveness criteria and/or hedge documentation criteria.
Therefore, the fair values of these instruments are included in "price risk
management assets and liabilities" in the accompanying consolidated balance
sheets.

49

The volumetric weighted average maturity, or weighted average tenor of the
North American portfolio, at December 31, 2002 was 2.5 years. The net notional
amount, or net long (short) position, of the price risk management assets and
liabilities at December 31, 2002 was approximately (3) million equivalent
megawatt-hours.

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
2002 (in millions).

Net fair value of portfolio at December 31, 2001............ $(1,036)
Gains (losses) recognized in the period, net................ 497
Contracts settled during the period, net.................... (74)
-------
Net fair value of portfolio at December 31, 2002............ $ (613)
=======

The fair values and average values of our price risk management assets and
liabilities, net of credit reserves, as of December 31, 2002 are included in the
following table (in millions). The average values are based on an annual average
for 2002.

The following table represents the net price risk management assets and
liabilities by tenor, complexity and liquidity, excluding derivative financial
instruments that were previously designated as cash flow hedges in accordance
with SFAS No. 133 and certain power purchase agreements that have been
determined to be derivatives under SFAS No. 133 and therefore subject to fair
value accounting (See Item 7A for more discussion). As of December 31, 2002,
approximately 86% of the net value was calculated using low complexity models
with high price discovery. These include forwards, swaps and options at actively
traded locations. Also, as of December 31, 2002, approximately 66% of the net
value was expected to be realized by the end of 2003. Examples of medium and
high complexity models include natural gas storage and transportation renewal
options, respectively.

50

- ---------------

Model Complexity:

- - Low -- Transactions involving exchange, or exchange look-a-like products with
no operational or other constraints.

- - Medium -- Transactions involving some operational constraints, but where these
constraints are not the primary drivers of value/risk.

- - High -- Transactions involving much more complex operational and/or
contractual constraints, incorporating factors such as temperature, and where
these items can be the primary drivers of value/risk.

Level of Price Discovery:

- - High -- Large, liquid markets within the next 3 years, with multiple daily
third party and/or exchange settled price quotes available.

- - Medium -- Less liquid markets with periodic external price quotes available,
or price levels which are validated, on a daily basis, indirectly as temporal
and/or locational spreads off of "High" price discovery data.

- - Low -- Illiquid markets with little or no external price quotes, or where the
underlying transactions constitute a large portion of the totality of the
transactions in the market.

The process of model development, independent testing and verification of
model robustness, system implementation and security, and version control are
all covered by the oversight activities of our Model Oversight Committee.
Documentation covering this process, including independent testing of model
results by the Risk Control organization, is maintained for oversight purposes.

See Item 7A "Market Risk" for further information.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The accounting policies described below are considered critical in
obtaining an understanding of Mirant's consolidated financial statements because
their application requires significant estimates and judgments by management in
preparing these consolidated financial statements. Management's estimates and
judgments are inherently uncertain and may differ significantly from actual
results achieved. Management believes that the following critical accounting
policies and the underlying estimates and judgments involve a higher degree of
complexity than others do. In addition, the estimates and assumptions used in
applying these critical accounting policies to our financial statements and
other estimates about future operating results affect the calculation of the
financial ratios and measures used to determine the Company's compliance with
its debt covenants. Significant changes in these estimates and assumptions could
impact calculations under our debt covenants. A more complete discussion
regarding debt compliance and the Company's plans regarding future debt
restructuring activities is discussed in "Financial Condition -- Liquidity and
Capital Resources."

ACCOUNTING FOR COMMODITY TRADING ACTIVITIES:

Our commodity trading activities include new origination transactions and
risk management activities using contracts for energy, other energy related
commodities and related derivative contracts. We use the mark-to-market method
of accounting for our commodity trading activities. Under the mark-to-market
method of accounting, we record the fair value of commodity and derivative
contracts as price risk management assets and liabilities at the inception of
the contract with changes in fair value being recorded on a net basis in
revenues. Certain commodity trading transactions are entered into under master
netting agreements that provide us with legal right of offset in the event of
default by the counterparty and are therefore reported net in our consolidated
balance sheets. Prior to the issuance of EITF 02-03, "Issues Related to
Accounting for Contracts involved in Energy Trading and Risk Management
Activities" the Company followed the guidance in EITF 98-10. Under 98-10, all
energy trading contracts were accounted for at fair value. The consensus reached
in EITF 02-03 rescinded EITF Issue 98-10 and required that all

51

energy trading contracts that do not qualify as derivatives under SFAS No. 133
such as transportation contracts, storage contracts, and tolling agreements,
should no longer be accounted for at fair value but rather on an accrual basis.
This consensus was effective for all new contracts executed after October 25,
2002, and will require a cumulative effect adjustment to income after tax on
January 1, 2003 for all contracts executed prior to October 25, 2002 which do
not qualify as derivatives under SFAS No. 133. Our energy contracts that qualify
as derivatives will continue to be accounted for at fair value under SFAS No.
133.

We enter into a variety of contractual agreements, such as forward purchase
and sale agreements, and futures, swaps and option contracts. Futures and option
contracts are traded on a national exchange and swaps and forward contracts are
traded 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.

The fair value of these contracts are primarily determined using quoted
market prices, or if no active trading market exists, quantitative pricing
models. We estimate the fair value of derivative contracts using our pricing
models based on contracts with similar terms and risks. Our modeling techniques
assume market correlation and volatility such as using the prices of one
delivery point to calculate the price of the contract's delivery point in the
model. The nominal value of the transaction is also discounted using a London
InterBank Offered Rate ("LIBOR") based forward interest rate curve. In addition,
the fair value of our derivative contracts includes credit reserves reflecting
the risk that the counterparties to these contracts may default on their
obligations. The degree of complexity of our pricing models increases for longer
duration contracts, contracts with multiple pricing features and off hub
delivery points. The amounts recorded as revenue change as these estimates are
revised to reflect actual results and changes in market conditions or other
factors, many of which are beyond our control.

As of December 31, 2002, approximately $12 million of the net fair value of
our price risk management assets and liabilities, excluding derivative financial
instruments previously designated as cash flow hedges (see Item 7A for further
discussion), was calculated using models with low price discovery. Low price
discovery includes illiquid markets with little or no external price quotes, or
where the underlying transactions constitute a large portion of the totality of
the transactions in the market. These circumstances require management to make
assumptions about forward commodity prices and volatility which could vary from
actual future results. As a result of the limited amount of transactions and
values that are derived using these quantitative models, our reported financial
results should not be materially effected by these estimates. However, in the
future, we could enter into additional contracts that are accounted for at fair
value which may be difficult to measure. The Model Risk Oversight Committee
maintains responsibility to review the model assumptions and design to ensure
that the valuation methodologies are consistent and appropriate.

INCOME TAX VALUATION ALLOWANCE

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 availability 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 a company's deferred
tax assets when significant negative evidence exists. Cumulative losses are the
most compelling form of negative evidence considered by management in this
determination. In 2002, the Company recognized a valuation allowance of $1,088
million primarily related to its United States net deferred tax assets.

52

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 the
impairment charge is calculated as the excess of the asset's carrying value over
its fair value, which generally represents the discounted future cash flows from
that asset or in the case of assets we expect to sell, at fair value less costs
to sell. In 2002, we recorded several impairment charges totaling $373 million
as shown in the table below (in millions).

Turbines and Related Project Costs: In March 2002 and December 2002, the
Company recognized impairment charges of approximately $151 million related to
the construction work in progress costs of turbines to be terminated and certain
turbines that it intends to place in storage and the related project costs. As
of December 31, 2002, the remaining estimated fair value of these projects was
approximately $3 million, and is included in property, plant and equipment, net
in the consolidated balance sheets.

Impairment charges for turbines are based on comparing our book value to
the expected amounts that would be recoverable from a sale. The estimated sale
values are determined by using quoted prices. The market for turbines is not
liquid and there is no way of knowing for certain the net realizable value until
proceeds are received or otherwise realized.

Substantially all construction has been suspended on four projects that
resulted in impairment charges of $77 million related to the Mint Farm project
only. These impairment charges were based on comparing the estimated discounted
cash flows, including costs of delaying construction, incurring suspension costs
and later continuing development against the fair value of the discounted cash
flows from the planned operations of the power plants. The estimated cash flows
from the plants are based on our estimate of forward electricity and natural gas
prices that have varying degrees of transparency. The forward market prices for
natural gas are generally available for 36 months to 48 months. Forward market
prices for electricity are generally available for 24 months to 36 months. For
forward prices beyond these periods, we construct a model based on third party
data and our market expectations. This data assumes demand and supply changes
impacting the power generation market that are difficult to accurately predict.
We discounted expected cash flows using an 8.5% rate, which was determined to be
an appropriate rate reflective of project risk. The impairment charges for these
three projects would change by $20 million for every 100 basis point change in
the discount rate.

Power Islands: In the third quarter of 2002, the Company assessed the
recoverability of certain costs associated with two engineered equipment
packages (commonly referred to as "power islands") related to its proposed
development projects in Europe and Korea. Based on management's estimate of
recoverability of the costs of these power islands, an impairment loss of $134
million was recognized in 2002. The Company also recorded an impairment loss of
$11 million for the related Yulchon Project site in Korea.

Other Long-Lived Assets: We reviewed the estimated undiscounted future
cash flows of our other North American, Caribbean, and Asian long-lived assets
and concluded that the estimated cash flows attributable to each of the assets
exceeded their carrying value. Consequently, we did not record any impairment
losses on these assets.

53

GOODWILL AND INTANGIBLE ASSETS

In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," we
evaluate our goodwill and indefinite-lived intangible assets for impairment at
least annually and periodically if indicators of impairment are present. The
Statement requires that if the fair value of a reporting unit is less than its
carrying value including goodwill (Step I), an impairment charge for goodwill
must be recognized. The impairment charge is calculated as the difference
between the implied fair value of the reporting unit goodwill and its carrying
value (Step II).

Upon adopting SFAS No. 142, we defined our reporting units, as required by
the Statement, for purposes of testing goodwill for impairment. Our reporting
units are the Americas, the Caribbean and Asia. The geographically defined
reporting units have specific management that is held responsible for
decision-making for a group of components representing the reporting unit. These
reporting units reflect the way we manage our business. Impairment testing at
this reporting unit level reflects how acquisitions were integrated into Mirant
and how Mirant is managed overall. The components within our reporting units
serve similar types of customers, provide similar services and operate in
similar regulatory environments. The benefits of goodwill are shared by each
component.

In performing the impairment evaluation required by SFAS No. 142, the
Company estimates the fair value of each reporting unit and compares it to the
carrying amount of that reporting unit. To the extent the carrying amount of a
reporting unit exceeds the fair value of that reporting unit, the Company is
required to perform the second step of the impairment test. In this step, the
Company compares the implied fair value of the reporting unit goodwill with the
carrying amount of the reporting unit goodwill. The implied fair value of
goodwill is determined by allocating the fair value of the reporting unit to all
of the assets (recognized and unrecognized) and liabilities of the reporting
unit in a manner similar to a purchase price allocation, in accordance with SFAS
No. 141. The residual fair value after this allocation is the implied fair value
of the reporting unit goodwill. Upon the adoption of SFAS No. 142, the fair
value of each of the Company's reporting units exceeded the carrying amount of
the reporting unit in the transition test and no impairment charge was
recognized.

In connection with our annual impairment assessment performed as of October
31, 2002, we tested all of our reporting units for impairment and recorded an
impairment charge of $697 million for goodwill related to our Asia reporting
unit. No impairment charge for goodwill related to our North American or
Caribbean reporting units was assessed. We believe that the accounting estimates
related to determining the fair value of goodwill and any resulting impairment
are critical accounting estimates because they are highly susceptible to change
from period to period because determining the forecasted future cash flows
related to the assets requires management to make assumptions about future
revenues, operating costs and forward commodity prices over the life of the
assets, and because of the impact that recognizing an impairment could have on
our compliance with certain debt covenant financial ratios. Our assumptions
about future sales, costs and forward prices require significant judgment
because such factors have fluctuated in the past and will continue to do so in
the future. Due to the subjective nature of our goodwill impairment analysis we
have provided certain critical assumptions used in our analysis for each of our
reporting units as follows:

Asia Goodwill Analysis -- Based on our impairment analysis, we recorded an
impairment charge of $697 million in the fourth quarter of 2002. This impairment
was primarily attributable to the loss of future cash flows associated with
certain Asian assets sold during the year, principally our investment in Shajiao
C. Within our Asian business are three long-term power plant contracts that
transfer ownership of the power plants to the Philippine NPC between 2022 and
2025. Three of our largest power projects in this reporting unit, Sual, Pagbilao
and Ilijan, representing 82% of the capacity, have entered into fixed-price,
long-term contracts with NPC. The contracts are build-operate-transfer ("BOT")
agreements pursuant to which Mirant Asia-Pacific builds the power facilities,
operates them during a cooperation period of up to twenty-five years, then
transfers ownership to NPC at the end of the cooperation period. Under the
contract, the NPC acts as both the fuel supplier and the energy off-taker. As a
result, substantially all the dispatch risk and fuel price risk remains with
NPC. The payments under the BOT agreements are almost

54

entirely in United States dollars and not subject to currency fluctuations.
Mirant Asia-Pacific also enjoys protection against political force majeure and
change in law under the contracts. These three BOT projects contribute more than
90% of the cash flow for Mirant Asia-Pacific. The contractual ownership transfer
will impact our annual goodwill analysis resulting in a portion of the remaining
goodwill balance being written off periodically until the time of ownership
transfer. Prior to the impairment charge in the fourth quarter of 2002, we had
$1.3 billion of goodwill on our consolidated balance sheet related to the Asia
reporting unit. As of December 31, 2002, we have $582 million of goodwill on our
consolidated balance sheet related to the Asia reporting unit. The critical
assumptions used in our analysis are as follows:

- Mirant's Sual project operates under a 25-year term BOT agreement with
1,000 MW of capacity committed to NPC. At the end of the agreement,
October 2024, the plant is required to be transferred to NPC free from
any lien or payment of compensation. NPC acts as both the fuel supplier
and energy off-taker under the agreement. NPC procures all the fuel
necessary for each plant, at no cost to Mirant Asia-Pacific's subsidiary,
and has accepted substantially all fuel risks and fuel related
obligations other than each plant's actual fuel burning efficiency.
Mirant Asia-Pacific receives compensation under the BOTs for fixed
capacity fees, variable energy fees and other incidental fees. Over 90%
of the revenues are expected to come from fixed capacity charges that are
paid without regard to dispatch level of the plant. Capital recovery
fees, infrastructure fees, and service fees, which comprise most of the
fixed capacity charges, are denominated in United States dollars. The
fixed operating fees, energy fees and other incidental fees have both
United States dollar and Philippine peso components that are both indexed
to inflation rates. Mirant is responsible for management, operations and
maintenance of the plants and earns fees for providing those services.
The remaining net available capacity is sold to NPC and large industrial
or commercial users at contracted prices.

- Mirant's Pagbilao project operates under a 29-year term BOT agreement
with 735 MW of capacity committed to NPC. At the end of the agreement,
August 2025, the plants are required to be transferred to NPC free from
any lien or payment of compensation. NPC acts as both the fuel supplier
and energy off-taker under the agreement. NPC procures all the fuel
necessary for each plant, at no cost to Mirant Asia-Pacific's subsidiary,
and has accepted substantially all fuel risks and fuel related
obligations other than each plant's actual fuel burning efficiency.
Mirant Asia-Pacific receives compensation under the agreement for fixed
capacity fees, variable energy fees and other incidental fees. Over 90%
of the revenues are expected to come from fixed capacity charges that are
paid without regard to dispatch level of the plant. Capital recovery
fees, infrastructure fees, and service fees, which comprise most of the
fixed capacity charges, are denominated in United States dollars. The
fixed operating fees, energy fees and other incidental fees have both
United States dollar and Philippine peso components that are both indexed
to inflation rates.

- Mirant holds a 20% minority interest in Ilijan, a 1,251 NW gas-fired
combined cycle power plant in the Philippines. Ilijan operates under a
20-year energy conversion agreement for 1,200 MW with NPC.

- Other Items -- The Asia forecasted cash flow data assumes the Pagbilao
and Sual minority shareholders exercise the put options requiring Mirant
Asia-Pacific to purchase the minority shareholders' interest in the
Pagbilao and Sual projects between 2003 and 2005.

- Cost of Capital -- The cost of capital rate significantly impacts the
fair value of our projected future cash flows. We used a cost of capital
of 13% in determining the present value of our projected future cash
flows. The rate was determined based on a study of discount rates in the
current market used to value similar cash flow streams, specific capital
fundamentals related to Mirant and comparable industry group data. 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
$70 million.

North America Goodwill Analysis -- We engaged a third party appraisal firm
to review our annual financial plan and perform our Step I goodwill impairment
analysis to determine if the fair value of our

55

North American reporting unit was less than its carrying value including
goodwill at October 31, 2002. The third party appraisal firm reviewed the
critical assumptions used in our financial plan. The result of the impairment
analysis indicated that the fair value of our North American reporting unit was
higher than its carrying value including goodwill at October 31, 2002 indicating
that no impairment was necessary. At December 31, 2002, we had $2 billion of
goodwill on our consolidated balance sheet related to the North American
segment. The critical assumptions used in our analysis are as follows:

- Forward Prices of Electricity and Natural Gas -- We used the forward
market curves that are used by Mirant for mark-to-market accounting and
that are regularly checked by Mirant's Risk Control group against broker
quotes and exchange closing prices. Typically, the liquidity of these
forward markets decreases significantly as maturity increases. Liquid
market data is generally available in the first 36-48 months for natural
gas prices and 24-36 months for power prices. Since our forecast is a
10-year estimate, for periods outside the liquid market we construct the
forward prices using data available from third parties and our market
knowledge. As such, our estimated future cash flows which contribute to
the determination of the fair value of our North American reporting unit
are highly sensitive to these price forecasts.

- Terminal Value -- We assume a terminal value based on the ability to
continue plant operations and additional growth from plant expansion or
new construction after 2010. Mirant employed a 4% terminal growth rate
assumption in the discounted cash flow analysis. This rate was determined
considering inflationary growth, historical and projected GDP growth,
electricity demand, and generation capacity growth. The sensitivity of
the fair value of our projected future cash flows is such that a 100
basis point change in the terminal value growth rate would change the
discounted value of our projected future cash flows by approximately $800
million.

- Assets sales -- Our financial plan assumes certain asset sales
representing approximately 2,000 MW of generating capacity in the North
American segment.

- Weighted average cost of capital -- the weighted average cost of capital
rate significantly impacts the fair value of our projected future cash
flows. We used a weighted average cost of capital of 10.25% in
determining the present value of our projected future cash flows. The
rate was determined based on a study of discount rates in the current
market used to value similar cash flow streams, specific capital
fundamentals related to Mirant and comparable industry group data. The
sensitivity of the fair value of our projected future cash flows is such
that a 100 basis point change in the rate would change the discounted
value of our projected future cash flows by approximately $1.2 billion.

The above assumptions were critical to our arriving at fair values of
the physical assets and other intangible assets of the Company. We used the
income approach in valuing our assets rather than a market approach, except
in the case of assets expected to be sold, because we believe the income
approach provides the best indicator of value that we expect to derive for
our stakeholders over time. We used the market approach for expected asset
sales. The combined subjectivity and sensitivity of our assumptions and
estimates used in our goodwill impairment analysis could result in a
reasonable person concluding differently on those critical assumptions and
estimates resulting in an impairment charge being required.

Equity Method Investments -- We analyze our equity method investments,
generally defined as investments where we own less than 50% but more than 20% of
the voting stock, for impairment whenever evidence is present indicating a loss
in value or ability to recover the carrying value of our investment. An
impairment charge is required to be recorded if the resulting decline in value
reduces the fair value our investment below its carrying value, and the decline
is considered other than temporary. In the second quarter of 2002, we made the
decision to sell our investment in WPD. Based on the initial purchase offers, we
determined that our investment had experienced an other than temporary decline
in fair value below our carrying value. We recorded an impairment charge of $325
million based on the preliminary purchase offers and an analysis from an
investment banking firm regarding our investment. In the third quarter of 2002,
we sold our investment in WPD for $235 million resulting in an additional loss
of $3 million.

56

We also recorded an impairment charge of $132 million related to our
investment in CEMIG upon our decision to sell this investment to reflect its
estimated net realizable value. CEMIG was sold in December 2002.

LITIGATION

We are currently involved in certain legal proceedings. These legal
proceedings are discussed in Item 3 Legal Proceedings and Note 15 to our
consolidated financial statements contained elsewhere in this report. 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 when the loss is considered probable, or the low end of our
range if no estimate is better than another estimate within a range of
estimates. 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.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information presented in this Form 10-K includes forward-looking
statements in addition to historical information. These statements involve known
and unknown risks and relate to future events, our future financial performance
or our projected business results. In some cases, you can identify forward-
looking statements by terminology such as "may," "will," "should," "expects,"
"plans," "anticipates," "believes," " estimates," "predicts," "targets,"
"potential" or "continue" or the negative of these terms or other comparable
terminology.

Forward-looking statements are only predictions. Actual events or results
may differ materially from any forward-looking statement as a result of various
factors, which include: (1) legislative and regulatory initiatives regarding
deregulation, regulation or restructuring of the electric utility industry; (2)
the failure of our assets to perform as expected or the extent and timing of the
entry of additional competition in the markets of our subsidiaries and
affiliates; (3) our pursuit of potential business strategies, including the
disposition of assets, termination of construction of certain projects or
internal restructuring; (4) changes in state, federal and other regulations
(including rate and other regulations); (5) changes in or application of
environmental and other laws and regulations to which we and our subsidiaries
and affiliates are subject; (6) political, legal and economic conditions and
developments; (7) changes in market conditions, including developments in energy
and commodity supply, demand, volume and pricing; (8) weather and other natural
phenomena; (9) war or the occurrence of a catastrophic loss; (10) deterioration
in the financial condition of our counterparties and the resulting failure to
pay amounts owed to us or perform obligations or services due to us; (11)
financial market conditions and the results of Mirant's financial restructuring
efforts, including its inability to obtain long-term or working capital on terms
that are not prohibitive and the effects that would result on our liquidity and
business; (12) the direct or indirect effects on our business of a lowering of
our credit rating or that of Mirant Americas Generation or Mirant Americas
Energy Marketing (or actions taken by us or our affiliates in response to
changing credit ratings criteria), including, increased collateral requirements
to execute our business plan, demands for increased collateral by our current
counterparties, curtailment of certain business operations in order to reduce
the amount of required collateral, refusal by our current or potential
counterparties or customers to enter into transactions with us and our inability
to obtain credit or capital in amounts needed or on terms favorable to us; (13)
the disposition of the pending litigation described in this Form 10-K; (14) the
direct or indirect effects of the "going concern" explanatory paragraph
contained in our, or our subsidiaries' independent auditors' reports; and (15)
other factors, including the risks discussed elsewhere in this Form 10-K.

Although we believe that the expectations reflected in the forward-looking
statements are reasonable, we cannot guarantee future results, events, levels of
activity, performance or achievements. We expressly disclaim a duty to update
any of the forward-looking statements.

57

FACTORS THAT COULD AFFECT FUTURE PERFORMANCE

In addition to the discussion of certain risks in Management's Discussion
and Analysis of Financial Condition and Results of Operations and the notes to
Mirant's consolidated financial statements, other factors that could affect the
Company's future performance (business, financial condition or results of
operations) are set forth below.

WE HAVE INCURRED SUBSTANTIAL INDEBTEDNESS ON A CONSOLIDATED BASIS TO FINANCE
OUR BUSINESS. AS OF DECEMBER 31, 2002, OUR TOTAL CONSOLIDATED INDEBTEDNESS WAS
$8.9 BILLION (APPROXIMATELY $4.4 BILLION OF WHICH WAS RECOURSE TO MIRANT
CORPORATION). WE DO NOT EXPECT THAT OUR CASH FLOWS FROM OPERATIONS WILL COVER
ALL OF OUR CAPITAL EXPENDITURES, INTEREST PAYMENTS AND DEBTS AS THEY BECOME
DUE AND PAYABLE PURSUANT TO THEIR SCHEDULED MATURITIES. WE ARE WORKING ON A
RESTRUCTURING PLAN PURSUANT TO WHICH WE WILL ASK CERTAIN OF OUR CREDITORS TO
DEFER REPAYMENTS OF PRINCIPAL. OUR PURPOSE IS TO ENABLE THE COMPANY TO REPAY
IN FULL ALL OF ITS OBLIGATIONS WITH INTEREST, INCLUDING UNSECURED LONG-TERM
INDEBTEDNESS THAT IS NOT SO EXTENDED. OUR INABILITY TO SUCCESSFULLY
RESTRUCTURE OUR DEBT WOULD MATERIALLY AND ADVERSELY EFFECT OUR FINANCIAL
CONDITION AND WOULD LIKELY CAUSE US TO SEEK BANKRUPTCY COURT OR OTHER
PROTECTION FROM OUR CREDITORS.

We have incurred substantial indebtedness on a consolidated basis to
finance our business. As of December 31, 2002, our total consolidated
indebtedness was $8.9 billion (approximately $4.4 billion of which was recourse
to Mirant Corporation). We do not expect that our cash flows from operations
will cover all of our capital expenditures, interest payments and debts as they
mature. We are working on a restructuring plan pursuant to which we will ask
certain of our creditors to defer repayments of principal. Those creditors
include holders of approximately $4.5 billion of bank facilities (including our
turbine facility and prepaid gas transaction) and capital markets debt of Mirant
Corporation and approximately $800 million of bank and capital markets debt of
Mirant Americas Generation. To reassure creditors who will be asked to extend
maturities, all of whom are currently unsecured, the Company intends to offer
security interests in substantially all of its and its subsidiaries'
unencumbered assets as well as terms more favorable to the creditors. The
purpose of the restructuring is to enable the Company to repay in full all of
its obligations with interest, including unsecured long-term indebtedness that
is not so extended. The Company has been working with its financial advisor to
develop its financial restructuring plan. If this restructuring plan is accepted
by creditors and creditors are ultimately paid in full, the Company believes
that there will be value available for existing shareholders. We note that there
can be no assurances either with respect to the accomplishment of the
contemplated financial restructuring or with respect to the values that may
ultimately be available for creditors and stockholders. In the event that we are
unable to successfully restructure our debt we would likely be required to seek
bankruptcy court or other protection from our creditors.

THE LENDERS UNDER THE MIRANT CORPORATION BANK FACILITIES HAVE WAIVED COMPLIANCE
WITH CERTAIN TERMS OF THOSE FACILITIES THROUGH MAY 29, 2003. UPON EXPIRATION OR
TERMINATION OF THE WAIVER, THE LENDERS UNDER THE RESPECTIVE BANK FACILITIES
WOULD BE ABLE TO RESTRICT THE ISSUANCE OF ADDITIONAL LETTERS OF CREDIT AND/OR
DECLARE AN EVENT OF DEFAULT AND, AFTER THE RESPECTIVE CURE OR GRACE PERIOD,
ACCELERATE THE INDEBTEDNESS UNDER SUCH BANK FACILITIES. AN ACCELERATION OF
INDEBTEDNESS UNDER THE MIRANT CORPORATION BANK FACILITIES WOULD CROSS
ACCELERATE APPROXIMATELY $910 MILLION OF MIRANT CORPORATION CAPITAL MARKETS AND
OTHER INDEBTEDNESS.

As a result of write-downs to reflect the impairment of goodwill, valuation
allowances provided for net deferred tax assets, and deferred tax liabilities
provided with respect to investments in non-United States subsidiaries, we
anticipated that Mirant Corporation would not be in compliance with the recourse
debt to recourse capital financial covenant under its bank facilities upon
delivery of its financial statements for the year ended December 31, 2002.
Therefore, we sought, and received, a waiver from the required lenders under the
Mirant Corporation bank facilities for any potential breaches with respect to
non-compliance with the recourse debt to recourse capital financial covenant,
any potential breaches that could arise relating to our historical financial
reporting requirements or representations or the inclusion in its

58

independent auditors' report on the Company's annual financial statements of an
explanatory paragraph stating that the Company has not presented the selected
quarterly financial data specified by Item 302(a) of Regulation S-K, that the
Securities and Exchange Commission requires as supplementary information to the
basic financial statements. The lenders under the respective Mirant Corporation
bank facilities have agreed to such waiver through May 29, 2003, subject to
certain terms and conditions, including limitations on capital expenditures and
other material payments. Simultaneous with the term of the waiver, we will be
working with the lenders under the Mirant Corporation bank facilities, together
with other creditors, on a comprehensive plan to restructure our debt. Upon
expiration or termination of the waiver, the lenders under the respective bank
facilities would be able to restrict the issuance of additional letters of
credit and/or declare an event of default and, after the respective cure or
grace period, accelerate the indebtedness under such bank facilities. An
acceleration of indebtedness under the Mirant Corporation bank facilities would
cross accelerate approximately $910 million of Mirant Corporation capital
markets and other indebtedness. The terms of the waiver provide for an
additional extension, to July 14, 2003, with the prior written consent of
lenders representing a majority of the committed amount under each of the
facilities. However, the Company can provide no assurances either with respect
to whether the waiver will be extended beyond May 29, 2003 or whether the
lenders under the Mirant Corporation bank facilities will accelerate the loans
after expiration or termination of the waiver. In the event that we are unable
to secure a waiver beyond May 29, 2003, we would likely be required to seek
bankruptcy court or other protection from our creditors.

OUR ACTIVITIES ARE RESTRICTED BY SUBSTANTIAL INDEBTEDNESS. THIS INDEBTEDNESS
MAY BE ACCELERATED IF WE ARE UNABLE TO SERVICE IT. ACCELERATION OF SOME OF OUR
DEBT MAY CAUSE OTHER LENDERS TO ACCELERATE OTHER DEBT OBLIGATIONS.

We have incurred substantial indebtedness on a consolidated basis to
finance our business. As of December 31, 2002, our total consolidated
indebtedness was $8.9 billion (approximately $4.4 billion of which was recourse
to Mirant Corporation), our total consolidated assets were $19.4 billion and our
stockholders' equity was $3.0 billion. Our level of indebtedness has important
consequences, including:

- limiting our ability to refinance existing indebtedness as it comes due
and to borrow additional amounts for working capital, capital
expenditures, debt service requirements, execution of our business plan
or other purposes,

- limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service our debt,

- increasing our vulnerability to general adverse economic and industry
conditions, and

- limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.

In addition, some of our existing debt agreements contain restrictive
covenants which, among other things, limit our ability to:

- incur indebtedness,

- make prepayments of indebtedness in whole or in part,

- pay dividends,

- make investments,

- engage in transactions with affiliates,

- create liens,

- sell assets, and

- acquire facilities or other businesses.

59

If we or one of our subsidiaries are unable to comply with the terms of its
debt agreements, the relevant debt holders may accelerate the maturity of the
obligations of such borrower. Although a default or acceleration of debt at the
subsidiary level would not trigger a cross-default under Mirant Corporation's
credit arrangements, a default or acceleration of our debt, or our
subsidiaries', could cause cross-defaults or cross-accelerations under the
obligations of such borrower and, in certain instances, the obligations of our
other subsidiaries. In such event, and because of our substantial indebtedness,
we may be unable to refinance such indebtedness and the respective borrower may
be unable to repay such debt.

CHANGES IN COMMODITY PRICES MAY IMPACT FINANCIAL RESULTS, EITHER FAVORABLY OR
UNFAVORABLY.

Our generation and distribution businesses are subject to changes in power
prices and fuel costs which may impact their financial results and financial
position by increasing the cost of producing power and decreasing the amounts
they receive from the sale of power. In addition, actual power prices and fuel
costs may differ from those assumed in our financial models.

Many factors influence the level of commodity prices, including weather,
illiquid markets, 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 may, at times, have an open position in the market, within
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 we devote a
considerable amount of management efforts to these issues, their outcome is
uncertain.

OUR LIQUIDITY AND PROFITABILITY MAY DECLINE IF WE ARE NOT ABLE TO EXECUTE OUR
HEDGING STRATEGY OR IF OUR HEDGING STRATEGIES DO NOT WORK AS PLANNED.

To lower our financial exposure related to commodity price fluctuations,
our commodity trading operations may enter into contracts to hedge purchase and
sale commitments, weather conditions, fuel requirements and inventories of
natural gas, coal, electricity, crude oil and other commodities. As part of this
strategy, we routinely utilize fixed-price forward physical purchase and sales
contracts, futures, financial swaps and option contracts traded in the
over-the-counter markets or on exchanges. However, we do not expect to cover the
entire exposure from market price volatility of our assets and the coverage will
vary over time. In addition, as a result of marketplace illiquidity and other
factors, our commodity trading operations will likely not be able to or may
choose not to fully hedge our portfolios for market risks. This inability to
hedge against changes in commodity prices may cause our profitability to
decline.

OUR PROJECTS LOCATED OUTSIDE OF THE UNITED STATES EXPOSE US TO RISKS RELATED
TO LAWS OF OTHER COUNTRIES, TAXES, ECONOMIC CONDITIONS, FLUCTUATIONS IN
CURRENCY RATES, LABOR SUPPLY AND RELATIONS, POLITICAL CONDITIONS AND POLICIES
OF FOREIGN GOVERNMENTS. THESE RISKS MAY DELAY OR REDUCE OUR REALIZATION OF
VALUE FROM OUR INTERNATIONAL PROJECTS.

We have substantial operations outside the United States. In 2002, we
derived approximately 16% of our operating revenues from foreign operations. The
financing and operation of projects outside the United States entail significant
political and financial risks, which vary by country, including:

- changes in laws or regulations,

- changes in foreign tax laws and regulations, including unexpected tax
liabilities,

- changes in United States laws, including tax laws, related to foreign
operations,

60

- compliance with United States foreign corrupt practices laws,

- changes in government policies or personnel,

- changes in general economic conditions affecting each country,

- difficulty in converting earnings to United States dollars or moving
funds out of the country in which the funds were earned,

- fluctuations in currency exchange rates,

- changes in labor relations in operations outside the United States,

- political instability and civil unrest, and

- expropriation and confiscation of assets and facilities.

Despite contractual protections we have against many of these risks for our
operations in the Philippines and some other countries in which Mirant operates
or may invest in the future, our actual results may be affected by the
occurrence of any of these events.

Risk from fluctuations in currency exchange rates can arise when our
foreign subsidiaries borrow funds in one type of currency but receive revenue in
another. In such cases, an adverse change in exchange rates can reduce our
ability to meet debt service obligations. Foreign currency risk can also arise
when the revenues received by our foreign subsidiaries are not in United States
dollars. In such cases, a strengthening of the United States dollar could reduce
the amount of cash and income we receive from these foreign subsidiaries.

While we believe we have contracts in place to mitigate our most
significant foreign currency exchange risks, we have some exposure that is not
hedged.

SOME OF OUR 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 LOSS IN REVENUES AND MAY
REQUIRE US TO INSTITUTE LEGAL PROCEEDINGS TO ENFORCE OUR AGREEMENTS.

Several of our power production facilities rely 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. Our sale and procurement agreements for these
facilities may also provide support for any project debt used to finance the
related facilities. The financial performance of these facilities is dependent
on the continued performance by customers and suppliers of their obligations
under their long-term agreements.

In addition, our commodity trading operations are exposed to the risk that
counterparties which owe us money or energy as a result of market transactions
will not perform their obligations. We are currently owed significant past due
revenues from the PX and CAISO.

Finally, revenue under some of our power sales agreements may be reduced
significantly upon their expiration or termination. Much 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 under such agreements.

FAILURES OF COMPANIES WITHIN OUR SECTOR COULD HAVE A MATERIALLY ADVERSE EFFECT
ON US.

The failure of companies within our sector could have a materially negative
effect on our business. As a result of intra-industry company failures and other
factors, we have experienced such adverse effects as increased negative
sentiment and reactions from our customers, investors, lenders and credit rating
agencies, increased requirements for collateral in the transaction of our
businesses, increased pressure on our liquidity and reduced access to additional
capital. Additional failures within our sector could heighten

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these reactions or cause additional negative impacts on our business which could
impair our ability to achieve our business plan.

OUR CREDIT RATINGS HAVE BEEN REDUCED BY MOODY'S, FITCH AND S&P TO
NON-INVESTMENT GRADE; FURTHER REDUCTIONS COULD INCREASE OUR COLLATERAL
REQUIREMENTS AND COULD MATERIALLY ADVERSELY AFFECT OUR FINANCIAL CONDITION.

As of April 25, 2003, our senior unsecured debt is rated "Caa2" with
Negative Outlook by Moody's. As of the same date, S&P has assigned a rating to
our senior unsecured debt of "B" on CreditWatch with negative implications, and
Fitch has assigned a rating to our senior unsecured debt of "B+" Rating Watch
Negative. While the foregoing indicates the ratings from the various rating
agencies, we note that these ratings are not a recommendation to buy, sell or
hold our securities and that each rating should be evaluated independently of
any other rating. There can be no assurance that a rating will remain in effect
for any given period of time or that a rating will not be lowered or withdrawn
entirely by a rating agency if, in its judgment, circumstances in the future so
warrant.

While we have removed ratings triggers from our various contracts, it is
possible that significant additional downgrades by the various credit ratings
agencies could materially negatively impact our business. For example,
significant additional downgrades could further increase requirements for
collateral in the transaction of our businesses, increase negative sentiment and
reactions from our customers, regulators, investors, lenders or other credit
rating agencies, increase pressure on our liquidity and reduce our ability to
raise capital. These reactions, and others, could impair our ability to achieve
our business plan.

OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT AND THE COST
OF COMPLIANCE WITH NEW AND EXISTING ENVIRONMENTAL LAWS COULD ADVERSELY AFFECT
OUR PROFITABILITY.

Our operations are subject to extensive federal, state, local and foreign
statutes, rules and regulations relating to environmental protection. To comply
with these legal requirements, we must spend significant sums on environmental
monitoring, pollution control equipment and emission fees. We may be exposed to
compliance risks from new projects, as well as from plants we have acquired.

Our failure to comply with environmental laws may result in the assessment
of penalties and fines against us by regulatory authorities. 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. As is true in many countries of the world, the
governments of the United States, the Philippines and Trinidad and Tobago have
proposed increased environmental regulation of many industrial activities,
including increased regulation of air quality, water quality and solid waste
management.

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. Most of our contracts
with customers do not permit us to recover capital costs incurred to comply with
new environmental regulations.

OUR BUSINESS IN THE UNITED STATES IS SUBJECT TO COMPLEX GOVERNMENT REGULATIONS
AND CHANGES IN THESE REGULATIONS OR IN THEIR IMPLEMENTATION MAY AFFECT THE
COSTS OF OPERATING OUR FACILITIES OR OUR ABILITY TO OPERATE OUR FACILITIES,
WHICH MAY NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS.

The majority of our generation operations in the United States are exempt
wholesale generators that sell electricity exclusively into the wholesale
market. Generally, our exempt wholesale generators are subject to regulation by
the FERC regarding rate matters and state public utility commissions regarding
non-rate matters. The majority of our generation from exempt wholesale
generators is sold at market prices under market rate authority exercised by the
FERC, although the FERC has the authority to impose "cost of service" rate
regulation or other market power mitigation measures if it determines that
market pricing is not in the public interest. A loss of our market-based rate
authority would prohibit electricity sales at

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market rates and would require all sales to be cost-based. A loss of our
market-based rate authority could severely impair our execution of our business
plan and could have a materially negative impact on our business.

To conduct our business, we must obtain licenses, permits and approvals for
our plants. We cannot provide assurance that we will be able to obtain and
comply with all necessary licenses, permits and approvals for our plants. If we
cannot comply with all applicable regulations, our business, results of
operations and financial condition could be adversely affected.

The United States Congress is considering legislation that would repeal
PURPA entirely, or at least eliminate the future obligation of utilities to
purchase power from qualifying facilities, and also repeal PUHCA. In the event
of a PUHCA repeal, competition from independent power generators and from
utilities with generation, transmission and distribution would likely increase.

Repeal of PURPA or PUHCA may or may not be part of comprehensive
legislation to restructure the electric utility industry, allow retail
competition and deregulate most electric rates. We cannot predict the effect of
this type of legislation, although we anticipate that any legislation would
result in increased competition. If we were unable to compete in an increasingly
competitive environment, our business and results of operation may suffer.

We cannot predict whether the federal government, state legislatures or
foreign governments will adopt legislation relating to the deregulation of the
energy industry. We cannot provide assurance that the introduction of new laws
or other future regulatory developments will not have a material adverse effect
on our business, results of operations or financial condition.

OUR FACILITIES MAY NOT OPERATE AS PLANNED, WHICH MAY LEAD TO POOR FINANCIAL
PERFORMANCE AND THE ACCELERATION OF THE AFFECTED PROJECT DEBT.

Our operation of power plants involves many risks, including the breakdown
or failure of generation equipment or other equipment or processes, labor
disputes, fuel interruption and operating performance below expected levels. In
addition, weather related incidents and other natural disasters can disrupt both
generation and transmission delivery systems. Operation of our power plants
below expected capacity levels may result in lost revenues or increased
expenses, including higher maintenance costs and penalties. In addition, we may
not be able to repay the project debt for an under-performing facility, which
could trigger default provisions in a project subsidiary's or project
affiliate's financing agreements and might allow the affected lenders to
accelerate that debt.

OUR OPERATIONS DEPEND SUBSTANTIALLY ON THE PERFORMANCE OF OUR SUBSIDIARIES AND
AFFILIATES, SOME OF WHICH WE DO NOT CONTROL AND SOME OF WHICH ARE SUBJECT TO
RESTRICTIONS AND TAXATION ON DIVIDENDS AND DISTRIBUTIONS. ALMOST ALL OF OUR
OPERATIONS ARE CONDUCTED THROUGH OUR SUBSIDIARIES AND AFFILIATES. AS A RESULT,
WE DEPEND ALMOST ENTIRELY UPON THEIR EARNINGS AND CASH FLOW.

Our Birchwood and PowerGen affiliates are not subject to our control of
management and policies to the same extent as our consolidated subsidiaries.
However, we do exercise significant influence over the operations of these
affiliates, and we account for these investments using the equity method of
accounting. These affiliates contributed approximately 1% of our income (loss)
from continuing operations in 2002.

The debt agreements of some of our subsidiaries and affiliates restrict
their ability to pay dividends, make distributions or otherwise transfer funds
to us prior to the payment of other obligations, including operating expenses,
debt service and reserves. Further, if we elect to receive distributions of
earnings from our foreign operations, we may incur United States taxes on such
amounts. Such amounts may also be subject to withholding taxes in some
countries. Tax on the repatriation of these earnings has already been provided
in the consolidated financial statement.

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OUR BUSINESS DEVELOPMENT ACTIVITIES MAY NOT BE SUCCESSFUL AND, AS SUCH,
PROJECTS MAY BE CANCELLED OR OTHERWISE MAY NOT COMMENCE OPERATION AS SCHEDULED
DESPITE THE EXPENDITURE OF SIGNIFICANT AMOUNTS OF CAPITAL.

Our business involves numerous risks relating to the acquisition,
development and construction of large power plants. During the past year, we
have terminated many of our previously planned development projects and deferred
other such projects. The termination of these projects has resulted in the
write-off of significant amounts of expenses, including termination expense
payments in connection with turbine acquisition agreements. Future terminations
of projects would most likely result in additional write-offs which could be
material.

Our future success in developing a particular project may be contingent
upon, among other things, negotiation of satisfactory engineering, construction,
fuel supply and power sales contracts, receipt of required governmental permits
and timely implementation and satisfactory completion of construction. We may be
unsuccessful in accomplishing any of these matters or in doing so on a timely
basis. Although we may attempt to minimize the financial risks in the
development of a project by securing a favorable power sales agreement,
obtaining all required governmental permits and approvals and arranging adequate
financing prior to the commencement of construction, the development of a power
project may require us to expend significant sums for preliminary engineering,
permitting, legal, equipment fabrication and other expenses before we can
determine whether a project is feasible, economically attractive or capable of
being financed.

Currently, we have power plants under development or construction. Our
completion of these facilities without delays or cost overruns is subject to
substantial risks, including changes in market prices; shortages and
inconsistent qualities of equipment, material and labor; work stoppages;
permitting and other regulatory matters; adverse weather conditions; unforeseen
engineering problems; environmental and geological conditions; unanticipated
cost increases; and our attention to other projects, any of which could give
rise to delays, cost overruns or the termination of the plant expansion,
construction or development.

If we were unable to complete the development of a facility, we would
generally not be able to recover our investment in the project. The process for
obtaining initial environmental, siting and other governmental permits and
approvals is complicated, expensive and lengthy, often taking more than one
year, and is subject to significant uncertainties. In addition, construction
delays and contractor performance shortfalls can result in the loss of revenues
and may, in turn, adversely affect our results of operations. The failure to
complete construction according to specifications can also result in
liabilities, reduced plant efficiency, higher operating costs and reduced
earnings.

THE IRS HAS COMPLETED ITS AUDIT OF MIRANT FOR ALL TAX YEARS THROUGH 1999. FOR
YEARS SUBSEQUENT TO 1999, THE IRS MAY RAISE ISSUES THAT COULD HAVE A MATERIAL
EFFECT ON OUR CASH FLOWS.

The IRS has completed its audit of Mirant for all tax years through 1999.
The tax liability resulting from this audit has already been reflected in the
financial statements for 2002. For years subsequent to 1999, the IRS may raise
issues that may have a material effect on our cash flows. Additionally, audits
of certain of our foreign operations are currently underway. Management believes
that it has adequately provided for any potential exposures related to such open
tax years.

OUR HISTORICAL FINANCIAL RESULTS FROM WHEN WE WERE A SUBSIDIARY OF SOUTHERN MAY
NOT BE REPRESENTATIVE OF OUR RESULTS AS A SEPARATE COMPANY.

The historical financial information included in this Form 10-K does not
necessarily reflect what our financial position, results of operations and cash
flows would have been had we been a separate, stand-alone entity during the
periods presented. Our costs and expenses reflect charges from Southern for
centralized corporate services and infrastructure costs, including engineering,
legal, accounting, information technology, investor relations and stockholder
services, insurance and risk management, tax, environmental, human resources and
payroll and external affairs, including marketing and public relations.

64

These allocations have been determined based on regulatory limitations and
other bases that we and Southern considered to be reasonable reflections of the
utilization of services provided to us for the benefits received by it. This
historical financial information is not necessarily indicative of what our
results of operations, financial position and cash flows will be in the future.
We experienced significant changes in our cost structure, funding and operations
as a result of our separation from Southern, including increased marketing
expenses related to building a company brand identity separate from Southern and
increased costs associated with being a publicly traded, stand-alone company.

TERRORIST ATTACKS, FUTURE WAR OR RISK OF WAR MAY ADVERSELY IMPACT OUR RESULTS
OF OPERATIONS, OUR ABILITY TO RAISE CAPITAL OR OUR FUTURE GROWTH.

Uncertainty surrounding terrorist acts, retaliatory military strikes or a
sustained military campaign may impact our operations in unpredictable ways,
including changes in insurance markets, disruptions of fuel supplies and
markets, particularly oil, and the possibility that infrastructure facilities,
including electric generation, transmission and distribution facilities, could
be direct targets of, or indirect casualties of, an act of terror. War or risk
of war may also have an adverse effect on the economy. The terrorist attacks on
September 11, 2001 and the changes in the insurance markets attributable to the
terrorist attacks have made it difficult for us to obtain certain types of
insurance coverage. As a result, we have chosen to self-insure some of our
plants and facilities for acts of terrorism. A lower level of economic activity
could also result in a decline in energy consumption, which could adversely
affect our revenues or restrict our future growth. Instability in the financial
markets as a result of terrorism or war could also affect our ability to raise
capital.

CONTINUATION OF CURRENT CAPITAL MARKET CONDITIONS COULD ADVERSELY AFFECT OUR
PROSPECTS.

Current conditions in our industry and in the capital markets have resulted
in the need for additional liquidity. Continuation of these conditions could
adversely affect our results of operations and growth prospects. We have taken
many actions to respond to these conditions, including issuing additional
equity, reducing our planned capital expenditures by deferring or canceling
certain construction and acquisition projects, reducing corporate overhead
expenses and undertaking the sale of several of our domestic and international
assets. There can be no assurance that conditions in the energy equity markets
will not continue to adversely affect our ability to efficiently conduct our
marketing operations and affect our results of operations.

WE ARE CURRENTLY INVOLVED IN SIGNIFICANT LITIGATION THAT, IF DECIDED ADVERSELY
TO US, COULD MATERIALLY ADVERSELY AFFECT OUR FINANCIAL CONDITION, CASH FLOWS
AND RESULTS OF OPERATIONS.

We are currently involved in a number of lawsuits concerning our activities
in the western power markets. These include a number of lawsuits by the
California Attorney General and ratepayers alleging, among other things, that
certain owners of electric generation facilities in California, and energy
marketing, engaged in various unlawful and fraudulent business acts that served
to manipulate wholesale markets and allegedly inflated wholesale electricity
prices in California. Additionally, a class action is pending against us and
four of our officers and former officers alleging, among other things, that
defendants made material misrepresentations and omissions to the investing
public regarding our business operations and future prospects during the period
from January 19, 2001 through May 6, 2002. In addition, we are involved in
various other litigation matters, all of which are described in more detail in
this Form 10-K. We intend to vigorously defend against those claims which we are
unable to settle, but the results of this litigation cannot be determined.
Adverse outcomes for us in this litigation could require significant
expenditures by us and could have a material adverse effect on our financial
condition, cash flows and results of operations.

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MIRANT MAY BE UNABLE TO RETAIN PERSONNEL CAPABLE OF SUCCESSFULLY EXECUTING OUR
BUSINESS PLAN GIVEN THE UNCERTAIN BUSINESS CLIMATE FOR OUR SECTOR AND OUR
COMPANY.

If our financial position does not improve or if our financial
restructuring is unsuccessful, there is a risk that personnel who are integral
to the success of our business model will leave the company, disrupting our
ability to successfully complete our short-and long-term goals.

To reduce this risk, we have in place an equity-based compensation plan and
have also put in place retention agreements with key employees. These measures
are designed to provide incentives to these key employees to remain with Mirant
throughout this critical period. There can be no assurance that these measures
will be effective.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Mirant is exposed to market risks associated with commodity prices,
interest rates and foreign currency exchange rates. The Company is also exposed
to credit risks.

COMMODITY PRICE RISK

HEDGING STRATEGIES

In connection with our power generating business in North America, we enter
into a variety of short and long-term agreements to acquire the fuel for
generating electricity, as well as to sell the electricity produced. A portion
of our fuel is also purchased in the spot market and a portion of the
electricity we produce is sold in the spot market. As a result, our financial
performance varies depending on changes in the prices of these commodities.

In the Philippines, our business is largely conducted based on fixed-price
long-term contracts denominated in United States dollars, under which the
purchaser is responsible for supplying the fuel, thereby mitigating our
exposures to both fluctuating commodity prices, as well as currency exchange
rates.

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 commodity prices in these businesses.

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 a "spark spread". 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 additional plant 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 move in the
same direction, which results in spark spreads widening or narrowing. We attempt
to maximize the spark spreads we realize and mitigate our exposure to price
volatility for fuel purchases and electricity sales in the spot market by
securing fuel under short and long-term fixed price contracts, selling
electricity under short and long-term fixed price contracts or utilizing
derivative instruments to hedge the cost of fuel or the sales price of the
electricity we produce.

In recent years, the power generation industry has seen increasing spark
spreads as the impact of steadily rising electricity demand reduced capacity
reserve margins. These increasing spark spreads affected the financial
performance of our generating assets in 2000 and 2001, particularly in
California. In 2002, spark spreads narrowed, and remained relatively low
compared to recent historical periods, which was the principal contributing
factor in the deterioration in the financial performance of our generating
businesses in the U.S. Excluding California, spark spreads in major metropolitan
areas in the U.S. have declined on average 10% in 2002 compared to 2001 and we
expect 2003 to be more similar to 2002 than 2001. For

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Northern California, where our physical assets are located, spark spreads
declined approximately 98% in 2002 as compared to 2001.

From time to time, the Company enters into derivative financial instruments
to manage the market risks associated with the electricity produced by our power
plants that are not covered by long-term, fixed price contracts. We enter into a
variety of contractual agreements, such as forward purchase and sale agreements,
and futures, swaps and option contracts. Futures and option contracts are traded
on a national exchange and swaps and forward contracts are traded 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.

All derivative instruments are recorded in the consolidated balance sheet
at fair value. Unless designated as cash flow hedges in accordance with SFAS No.
133, changes in the fair value of these derivative instruments are reflected in
earnings currently, as unrealized gains or losses on derivative instruments. For
derivative contracts that qualify and are designated as effective hedges of
future cash flows, the effective portion of changes in fair value is recorded in
other comprehensive income ("OCI") until the related hedged items affect
earnings. Any ineffective portion of the change in the fair value of the
contracts is reported in earnings immediately. Settlements of amounts receivable
or payable under all derivative instruments utilized to manage the price risk of
fuel purchased or energy sold are recorded as an adjustment of revenue or the
cost of fuel purchased, as applicable.

The Company subsequently determined that all derivative financial
instruments previously designated as cash flow hedges under SFAS No. 133 do not
qualify for hedge accounting. Accordingly, all realized and unrealized gains and
losses associated with all derivative transactions we entered into during the
periods presented are recognized in earnings in the period incurred.

PROPRIETARY TRADING ACTIVITIES

In addition to managing commodity price risk for our generation assets, we
also engage in proprietary trading primarily in regions where we own or operate
generating facilities or other physical assets. The Company assumes 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. Our
proprietary trading business can be volatile and subject to swings in earnings
and cash flow as commodity prices change. We manage our trading risk by
monitoring compliance with stated risk management policies, as well as
monitoring the effectiveness of our trading policies and strategies through our
Risk Oversight Committee.

These derivative financial instruments utilized in our proprietary trading
activities are recorded at their estimated market value in our consolidated
balance sheet as price risk management assets and liabilities. Changes in the
market value and settlements of these instruments are recorded as net trading
revenues.

At times, we use complex derivatives for which the fair value determination
is based on quantitative models. The quantitative models used may include
assumptions that are not readily verifiable in the market. Therefore, the
estimated value of these derivative instruments can be subject to unexpected
changes in value as additional market information becomes available or upon
settlement of the derivative instrument. To mitigate the risk that our
quantitative models are not fully capturing the essential details of the
derivative instruments, we have a Model Risk Oversight Committee to ensure that
the model risk is properly controlled through a process of systematic model
development, deployment and control. The Model Risk Oversight Committee sets the
guidelines for model development, testing, implementation process and
responsibilities.

VALUE AT RISK

We use a systematic approach to managing risks associated with our
derivative instruments. For those transactions that are not designated for cash
flow hedge accounting under SFAS No. 133, we use a Value-at-Risk (VaR) model to
summarize in dollar terms the market price risk we have and the potential loss
in

67

value of the Company's portfolio due to adverse market movement over a defined
time horizon within a specified confidence interval. For those transactions that
were designated for cash flow hedge accounting, we manage the market risks
associated with these derivative financial instruments in conjunction with the
underlying asset positions they are designed to hedge.

All of our positions, except those that are designated for cash flow hedge
accounting, are managed based on VaR limits that have been established by the
Board of Directors of Mirant. VaR is a statistical measure that is dependent
upon a number of assumptions and approximations. The Company uses recent
historical price volatility to estimate how the value of the portfolio will move
in the future. Given its reliance on historical data, VaR is effective in
estimating risk exposures in markets in which there are not sudden fundamental
changes or shifts in market conditions. If future pricing patterns are not
similar to historical patterns VaR could overstate or understate actual market
risks. As a result, even though the portfolio is within the established VaR
limit, actual gains or losses can exceed the reported VaR by a significant
amount.

We assume a 95% confidence interval and holding periods that vary by
commodity to calculate our VaR exposure. By using a 95% confidence interval, we
are accepting a 5% probability that the actual market risk in the portfolio is
greater than what is indicated by the VaR calculation. The holding period
assumption relates to our estimate of how long it would take to liquidate our
commodity positions (i.e., how long our positions are subjected to market price
risk before mitigating the position). To determine our holding period by
commodity we analyze the relative liquidity of different commodity positions
across different time horizons and locations by assuming different holding
periods. For very liquid commodity positions, such as natural gas for delivery
within one year, we use a five-day holding period, whereas for a less liquid
commodity position, such as physical coal, we employ a sixty business day
holding period. As a result, the VaR that we measure, monitor and report on a
daily basis is larger than what would be obtained using a one-day holding period
for all positions, commodities and commitments.

Another important assumption in VaR is the effect of multiple commodities
on risk. Our VaR calculation benefits from diversity; a variety of commodity
positions that individually present large potential risk, when combined, present
less risk. Our VaR calculation also takes into account very complex correlations
between commodities, regions and time to determine the portfolio VaR.

The VaR calculation methodology we use is a variance covariance statistical
modeling technique. Although VaR is a common technique utilized in the industry
to measure and manage market risk, there is no uniform industry method of
calculating VaR and, therefore, different assumptions or estimates could produce
significantly different VaR results for the same portfolio.

The average VaR, using various assumed holding periods and a 95% confidence
interval, was $34.3 million for the year ended December 31, 2002 and the VaR as
of December 31, 2002, was $28.9 million, as compared to $51.8 million and $37.9
million, respectively, in 2001. If we assumed VaR levels using a one-day holding
period for all positions and commitments in our portfolio based on a 95%
confidence interval, our portfolio VaR was $9.6 million at December 31, 2002 and
the average for the year ended December 31, 2002 was $11.2 million, compared to
$11.9 million and $17.9 million, respectively, in 2001. During the year ended
December 31, 2002, the actual daily loss on a fair value basis exceeded the
corresponding one-day VaR calculation three times, which falls within our 95%
confidence interval. During the second quarter of 2002, we implemented a new
trading system to administer our natural gas transactions. As a result, the
natural gas component of our total VaR calculation was held constant for a
period of approximately 45 days. We believe this was a reasonable estimate of
our average VaR calculations for 2002 and we would not have had additional
instances of exceeding our VaR limits if the natural gas portion of the total
VaR calculation would not have been held constant.

The VaR data presented does not include the derivative financial
instruments that were initially designated as hedges under SFAS No. 133. We have
subsequently determined that these transactions did not qualify for hedge
accounting treatment. It is not practical to recalculate the VaR data presented
above to include the effects of these derivative financial instruments.

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In addition, we subsequently determined that certain of the Company's power
purchase agreements are considered derivative financial instruments and subject
to fair value accounting under SFAS No. 133. Previously, the Company believed
the agreements qualified for the "normal purchase/normal sale" exception under
SFAS No. 133 and had accounted for the agreements as executory contracts using
the accrual method. These power purchase agreements have also not been included
in the VaR data presented since it is also not practical to recalculate the
data.

The following is a summary of the units, equivalent megawatt-hours,
duration and estimated fair value of the derivative financial instruments
previously designated as cash flow hedges or normal purchase and sale exemption
by commodity.

The following table represents the estimated cash flows of these financial
instruments and power purchase agreements (based on market prices at December
31, 2002) by tenor (in millions):

Credit Risk

Credit risk represents the loss that the Company would incur if a
counterparty fails to perform under its contractual obligations. We have
established controls to determine and monitor the creditworthiness of customers,
as well as the quality of pledged collateral. To reduce the Company's credit
exposure, the Company seeks to enter into payment master netting agreements with
counterparties that permit the Company to offset receivables and payables with
such counterparties. The Company attempts to further reduce credit risk with
certain counterparties by entering into agreements that enable the Company to
obtain collateral or to terminate or reset the terms of transactions after
specified time periods or upon the occurrence of credit-related events.

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 falls
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. The average credit quality is monitored on a regular basis and
reported to the Risk Oversight Committee on a periodic basis, together with
steps initiated to bring credit exposures to within the authorized range. The
weighted average credit

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rating of our customers, based on outstanding balances and management's internal
assessment, included in the net fair value of our price risk management assets
was BBB+ at December 31, 2002.

We also monitor the concentration of credit risk from various positions,
including contractual commitments. Credit concentration exists when a group of
customers have similar business characteristics, and/or are engaged in like
activities that would cause their ability to meet their contractual commitments
to be adversely affected, in a similar manner, by changes in the economy or
other market conditions. We monitor credit concentration risk on both an
individual basis and a group counterparty basis. The table below summarizes
credit exposures by rating category as of December 31, 2002 (in millions, except
percentages).

Collection Risk

Once we bill a customer for the commodity delivered or have financially
settled the credit risk, the Company is subject to collection risk. Collection
risk is similar to credit risk, collection risk is accounted for when we
establish our allowance for bad debts. We manage this risk using the same
techniques and processes used in credit risk discussed above. As of December 31,
2002, we had $295 million of bad debt reserves related to amounts not deemed
collectible. Approximately $237 million of this reserve relates to two
customers -- CAISO and PX, which is discussed more fully in Note 2 to our
consolidated financial statements.

Interest Rate Risk

Our policy is to manage interest expense using a combination of fixed- and
variable-rate debt. From time to time, we also enter into interest rate swaps in
which we agree to exchange, at specified intervals, the difference between
fixed- and variable-interest amounts calculated by reference to agreed-upon
notional principal amounts. These interest rate swaps are designated to hedge
the variable interest rate risk in the underlying debt obligations. For swaps
that qualify as cash flow hedges, changes in the fair value of the swaps are
deferred in OCI and are reclassified from OCI as an adjustment of interest
expense over the term of the swaps. Gains and losses resulting from the
termination of qualifying hedges prior to their stated maturities are recognized
as interest expense ratably over the remaining term of the hedged debt
instruments.

To assess our exposure to changes in interest rates, we determine the
amount of our variable rate debt that is not hedged by an interest rate swap and
then adjust this number for the amount of cash and investments having an
offsetting exposure. If we sustained a 100 basis point change in interest rates
for all variable rate debt and cash in all currencies, the change would affect
earnings by approximately $5 million per year, based on variable rate balances
outstanding at December 31, 2002.

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. We do not have any foreign exchange contracts
outstanding at December 31, 2002 that are designated as hedges of our
investments in foreign countries. We have also utilized currency swaps

70

to hedge the effect of exchange rate fluctuations on foreign currency
denominated debt. In 2002, we sold our investments where this type of hedging
was applicable. Occasionally, we use currency forwards to offset the effect of
exchange rate fluctuations on forecasted transactions denominated in a foreign
currency. We also use forward contracts to hedge a portion of our Canadian
dollar denominated storage, transport and commodity transactions. When the gains
and losses are accounted for using mark-to-market through income, we do not
apply hedge accounting for the related currency forwards.

We measure currency risk associated with net monetary investments
denominated in foreign currencies using sensitivity analysis. At December 31,
2002, the carrying value of these investments would change by $3 million if
applicable foreign currencies changed by 10% against the United States dollar.
This figure does not include changes in income related to United States dollar
denominated intercompany loans to foreign subsidiaries having a different
functional currency.

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.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

Not applicable.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by Item 10 of Form 10-K relating to directors who
are nominees for election as directors at Mirant's Annual Meeting of
Shareholders to be held on May 22, 2003 is set forth in Mirant's Proxy Statement
and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information regarding executive compensation is set forth in Mirant's
Proxy Statement and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information regarding executive compensation is set forth in Mirant's
Proxy Statement and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information regarding executive compensation is set forth in Mirant's
Proxy Statement and is incorporated herein by reference.

ITEM 14. CONTROLS AND PROCEDURES

During an interim review for the second quarter of 2002, the Company's
independent auditors assessed the internal controls of the Company's North
American energy marketing and risk management operations and advised the
Company's Audit Committee that certain deficiencies identified in this review
collectively constituted a material control weakness. The Company assigned the
highest priority to the short and long-term correction of the internal control
deficiencies identified and has made significant progress. As of the date of
this report, we believe we have corrected deficiencies to internal controls in
place and no longer have a material internal control weakness. A summary of the
main control issues identified and the Company's resolution is detailed below.

71

RESOLUTION OF MATERIAL CONTROL WEAKNESS DEFICIENCY

As part of the internal control assessment completed by its independent
auditor, the Company received detailed process improvement recommendations
during October 2002 which addressed the internal control deficiencies in
existence at June 30, 2002, the most significant of which relate to the
Company's systems and processes and include:

(i) Inadequate analysis, documentation and internal communication of
natural gas actualization adjustments;

(ii) Inadequate reconciliation of the Company's risk report and
general ledger;

(iii) Inadequate systems integration and data reconciliation; and

(iv) Untimely resolution of balance sheet account reconciliation
discrepancies.

As noted, the Company assigned the highest priority to addressing these
deficiencies and developed a detailed action plan, including both short and
long-term corrective measures. Initially, intensive manual processes were
implemented to ensure the accuracy of the Company's financial statements.
Additionally, the Company has implemented other short-term steps during the
fourth quarter of 2002 in order to improve the controls detailed above by
December 31, 2002. The Company believes that the corrective actions implemented
prior to December 31, 2002 and additional manual procedures instituted are
sufficient to ensure the accuracy of the financial statements as of and for the
period ended December 31, 2002.

Subsequent to December 31, 2002, the Company has continued to implement
both short and long-term solutions to resolve the control deficiencies
identified. Specifically, the risk report to general ledger reconciliation and
actualization issues were resolved by enabling the mid and back office data to
reconcile information on an individual transaction basis, identifying and
resolving all variances between the risk report and general ledger, and
developing action plans to eliminate any systemic differences. The systems
integration issues noted were addressed through the continued implementation of
functionality included in the Company's new information technology system for
natural gas trading and marketing activities ("ENDUR"), supported by increased
controls and reconciliations around manual interfaces in the interim. The issue
concerning untimely resolution of balance sheet reconciliation discrepancies was
addressed by instituting standard policies, procedures and controls across all
North American sites.

The Company continues to focus on certain longer-term initiatives, many of
which are tied to systems implementations and integration projects, and expects
these to be completed throughout the second and third quarters of 2003. Until
these system solutions are in place and operating effectively, the additional
manual processes and management oversight previously implemented will remain in
place. Management has discussed its action plan with the Audit Committee and its
independent auditors and will continue to provide periodic updates on progress
made. As of the date of this filing, the Company is satisfied that the manual
processes and systems of internal controls are now adequate. Like other
companies, however, management cannot provide absolute assurance that material
control weaknesses will not be identified from time to time or that any such
weaknesses would not materially affect our financial results.

EVALUATION OF DISCLOSURE CONTROLS

Within the 90-day period immediately preceding the filing of this report,
an evaluation was carried out under the supervision and with the participation
of the Company's management, including its Chief Executive Officer and its Chief
Financial Officer, of the effectiveness of the design and operation of its
disclosure controls and procedures (as defined in Rule 13a-14(c) and 15d-14(c)
under the Exchange Act). Based upon that evaluation, the Chief Executive Officer
and Chief Financial Officer concluded that there were no significant
deficiencies or material weaknesses in the Company's disclosure controls and
procedures and that the design and operation of these disclosure controls and
procedures were effective.

72

CHANGES IN INFORMATION SYSTEMS

Effective April 1, 2002, the Company implemented ENDUR, a new risk
management system for its gas trading and marketing activities in North America.
Because of ENDUR's improved capabilities over the legacy systems, management
views the implementation of ENDUR as a significant change in internal controls.
In addition, the Company recently modified its power trading and marketing
information technology system to improve reporting of realized and unrealized
income associated with power transactions and expects to implement the ENDUR
system for power by mid-year 2003.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)1. Financial Statements

See "Index to Financial Statements" set forth on page F-1.

2. Financial Statement schedules
None

3. Exhibit Index

- ---------------

* Asterisk indicates exhibits incorporated by reference.

(b) Reports on Form 8-K

During the quarter ended December 31, 2002, the Company did not file a
Current Report on Form 8-K.

76

INDEX TO FINANCIAL STATEMENTS

MIRANT CORPORATION AND SUBSIDIARIES

F-1

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Shareholders
Mirant Corporation:

We have audited the consolidated balance sheets of Mirant Corporation and
subsidiaries (the "Company") as of December 31, 2002 and 2001, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the years in the three-year period ended December 31, 2002. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mirant
Corporation and subsidiaries as of December 31, 2002 and 2001, and the results
of their operations and their cash flows for each of the years in the three-year
period ended December 31, 2002, in conformity with accounting principles
generally accepted in the United States of America.

The Company has not presented the selected quarterly financial data
specified by Item 302(a) of Regulation S-K, that the Securities and Exchange
Commission requires as supplementary information to the basic financial
statements.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As more fully described in Note 1 to
the accompanying consolidated financial statements, the Company has a loss from
continuing operations of $2.4 billion for the year ended December 31, 2002 and
has sold significant assets during 2002 in order to generate additional
liquidity. Furthermore, the Company has $1.8 billion in scheduled debt
maturities during 2003, and does not project that it will have sufficient
liquidity to repay such debt maturities as they come due. Therefore, the Company
anticipates that it will be required to refinance significant debt obligations
during 2003 in order to maintain continuing operations. All of these conditions
raise substantial doubt about the Company's ability to continue as a going
concern. Management's plans with regard to these matters are also described in
Note 1. The financial statements do not include any adjustments that might
result from the outcome of this uncertainty.

As discussed in Note 1 to the accompanying consolidated financial
statements, the Company changed its method of accounting for goodwill and other
intangible assets, and the impairment of long-lived assets and discontinued
operations in 2002. Additionally in 2002, the Company changed the method of
reporting gains and losses associated with energy trading contracts from the
gross to the net method and retroactively reclassified the consolidated
statements of operations for 2001 and 2000. The Company changed its method of
accounting for derivative instruments and hedging activities in 2001.

As discussed in Note 3 to the accompanying consolidated financial
statements, the Company has restated the consolidated balance sheet as of
December 31, 2001, and the related consolidated statements of operations,
stockholders' equity, and cash flows for the years ended December 31, 2001 and
2000, which consolidated financial statements were previously audited by other
independent auditors who have ceased operations.

/s/ KPMG LLP

Atlanta, Georgia
April 29, 2003

F-2

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

The accompanying notes are an integral part of these consolidated financial
statements.
F-3

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001

The accompanying notes are an integral part of these consolidated statements.
F-4

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

The accompanying notes are an integral part of these consolidated statements.
F-5

MIRANT CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

The accompanying notes are an integral part of these consolidated statements.
F-6

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, 2001 AND 2000

1. DESCRIPTION OF BUSINESS AND ORGANIZATION

Overview. 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").

Mirant's revenues are generated through the production of electricity in
the United States, the Philippines and the Caribbean. In addition, in North
America Mirant trades and markets commodities to optimize the financial
performance of its power generation business and to take proprietary commodity
trading positions, primarily in regions where it owns generating facilities or
other physical assets. In the Philippines, over 80% of the Company's generation
output is sold under long-term contracts. The Company's operations in the
Caribbean include fully integrated electric utilities, which generate power sold
to residential, commercial and industrial customers. As of December 31, 2002,
Mirant owned or controlled through lease or operating agreements more than
21,800 MW of electric generating capacity. In North America, the Company also
had rights to approximately 3.1 billion cubic feet per day of natural gas
production, more than 2.1 billion cubic feet per day of natural gas
transportation and approximately 13.4 billion cubic feet of natural gas storage
as of December 31, 2002.

Mirant manages its business through two principal operating segments. The
Company's North America segment consists of power generation and commodity
trading operations managed as an integrated business. The International segment
includes power generation businesses in the Philippines, Curacao and Trinidad,
Guam and integrated utilities in the Bahamas and Jamaica. In 2002, Mirant closed
its European trading operations and sold its distribution and generation assets
in Europe and Asia. Prior to their sale, the operations of these assets were
previously reflected in the International segment.

Consolidated subsidiaries and equity affiliates, in which Mirant has less
than 100% ownership at December 31, 2002, are as follows:

F-7

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Restructuring. The financial statements have been prepared on a going
concern basis, which contemplates the realization of assets and the satisfaction
of liabilities in the normal course of business. As shown in the consolidated
financial statements, the Company has a loss from continuing operations of $2.3
billion for the year ended December 31, 2002 and has sold assets during 2002 in
order to generate additional liquidity. Furthermore, the Company has $1.7
billion in scheduled debt maturities during 2003, and does not project that it
will have sufficient liquidity to repay such debt maturities as they come due.
Therefore, the Company anticipates that it will be required to restructure
significant debt obligations during 2003 in order to maintain continuing
operations. All of these conditions raise substantial doubt about the Company's
ability to continue as a going concern.

Management recognizes that the Company's continuation as a going concern is
dependent upon its ability to restructure its upcoming debt obligations. The
Company is working on a restructuring plan pursuant to which it will ask certain
of its creditors to defer repayments of principal. Those creditors include
holders of approximately $4.5 billion of bank facilities (including its turbine
facility and prepaid gas transaction) and capital markets debt of Mirant
Corporation and approximately $800 million of bank and capital markets debt of
Mirant Americas Generation, LLC, a subsidiary. The purpose of the restructuring
is to enable the Company to repay in full all of its obligations with interest,
including unsecured long term indebtedness that is not extended. To reassure
creditors who will be asked to extend maturities, all of whom are currently
unsecured, the Company intends to offer security interests in substantially all
of its and its subsidiaries unencumbered assets as well as terms more favorable
to the creditors.

The restructuring of the debt of the Company is part of a broader effort to
refocus the Company and restructure the business of the Company. Restructuring
activities thus far include:

- The sale of our investments in the United Kingdom (WPD), Germany (Bewag),
China and others. The proceeds from the sale of Bewag, Shajiao C and
others, were used to reduce debt by $847 million. The net gains from the
sale of investments decreased the 2002 net loss by $329 million, however,
future earnings will be adversely impacted by the loss of the related
income from these investments.

- The cancellation or sale of 70 turbines and power islands in order to
reduce future expenditures. These actions increased the 2002 net loss by
$586 million, but will reduce future cash expenditures by approximately
$1.9 billion between 2003 and 2005. As of April 25, 2003, approximately
$160 million in additional cash will be required to cancel or settle
remaining obligations.

F-8

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- The reduction of the workforce by approximately 655. This action resulted
in a $50 million severance charge, but will result in significant payroll
savings. The Company expects to continue to reduce its workforce as it
exits additional activities.

- The purchase of $83 million of TIERS Fixed Rate Trust Certificates for
approximately $51 million. TIERS Certificates represent beneficial
interests in approximately $400 million aggregate principal amount of our
2.5% Convertible Senior Debentures, which are held as the underlying
trust assets of a trust established on June 18, 2001 by Structured
Products Corp., an indirect wholly-owned subsidiary and affiliate of
Salomon Smith Barney Inc. The Company purchased the TIERS Certificates
pursuant to an authorization by our board of directors to repurchase up
to $500 million of the Company's debt securities as liquidity permits.

Mirant Corporation sought, and received, a waiver from the required lenders
under its bank facilities for any potential breaches with respect to
non-compliance with the recourse debt to recourse capital financial covenant,
any potential breaches that could arise relating to our historical financial
reporting requirements or representations or the inclusion in its independent
auditors' report on the Company's annual financial statements of an explanatory
paragraph stating that the Company has not presented the selected quarterly
financial data specified by Item 302(a) of Regulation S-K, that the Securities
and Exchange Commission requires as supplementary information to the basic
financial statements. The lenders have agreed to such waiver through May 29,
2003, subject to certain terms and conditions, including limiting future use of
the bank facilities to issuances of letters of credit and limiting capital
expenditures and other material payments. The terms of the waiver provide for an
additional extension, to July 14, 2003, with the prior written consent of
lenders representing a majority of the committed amount under each of the
facilities. Upon expiration or termination of the waiver, the lenders under the
respective bank facilities would be able to restrict the issuance of additional
letters of credit and/or declare an event of default and, after the respective
cure or grace period, accelerate the indebtedness under such bank facilities. An
acceleration of indebtedness under the Mirant Corporation bank facilities would
cross accelerate approximately $910 million of Mirant Corporation capital
markets and other indebtedness.

If the Company is successful in its restructuring efforts, it expects to
meet its liquidity needs going forward through a combination of cash from
operations, amounts available under its revolving credit facilities, existing
cash balances and proceeds from asset sales. In addition, the anticipated
contractions in the level of our trading and marketing activities are expected
to reduce the need for collateral provided by letters of credit and cash
deposits. There can be no assurance that the Company will be able to restructure
its indebtedness or that its liquidity and capital resources will be sufficient
to maintain its current operations. If the Company is not successful in its
restructuring efforts and/or if a substantial portion of its indebtedness is
accelerated, it would likely be required to seek bankruptcy court or other
protection from its creditors. These financial statements do not include any
adjustments relating to the recoverability and classification of asset carrying
amounts or the amount and classification of liabilities that might result should
the Company be unable to continue as a going concern.

2. ACCOUNTING AND REPORTING POLICIES

Basis of Presentation. The consolidated financial statements of Mirant are
presented in United States dollars in conformity with accounting principles
generally accepted in the United States. The financial statements include the
accounts of Mirant and its wholly-owned as well as controlled majority-owned
subsidiaries 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 companies in which Mirant exercises significant
influence over operating and financial

F-9

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

policies are accounted for using the equity method. Majority or jointly owned
affiliates, which Mirant does not control, are also accounted for using the
equity method of accounting.

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

Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.

New Accounting Standards. In June 2001, the FASB issued Statement of
Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses financial accounting and
reporting obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. SFAS No. 143 is effective for
the Company's 2003 fiscal year. Mirant adopted this statement on January 1,
2003. The impact of the adoption of SFAS No. 143 is not expected to have a
material effect on the Company's financial position, results of operations or
cash flows.

In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires companies to
recognize certain costs associated with exit or disposal activities when they
are incurred rather than at the date of a commitment to an exit or disposal
plan. Examples of costs covered by the standard include lease termination costs
and certain employee severance costs that are associated with a restructuring,
discontinued operation, plant closing, or other exit or disposal activities. The
provisions of SFAS No. 146 are effective for exit or disposal activities that
are initiated after December 31, 2002.

The Company had previously reported the gross amounts of revenues and
expenses relating to its energy trading activities. However, in accordance with
the consensus reached in Emerging Issues Task Force ("EITF") Issue 02-03,
"Issues Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," the Company is required to present such revenues and
expenses net. Accordingly, the Company has reclassified its previously reported
revenues and expenses relating to its energy trading activities in the
accompanying consolidated statements of operations for all periods presented.
These reclassifications reduced revenues and cost of fuel, electricity and other
products by corresponding amounts but did not impact Mirant's gross margin or
net income (loss).

See Note 3 for the financial statement effects of this accounting change.

In October 2002, the Task Force also reached a consensus in EITF Issue
02-03 to rescind EITF Issue 98-10. Accordingly, energy-related contracts that
are not accounted for pursuant to 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 at fair value. Energy-related contracts that meet the definition of a
derivative pursuant to SFAS No. 133 will continue to be carried at fair value.
In addition, the Task Force observed that accounting for energy-related
inventory at fair value by analogy to the consensus in EITF Issue 98-10 was no
longer appropriate and that inventory should no longer be recognized at fair
value. The effect of implementing the EITF consensus with respect to ceasing use
of the fair value method of accounting for non-derivative energy trading
contracts is currently being assessed by management and will be recorded as the
cumulative effect of a change in accounting principle during the first quarter
of 2003.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). This interpretation requires
that certain disclosures are to be made by a guarantor in its interim and annual

F-10

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

financial statements about its obligations under certain guarantees that it has
issued. It also requires a guarantor to recognize a liability for the fair value
of the obligation undertaken in issuing certain guarantees. The initial
recognition and initial measurement provisions of this interpretation are
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements of this interpretation are
effective for financial statements of interim or annual periods after December
15, 2002. The disclosures required by FIN 45 are included in Note 16.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an interpretation of ARB No. 51" ("FIN 46"). FIN 46
addresses the consolidation by business enterprises of variable interest
entities, as defined in the interpretation. FIN 46 expands existing accounting
guidance regarding when a company should include in its financial statements the
assets, liabilities and activities of another entity. The consolidation
requirements of FIN 46 apply immediately to variable interest entities created
after January 31, 2003. The consolidation requirements apply to variable
interest entities created before February 1, 2003 in the first fiscal year or
interim period beginning after June 15, 2003. Certain of the disclosure
requirements apply to all financial statements issued after January 31, 2003.
The application of this Interpretation is not expected to have a material effect
on the Company's financial position, results of operations or cash flows.

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.

The Company may choose not to operate certain generating plants, but
purchase electric power to meet its contractual energy sales commitments. The
resale of electric power purchased is recorded as revenue and the cost of power
purchased is recorded as operating expense.

Commodity Trading Activities. Commodity trading activities are accounted
for under the mark-to-market method. Under the mark-to-market method of
accounting, energy trading contracts are recorded at fair value in the
accompanying consolidated balance sheets. The determination of fair value
considers various factors, including closing exchange or OTC market price
quotations, time value and volatility factors underlying options and contractual
commitments, price activity for equivalent or synthetic instruments in markets
located in different time zones and counterparty credit quality. The net
realized gain or loss and net unrealized gain or loss resulting from the change
in the fair value of these energy trading contracts are reported as "net trading
revenues." Prior to the effective date of EITF 02-03, all energy trading
contracts including transportation and storage contracts and inventory held for
trading purposes were marked-to-market under the provisions of EITF 98-10.

Subsequent to the rescission of EITF 98-10 the mark-to-market method is
used to account for energy trading contracts entered into after October 25, 2002
that meet the criteria of derivative financial instruments pursuant to SFAS No.
133. These criteria require these contracts to be related to future periods, to
contain one or more underlyings and one or more notional amounts, require little
or no initial net investment and to have terms that require or permit net
settlement of the contract in cash or its equivalent. As these transactions may
be settled in cash, the fair value of the assets and liabilities associated with
these transactions is reported at estimated settlement value based on current
prices and rates as of each balance sheet date. The net unrealized gains or
losses resulting from the revaluation of these contracts during the period are
recognized currently in net trading revenues in the accompanying consolidated
statements of operations. Assets and liabilities associated with energy trading
activities are

F-11

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

reflected in our consolidated balance sheet as price risk management assets and
liabilities, classified as short-term (i.e., current) or long-term based on the
term, or tenor, of the contracts.

The fair values of swap agreements, swap options, caps and floors and
forward contracts in a net receivable position, as well as options held, are
reported as price risk management assets in the accompanying consolidated
balance sheets. Similarly, financial instruments and contractual commitments in
a net payable position, as well as options written, are reported as price risk
management liabilities in the accompanying consolidated balance sheets. The
price risk management assets and liabilities associated with financial
instruments and contractual commitments are reported net by counterparty,
provided a legally enforceable master netting agreement exists, and are netted
across products when such provisions are stated in the master netting agreement.

Derivative Financial Instruments. SFAS No. 133 requires that derivative
financial instruments be recorded in the balance sheet at fair value as either
assets or liabilities, and that changes in fair value be 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 for which hedge accounting criteria are met are reflected
within other current and non-current assets and liabilities in the accompanying
consolidated balance sheets. 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. Many of Mirant's power sales and
fuel supply agreements that otherwise would be required to follow derivative
accounting qualify as normal purchases and normal sales under SFAS No. 133 and
are therefore exempt from fair value accounting treatment. The majority of the
Company's commodity derivative financial instruments do not qualify for hedge
accounting and therefore changes in such instruments' fair value are recognized
currently in earnings.

Concentration of Revenues and Credit Risk. Revenues earned from California
Department of Water Resources ("DWR") approximated 37% of Mirant's total
revenues for the year ended December 31, 2001. During 2002 and 2000, revenue
earned from a single customer did not exceed 10% of Mirant's total revenues. As
of December 31, 2002, no customer represented more than 10% of Mirant's total
credit exposure.

Interest Rate and Foreign Currency Financial Instruments. Mirant's policy
is to manage interest expense using a combination of fixed- and variable-rate
debt. The Company also enters into interest rate swaps in which it agrees to
exchange, at specified intervals, the difference between fixed- and variable-
interest amounts calculated by reference to agreed-upon notional principal
amounts. These swaps are designated to hedge the interest rate exposure arising
from variable rate debt obligations. For qualifying hedges, changes in the fair
value of the swaps are deferred in OCI, net of tax, and are 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 are 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 are recognized currently in earnings.

From time-to-time, Mirant has used currency swaps and currency forwards to
hedge its net investments in certain foreign subsidiaries. Unrealized gains or
losses on these derivatives are designated as hedges of net investments and are
offsets against the unrealized foreign currency translation gains or losses
recorded in OCI relating to these investments. The Company does not have any
foreign exchange contracts outstanding at December 31, 2002 that are designated
as hedges of its investments in foreign
F-12

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

countries. Occasionally, the Company will use currency forwards to manage the
effect of exchange rate fluctuations on forecasted transactions denominated in a
foreign currency. In addition, Mirant has also utilized currency swaps to hedge
the effect of exchange rate fluctuations on foreign currency denominated debt
and the interest rate exposure.

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 funds on deposit and other
noncurrent assets in the accompanying consolidated balance sheets and amounted
to $236 million and $242 million, respectively, at December 31, 2002 and 2001.
Cash is restricted primarily due to debt service reserve requirements under
Mirant's project financing in the Philippines and deposits to support letters of
credit and deposits held by commodity trading counterparts.

Receivables. Receivables, less provision for uncollectibles of $191
million and $191 million for 2002 and 2001, respectively, consisted of the
following at December 31, 2002 and 2001 (in millions).

During 2002, Mirant received $29 million as final payment related to
receivables that were acquired in conjunction with the acquisition of
Consolidated Electric Power Asia Limited. During 2001, Mirant received $10
million related to these receivables. No amounts were received in 2000. At the
time of the acquisition, Mirant did not record any value for the receivables due
to the uncertain credit standing of the party from whom the receivables were
due. Consequently, all amounts received have been recorded as income in the
accompanying consolidated statements of operations.

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.

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.

Inventory. Inventory consists primarily of natural gas, fuel, oil, coal
and purchased emission certificates. Commodity trading inventory acquired prior
to October 26, 2002 is stated at fair value. All other inventories, including
commodity trading inventory acquired after October 25, 2002, is stated at the
lower of cost, computed using an average cost basis, or market value.

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

F-13

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 provided by 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, in
accordance with SFAS No. 34, "Capitalization of Interest Cost," as amended. 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, 2002, 2001 and 2000, the
Company incurred the following interest costs (in millions):

As part of Mirant's operational restructuring plan announced in March of
2002 (the "March 2002 Plan"), substantially all construction on several projects
has been suspended and Mirant no longer capitalizes interest on these projects.

Leasehold Interests. Certain of Mirant's Asian 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 local
country 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 term of the agreement.

Goodwill and Intangible Assets. Goodwill represents the excess of costs
over fair value of assets of businesses acquired. The Company adopted the
provisions of SFAS No. 142, "Goodwill and Other Intangible Assets" ("SFAS No.
142") as of January 1, 2002. Under SFAS No. 142, goodwill and intangible assets
acquired in a purchase business combination and determined to have an indefinite
useful life are not amortized, but instead tested for impairment at least
annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 also
requires that intangible assets with estimable useful lives be amortized over
their respective useful lives to their estimated residual values, and reviewed
for impairment in accordance with SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" ("SFAS No. 144").

SFAS No. 142 requires that a goodwill impairment evaluation be performed
upon adoption of the standard, annually, and between annual tests upon the
occurrence of certain events. Upon adoption of SFAS No. 142, the Company was
required to identify its reporting units and determine the carrying value of
each reporting unit by assigning the assets and liabilities, including existing
goodwill and intangible

F-14

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

assets, to those reporting units as of January 1, 2002. In performing the
impairment evaluation, the Company estimates the fair value of each reporting
unit and compares it to the carrying amount of that reporting unit. To the
extent the carrying amount of a reporting unit exceeds the fair value of that
reporting unit, the Company is required to perform the second step of the
impairment test. In this step, the Company compares the implied fair value of
the reporting unit goodwill with the carrying amount of the reporting unit
goodwill. The implied fair value of goodwill is determined by allocating the
fair value of the reporting unit to all of the assets (recognized and
unrecognized) and liabilities of the reporting unit in a manner similar to a
purchase price allocation, in accordance with SFAS No. 141, "Business
Combinations" ("SFAS No. 141"). The residual fair value after this allocation is
the implied fair value of the reporting unit goodwill. Upon the adoption of SFAS
No. 142, the fair value of each of the Company's reporting units exceeded the
carrying amount of the reporting unit in the transition test and no impairment
charge was recognized. See Note 8 for a discussion of the 2002 annual impairment
test.

Prior to the adoption of SFAS No. 142, goodwill was amortized on a
straight-line basis over the expected periods to be benefited, generally 30 to
40 years, and assessed for recoverability by determining whether the goodwill
balance could be recovered through projected undiscounted future operating cash
flows. The amount of goodwill impairment, if any, was measured based on
projected discounted future operating cash flows.

Mirant recognizes specifically identifiable intangible assets when specific
rights or contracts are acquired. Intangible assets are amortized on a
straight-line basis over the lesser of their contractual or estimated useful
lives, ranging up to 40 years. The cost of certain rights acquired, such as
operating permits, are included in property, plant and equipment in the
accompanying consolidated balance sheets as they are considered an integral part
of the tangible 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, in
accordance with SFAS No. 144. Recoverability of assets to be held and used is
measured by a comparison of the carrying amount of an asset to the estimated
undiscounted future cash flows expected to be generated by the asset. If the
carrying amount of an asset exceeds its estimated discounted future cash flows,
an impairment charge is recognized by 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 balance sheet.

Prior to the adoption of SFAS No. 144, the Company accounted for the
impairment of long-lived assets in accordance with SFAS No. 121, "Accounting for
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."

Stock-Based Compensation. Mirant accounts for its stock-based employee
compensation plans under the intrinsic-value method of accounting prescribed by
APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. 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. SFAS No. 123, "Accounting for
Stock-Based Compensation" established accounting and disclosure requirements
using a fair-value-based method of accounting for stock-based employee
compensation plans. As allowed by SFAS No. 123, the Company has elected to
continue to apply the intrinsic-value-based method of accounting described
above, and has adopted only the disclosure requirements of SFAS No. 123. The
following table illustrates the effect on net income (loss) if the fair-

F-15

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

value-based method had been applied to all outstanding and unvested awards in
each period (in millions, except per share data). See also Note 12.

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 United States 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 United States dollar,
transactions denominated in currencies other than the United States dollar are
translated into United States dollars. Gains or (losses) on such transactions
are recognized in earnings and amounted to $2 million, $(7) million and $2
million in 2002, 2001 and 2000, respectively.

3. RESTATEMENT AND RECLASSIFICATIONS

Prior to filing its second quarter 2002 Form 10-Q, the Company identified a
number of accounting errors in its previously issued financial statements due to
a material weakness in its accounting controls. As a result, we completed a
comprehensive analysis of our financial statements and accounting records and
identified a number of additional errors.

The Company's 2001 and 2000 consolidated financial statements have been
restated to correct certain accounting errors made in preparing those financial
statements. In addition, the Company has reclassified certain amounts in the
2001 and 2000 consolidated financial statements to reflect the adoption of new
accounting standards. The reclassifications include the net presentation of
revenues and expenses associated with energy trading activities required by EITF
Issue 02-03, and the presentation of discontinued operations discussed below.

DISCONTINUED OPERATIONS

The financial statements for prior years have been restated to report the
revenues and expenses of the components of the Company that were disposed of
separately as discontinued operations. Income (loss) from discontinued
operations for 2002, 2001 and 2000 includes the following components of the
Company that have been disposed of: Mirant Americas Energy Capital, LP ("Mirant
Americas Energy Capital"), Mirant Americas Production Company in Louisiana, MAP
Fuels Limited in Queensland, Australia, the State Line generating facility in
Indiana and the Neenah generating facility in Wisconsin.
F-16

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Income (loss) from discontinued operations for 2001 and 2000 also includes the
operations of SE Finance Capital Corporation ("SE Finance"), which was
distributed to Southern on March 5, 2001, as part of Mirant's spin-off from
Southern. The Company recorded impairment charges of approximately $146 million
in 2002 relating to certain of these discontinued operations, which are included
in the operating expenses caption below. See Note 6 for a discussion of these
dispositions.

A summary of the operating results for these discontinued operations for
the years ended December 31, 2002, 2001 and 2000 follows (in millions):

The table below presents the components of the balance sheet accounts
classified as current assets and liabilities held for sale as of December 31,
2002 and 2001 (in millions):

RECLASSIFICATIONS

The Company had previously reported the gross amounts of revenues and
expenses relating to its energy trading activities. However, in accordance with
the consensus reached in EITF Issue 02-03, the Company now presents such
revenues and expenses on a net basis. The Company has reclassified its
previously reported revenues and expenses relating to its energy trading
activities in the accompanying consolidated statements of operations for all
periods presented to conform to this new method of

F-17

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

presentation. These reclassifications reduced revenues and cost of fuel,
electricity and other products by corresponding amounts but did not impact
Mirant's gross margin or net income (loss). See Note 2.

RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

In addition to the changes to the Company's previously issued financial
statements required by the adoption of SFAS No. 144 and EITF Issue 02-03,
management has identified certain errors which necessitated a restatement of the
Company's 2001 and 2000 consolidated financial statements. The following tables
and discussion highlight the effects of the restatement adjustments and
reclassifications on the previously reported consolidated statements of
operations for 2001 and 2000 (in millions).

CONSOLIDATED STATEMENTS OF OPERATIONS

F-18

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Operating revenue for 2001 was adjusted by $4 million primarily as a result
of the following restatement adjustments:

- the reduction by $245 million for certain power purchase agreements
previously accounted for as executory contracts that are now reflected at
fair value under SFAS No. 133;

- the reduction for $39 million of mark-to-market gains on energy loans
held by Mirant's Energy Capital business, which were previously accounted
for at fair value;

- an increase of $132 million to record a full requirements contract in
Texas at fair value; and

- an increase of $196 million to reflect the fair value of certain
commodity financial instruments previously accounted for as cash flow
hedges under SFAS No. 133.

Cost of fuel, electricity and other products, excluding depreciation, for
2001 was adjusted by $132 million primarily as a result of mark-to-market
accounting adjustments to our natural gas trading business of $80 million and
the reversal of $33 million of power purchase agreement contra-expense
amortization in 2001 due to the change in the accounting for these power
purchase agreements to fair value accounting.

Selling, general and administrative expense was adjusted by $38 million for
2001 primarily as a result of the reclassification of labor costs to maintenance
expense.

Maintenance expense was increased by $49 million primarily as a result of
the reclassification of maintenance labor costs previously classified as
selling, general and administrative expense and other operating expenses.

F-19

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other operating expenses were adjusted by $11 million for 2001 primarily as
a result of reclassifications of labor costs to maintenance expense.

Interest expense was adjusted by $63 million primarily as a result of
losses on interest rate hedges previously accounted for as cash flow hedges
under SFAS No. 133. Accordingly, swap breakage costs incurred in 2001 of
approximately $42 million are now reflected as interest expense in 2001, rather
than such costs being deferred in OCI and amortized to interest expense over the
life of the related debt.

Equity in income of affiliates was adjusted by $26 million, primarily as a
result of changes in the timing of income recognition from the Company's Bewag
investment between 2001 and 2000.

The provision for income tax for 2001 was adjusted primarily as a result
of: $4 million of additional income tax expense recorded in Asia, $21 million of
additional income tax expenses related to WPD; the tax effect of restatement
adjustments in 2001 described above; and various adjustments related to U.S.
residual taxes or non-consolidated equity interests.

F-20

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Operating revenue for 2000 was adjusted by $101 million primarily as a
result of the following restatement adjustments:

- the reduction by $45 million relating to the Company's overstatement of
$85 million of natural gas inventories (the remainder reduces revenues in
2000 and prior years);

- a reduction of $30 million to record a full requirements contract in
Texas at fair value; and

- the reduction of $23 million of mark-to-market gains on energy loans held
by Mirant's Energy Capital business, which were previously accounted for
at fair value.

Cost of fuel, electricity and other products was adjusted by $88 million
primarily as a result of the reversal of $86 million of expenses associated with
a full requirements contract in Texas, due to the change in accounting for this
contract to fair value accounting.

Equity in earnings of affiliates was adjusted by $57 million, primarily as
a result of benefits from the reduction of the tax rate in Germany in 2000,
which were not previously recognized.

Provision for income tax for 2000 was adjusted primarily as a result of the
income tax effect of a currency devaluation in the Philippines of $35 million
which had not been previously recognized and $62 million of additional expense
related to Bewag and the tax effect of restatement adjustments in 2000 described
above.

F-21

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONSOLIDATED BALANCE SHEETS

F-22

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Funds on deposit have been reclassified from other current assets to a
separate line on the consolidated balance sheet.

Receivables, net was adjusted by $184 million primarily due to the
reduction of customer receivables by $152 million due to cash receipts in 2001
previously not recorded as such, and due to the reduction of accrued revenues by
$85 million due to an error associated with the accounting for sales of natural
gas.

Price risk management assets, current and noncurrent, were adjusted by $523
million, primarily due to the elimination of intracompany positions.

Other current and other noncurrent assets were adjusted by $650 million
primarily due to a change in the accounting for certain derivative financial
instruments from hedge accounting to fair value accounting through earnings.

Property, plant and equipment, net was adjusted by $160 million primarily
due to the change in accounting for certain leases from operating leases to
capital leases of $132 million and additional accruals for construction work in
progress of $26 million.

Other intangible assets were adjusted by $46 million primarily as a result
of reclassifications of trading rights associated with the Company's New York
business unit being reclassified to goodwill. This increase to goodwill was
partly offset by finalizing purchase accounting for the Company's Jamaica
acquisition.

Price risk management liabilities, current and noncurrent, were adjusted by
$109 million and $749 million, respectively, primarily due to the
reclassification of the estimated fair value of power purchase agreements of
approximately $914 million and the reclassification of certain derivative
financial instruments to price risk management liabilities, partly offset by the
elimination of intercompany positions discussed above.

Obligations under energy delivery and purchase commitments were adjusted by
$679 million primarily due to the reclassification of a power purchase agreement
to price risk management liabilities as discussed above.

Long-term debt was adjusted primarily due to the change in accounting for
certain leases from operating leases to capital leases.

Accumulated other comprehensive loss was adjusted by $103 million during
2001 primarily as a result of errors in the Company's accounting for certain
commodity financial instruments as hedging instruments. Certain gains previously
deferred in OCI are now reflected in earnings due to the change in accounting
for commodity financial instruments at fair value rather than as hedges.

Additional paid-in capital at December 31, 1999 has been adjusted primarily
to reflect a non-cash transfer of employee obligations by Mirant to Southern
Company.

F-23

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Retained earnings at December 31, 1999 has been restated to reflect the
prior period adjustment in the accompanying consolidated statements of
shareholders' equity, and increased by $53 million, as a result of the
restatement adjustments. This increase in the retained earnings balance is
primarily due to $49 million of tax benefits relating to the devaluation of the
Philippine Peso relative to the United States dollar that occurred in the
Philippines from 1997 through 1999 but were not previously recognized in the
consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS

F-24

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- ---------------

* Classification of certain amounts has changed in the current year.

Operating cash flows in 2001 decreased by $171 million primarily due to the
reclassification of $217 million in proceeds from a commodity prepay transaction
to financing activities. Cash flows from financing activities in 2001 were
increased by a corresponding amount.

Operating cash flows in 2000 have been adjusted by $185 million primarily
as a result of the reclassification of $88 million of proceeds from notes
payable previously classified as cash flows from operating activities as well as
the reclassification of $73 million of cash associated with discontinued
operations to assets held for sale. Cash paid for acquisitions and proceeds from
sales of assets were each reduced by $1.5 billion to eliminate amounts
attributable to the operating leases for the Morgantown and

F-25

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Dickerson facilities which were previously accounted for as a sale-leaseback
transaction. Financing cash flows increased $88 million as a result of the
reclassification of the proceeds from the loan discussed above.

4. FINANCIAL INSTRUMENTS

DERIVATIVE FINANCIAL INSTRUMENTS

In connection with its power generation business in North America, Mirant
enters into a variety of short and long-term agreements to acquire the fuel for
generating electricity, as well as to sell the electricity produced. A portion
of the Company's fuel is also purchased in the spot market and a portion of the
electricity it produces is sold in the spot market. As a result, the Company's
financial performance varies depending on changes in the prices of these
commodities.

From time-to-time, the Company enters into derivative financial instruments
to manage the market risks associated with the electricity produced by its power
plants that are not covered by long-term, fixed price contracts. Mirant enters
into a variety of contractual agreements, such as forward purchase and sale
agreements, and futures, swaps and option contracts. Futures and option
contracts are traded on a national exchange and swaps and option contracts are
traded 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 discussed in Note 3, the Company has subsequently determined that all of
the Company's commodity derivative financial instruments previously accounted
for as cash flow hedges under SFAS No. 133 do not qualify for cash flow hedge
accounting. Accordingly, all unrealized gains and losses associated with these
derivative transactions, previously deferred, have now been recognized in
earnings as incurred in 2002 and 2001.

In addition, the Company has subsequently determined that certain of the
Company's power purchase agreements are derivative financial instruments and
subject to fair value accounting under SFAS No. 133. Previously, the Company
believed the agreements qualified for the "normal purchase/normal sale"
exclusion under SFAS No. 133 and had accounted for the agreements as executory
contracts under accrual accounting.

PROPRIETARY TRADING ACTIVITIES

In addition to managing commodity price risk for its generation assets,
Mirant also engages in proprietary trading, primarily in regions where it owns
generating facilities or other physical assets. The Company assumes 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
Company's proprietary trading business can be volatile and subject to swings in
earnings and cash flow as commodity prices change. Gas and electricity, the
primary commodities it trades, are among the most volatile commodities in terms
of price in the market.

These derivative instruments are recorded at their estimated fair value in
the Company's consolidated balance sheet as price risk management assets and
liabilities. Changes in the fair value and settlements of these instruments are
recorded as net trading revenues.

The volumetric weighted average maturity, or weighted average tenor, of the
North American portfolio, including the derivative financial instruments
previously accounted for as cash flow hedges, at December 31, 2002 was 2.5
years. The net notional amount, or net long (short) position, of the price risk
management assets and liabilities at December 31, 2002 was approximately (3)
million equivalent megawatt-hours.

F-26

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair values, net of credit reserves, of Mirant's price risk management
assets and liabilities as of December 31, 2002, are included in the following
table (in millions):

Power sales agreements and contracts that are used to mitigate exposure to
commodity prices but do not meet the definition of a derivative or are excluded
from fair value accounting under certain exceptions in SFAS No. 133 are
accounted for as executory contracts.

INTEREST RATE AND CURRENCY DERIVATIVES

The Company has entered into interest rate swaps, which are accounted for
as hedges of its cash flow exposure to variable interest rates. The interest
rates in the following table represent the range of fixed interest rates that
Mirant pays on the related interest rate swaps. On all of these interest rate
swaps, Mirant receives floating interest rate payments based on the London
InterBank Offered Rate ("LIBOR"). The Company has also entered into a currency
swap to mitigate Mirant's exposure changes in foreign currency rates arising
from cross border sales denominated in foreign currency. Interest rate and
foreign currency swaps outstanding at December 31, 2002 are as follows:

CAD -- Denotes Canadian dollar

Unrealized gains and losses on interest rate swaps and foreign currency
swaps accounted for as hedges are recorded in OCI.

The unrealized gain or loss for interest rate swaps is determined based on
third party quotations of forward LIBOR and swap rates at December 31, 2002.
This value estimates the amount that Mirant would receive or pay to terminate
the swap agreement at the reporting date. The unrealized gain or loss for
currency forwards is determined based on third party forward rates as of
December 31, 2002.

Additional Canadian dollar contracts with a notional amount of CAD$219
million are included in the fair value of price risk management liabilities
because hedge accounting criteria were not met. As of December 31, 2002, the
unrealized loss was $2 million.

FAIR VALUES

SFAS No. 107, "Disclosures About Fair Value of Financial Instruments,"
requires the disclosure of the fair value of all financial instruments.
Financial instruments recorded at market or fair value include cash and
interest-bearing cash equivalents, derivative financial instruments, and
financial instruments used

F-27

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

for price risk management purposes. The following methods were used by Mirant to
estimate the fair value of all financial instruments that are not otherwise
carried at fair value on the accompanying consolidated balance sheets:

Notes Receivable. The fair value of Mirant's notes receivable is
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, or discounted cash flow analysis
based on current market interest rates for similar types of borrowing
arrangements.

Company Obligated Mandatorily Redeemable Securities. The fair value
of Mirant's company obligated preferred securities is calculated based on
the quoted market price.

The carrying or notional amounts and fair values of Mirant's financial
instruments at December 31, 2002 and 2001 were as follows (in millions):

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following at December 31,
2002 and 2001 (in millions):

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. The following table shows the estimated useful lives (in years):

Production.................................................. 5 to 42
Transmission and distribution............................... 5 to 39
Other....................................................... 3 to 35

F-28

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The cost of oil and gas properties was amortized using the units of
production method over the estimated proved reserves of the properties.

Substantially all construction on three generating facilities has been
suspended in 2002. Management plans to resume construction on two of these
facilities during 2005 and 2006 and pursue a sale of the remaining facility. A
portion of one construction project, the Bowline expansion at Mirant New York,
has been suspended.

As a result of the suspension, Mirant reviewed the suspended construction
projects for impairment in accordance with SFAS No. 144. See Note 9 for a
discussion of the impairment losses recorded for suspended construction
projects.

6. DISPOSITIONS AND ACQUISITIONS

DISPOSITIONS

In 2002, Mirant undertook a program of asset sales designed to reduce
investments in businesses that are not central to the Company's current
strategy. The following table summarizes information related to completed asset
sales as of December 31, 2002 (in millions):

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

In addition to the above completed sales, Mirant announced in July 2002 its
agreement to sell the Company's Neenah generating facility for approximately
$109 million. This sale closed in the first quarter of 2003. Subsequent to
December 31, 2002, Mirant also completed the sale of its Tanguisson power plant
in Guam for approximately $16 million, and in March 2003, Mirant completed the
sale of Mirant Americas Energy Capital for approximately $160 million. The
financial statements for prior years have been reclassified to report the
revenues and expenses separately as discontinued operations for these asset
sales (See Note 3).

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. This business
is included in income (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. This
business is included in income (loss) from discontinued operations in the
accompanying consolidated statements of operations.

F-29

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, which mines and processes over 1 million tons of coal
each year for sale to a combination of domestic and export markets 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.

EDELNOR: In December 2001, Mirant wrote down its remaining investment in
EDELNOR by $82 million. On December 31, 2001, Mirant completed the sale of its
82.3% interest in EDELNOR for consideration of approximately $5 million.

Hidroelectrica Alicura S.A. ("Alicura"): In 2000, Mirant completed the
sale of its 55% indirect interest in Alicura for total consideration of $205
million, including the assumption of debt and the buy-out of the minority
partners. Alicura's principal asset was a concession to operate a 1,000 MW
hydroelectric facility located in the province of Neuquen, Argentina. The
proceeds from the sale approximated the net book value of the investment.

ACQUISITIONS

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.

Navotas 1 and 2: In December 2002, Mirant entered into an agreement with
the Philippine government ("NPC") to acquire 100% ownership of the Navotas 2
plant for approximately $13 million at the end of the cooperation period. NPC
will pay Mirant approximately $7 million in full settlement of its obligations
to pay capacity fees for the remaining term of the energy conversion agreement
("ECA"). This agreement is expected to close during the second quarter of 2003.
In March 2003, the ECA for Navotas 1 expired, and the plant was transferred to
NPC pursuant to the terms of the ECA.

TransCanada Marketing Business: In December 2001, Mirant acquired the
majority of the gas marketing business of TransCanada for approximately $120
million. The transaction included the purchase of the majority of TransCanada's
natural gas trading and marketing business and the related natural gas
transportation and storage contracts. Mirant also purchased the right to market
the aggregated supply from 550 Canadian natural gas producers.

JPSCo: In March 2001, Mirant acquired 80% of the outstanding shares of
JPSCo for $201 million from the Jamaican government. JPSCo is a fully integrated
electric utility on the island of Jamaica. JPSCo is subject to monitoring and
rate regulation by the Jamaican government and operates under a 20-year license,
expiring in 2021.

Generating Assets of Potomac Electric Power Company ("PEPCO"): On December
19, 2000, Mirant, through its subsidiaries and together with third-party lessors
in a leveraged lease transaction, purchased PEPCO's generating facilities in
Maryland and Virginia, consisting of four electric generating stations,
Morgantown, Chalk Point, Dickerson and Potomac River, with a combined generating
capacity of 5,256 MW. In addition to the generating facilities, Mirant acquired
three coal ash storage facilities, a 51.5 mile oil pipeline serving the Chalk
Point and Morgantown facilities, an engineering and maintenance service
facility, and other related assets.

F-30

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Mirant paid an aggregate of $1.255 billion in cash and transaction expenses
for the generating facilities and related assets, except for the baseload
facilities at Morgantown and Dickerson, which were purchased by the third-party
lessor for $1.5 billion in cash. Mirant Mid-Atlantic simultaneously entered into
agreements with the lessors to lease the Morgantown (1,244 MW) and Dickerson
(546 MW) baseload facilities for terms of 33.75 years and 28.5 years,
respectively (see note 16). These leases have been accounted for as operating
leases.

As part of the acquisition, Mirant assumed obligations for pension
benefits, other post employment benefits and vacation accruals associated with
the 950 former PEPCO personnel that became employees of Mirant aggregating $107
million. Mirant also assumed the obligations related to a lease for the 84 MW
combustion turbine owned by SMECO at the Chalk Point facility. This lease has
been accounted for as a capital lease by Mirant.

As part of the acquisition, Mirant also entered into two transition power
agreements to provide power to PEPCO, and assumed PEPCO's obligations under
existing power purchase agreements from third parties, representing obligations
with an estimated fair value of approximately $1.7 billion and $700 million,
respectively, at the date of the acquisition. See note 17 for a discussion of
the transition power agreements and the power purchase agreements.

The acquisition was accounted for under the purchase method of accounting.
The final purchase price allocation is as follows (in millions):

Current assets.............................................. $ 53
Property, plant and equipment............................... 1,429
Goodwill.................................................... 1,276
Other intangible assets..................................... 285
Deferred tax asset resulting from acquisition............... 822
Obligations under power purchase agreements and transition
power agreements.......................................... (2,438)
Other liabilities........................................... (172)
------
Net purchase price........................................ $1,255
======

The obligations under the power purchase agreements and under the
transition power agreements were recorded at their estimated fair value at the
acquisition date.

Minority Interest in Mirant Americas Energy Marketing: In September 2000,
Mirant acquired Vastar's 40% interest in Mirant Americas Energy Marketing for
$250 million. As a result, Mirant Americas Energy Marketing became a wholly
owned subsidiary and has been consolidated in Mirant's financial statements
since the date of acquisition.

SE Finance and Capital Funding: On March 5, 2001, Southern redeemed its
outstanding share of Mirant's Series B preferred stock in exchange for
transferring two of the Company's subsidiaries, SE Finance Capital Corporation
and Southern Company Capital Funding Inc., to Southern.

F-31

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

7. INVESTMENTS

Following is a summary of investments as of December 31, 2002 and 2001 (in
millions):

Preferred Stock: Mirant owns a $40 million 16.75% convertible preferred
equity interest in Aqualectra, an integrated water and electric company in
Curacao, Netherlands Antilles. Aqualectra has a call option and Mirant has a put
option related to this investment. The options are exercisable the earlier of
three years from December 2001 or upon privatization of the company and expire
three years after the trigger date. Mirant can convert its shares to common
shares during the vesting period.

F-32

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In 2002, Mirant's undertook a program of asset sales designed to reduce
investments that are not central to the Company's current strategy. Following is
a summary of information related to completed investment sales as of December
31, 2002 (in millions):

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

Bewag: Mirant had owned 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 $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 addition, Mirant retains certain obligations as a project
sponsor, some of which are subject to indemnification by Cleco. The obligations
retained by Mirant and not subject to indemnity relate primarily to the existing
20-year tolling agreement between Mirant and Perryville. Effective August 23,
2002, Mirant and Perryville restructured the tolling agreement to remove the
requirement for Mirant to post a letter of credit or other credit support in the
event of a downgrade from S&P or Moody's. In connection with the restructuring,
Mirant made a $100 million subordinated loan to Perryville which is reported as
$98 million of notes and other receivables -- noncurrent and $2 million of
receivables -- current on the consolidated balance sheet. 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.

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, Mirant recognized
an impairment loss of approximately $265 million, net of $60 million of related
income tax benefits, 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.

F-33

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 December 2002, Mirant completed the sale of its
investment in the development project in Norway. 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. The investment was sold at
approximately its carrying value.

8. GOODWILL AND OTHER INTANGIBLE ASSETS

GOODWILL

Following is a summary of the changes in goodwill for the years ended
December 31, 2002 and 2001, (in millions):

Upon the adoption of SFAS No. 141, Mirant reclassified its intangible
assets relating to trading rights resulting from business combinations, to
goodwill effective January 1, 2002. The reclassification increased goodwill by
$149 million, net of accumulated amortization of $13 million and decreased
intangible assets by a corresponding amount.

F-34

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Upon the adoption of SFAS No. 142, Mirant discontinued amortization of
goodwill effective January 1, 2002. Net income and earnings per share (basic and
diluted) for 2001 and 2000 have been adjusted below to exclude amortization
related to goodwill and trading rights recognized in business combinations (in
millions, except per share data).

In the fourth quarter of 2002, the Company performed the annual goodwill
impairment evaluations of its Asian, Caribbean and North American reporting
units as required by SFAS No. 142. No impairment charge for goodwill related to
our North American or Caribbean reporting units was recorded, as the fair value
of the reporting units exceeded the carrying value. In evaluating the Asian
reporting unit goodwill, the Company determined that the carrying value of that
reporting unit exceeded its fair value. As a result, the Company performed the
second step of the impairment test by comparing the implied fair value of the
Asian reporting unit goodwill, determined in a manner similar to a purchase
price allocation, with the carrying amount of that goodwill. As a result, the
Company recognized an impairment charge in 2002 of $697 million. The impairment
was primarily attributable to the loss of future cash flows associated with
certain Asian assets that were sold during the year, principally the Company's
interest in the Shajiao C power plant.

INTANGIBLE ASSETS

Following is a summary of intangible assets as of December 31, 2002 and
2001 (in millions):

F-35

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Substantially all of Mirant's intangible assets are subject to amortization
and are being amortized on a straight-line basis over their estimated useful
lives, ranging up to 40 years. Amortization expense for the years ended December
31, 2002, 2001 and 2000 was approximately $19 million, $31 million and $35
million, respectively. Assuming no future acquisitions, dispositions or
impairments of intangible assets, amortization expense is estimated to be $19
million for each of the following five years.

The 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.

During 2002, Mirant transferred $36 million, net of accumulated
amortization of $4 million, in development rights to construction work in
process.

9. RESTRUCTURING CHARGES AND IMPAIRMENT LOSSES

As a result of changing market conditions, including constrained access to
capital markets attributable primarily to the Enron bankruptcy and Moody's
downgrade of Mirant's credit rating in December 2001, Mirant adopted a plan in
March 2002 to restructure its operations by exiting certain activities
(including its European trading and marketing business), canceling and
suspending planned power plant developments, closing business development
offices, and severing employees. During 2002, Mirant recorded restructuring
charges of $600 million related to accruals under the March 2002 restructuring
plan as well as other costs that were recorded directly to restructuring
expense. Also during 2002, Mirant recorded asset impairment charges of $373
million for costs relating to certain turbines and development projects that
were to be sold, abandoned or placed in storage.

RESTRUCTURING CHARGES

Components of the restructuring charges are as follows (in millions):

Costs to cancel equipment orders and service agreements per
contract terms............................................ $549
Severance of approximately 655 employees worldwide and other
employee termination-related charges...................... 51
----
Total..................................................... $600
====

As of December 31, 2002, Mirant had terminated approximately 655 employees
as part of its restructuring.

During 2002, Mirant reclassified $164 million of the accrual to current
portion of long-term debt as a result of the consolidation during the year of
certain portions of Mirant's formerly off-balance sheet equipment procurement
facilities (Note 16). Also during 2002, Mirant adjusted the accrual as a result
of revisions to restructuring estimates (primarily relating to European and
domestic office closures and

F-36

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

adjustments to equipment termination costs) and payments made against the
accrual as summarized in the following table (in millions):

IMPAIRMENT LOSSES

The Company recorded impairment charges for the years ended December 31,
2002, 2001 and 2000 as follows (in millions):

Impairment charges for equity method and other investments are disclosed in
Note 7.

Turbines and Related Project Costs: In March 2002 and December 2002, the
Company recognized impairment charges of approximately $151 million related to
the construction work in progress costs of turbines to be terminated and the
related project costs and certain turbines that it intends to place in storage.
As of December 31, 2002, the remaining estimated fair value of these projects
was approximately $3 million, and is included in property, plant and equipment,
net in the accompanying consolidated balance sheets.

Power Islands: In the third quarter of 2002, the Company assessed the
recoverability of certain costs associated with two engineered equipment
packages (commonly referred to as "power islands") related to its proposed
development projects in Europe and Korea. Based on management's estimate of
recoverability of the costs of these power islands, an impairment loss of $134
million was recognized in 2002. The Company also recorded an impairment loss of
$11 million for the related Yulchon Project site in Korea.

Mint Farm: In December 2002, the Company assessed the recoverability of
certain costs related to its Mint Farm generating project in Longview,
Washington, which had been suspended. Based on management's estimate of the
recoverability of the project costs, Mirant recognized an impairment charge of
approximately $77 million. The remaining project cost associated with this
facility is $92 million, and is included in property, plant and equipment, net
in the accompanying consolidated balance sheets.

EDELNOR: In 2001, Mirant recognized an impairment charge of $82 million
related to its investment in EDELNOR.

F-37

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. DEBT

At December 31, 2002 and 2001, long-term debt of Mirant and its
consolidated subsidiaries was as follows (in millions):

F-38

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In 2002, Mirant deferred shipment dates and made direct payments for
certain turbines in its off-balance sheet equipment procurement facilities. As a
result, those specific turbines no longer qualify for off-balance sheet
treatment. Therefore, Mirant has included a $359 million liability for these
turbines (equal to the drawn amounts for those turbines) as of December 31,
2002, of which $59 million is reported as other long-term debt and $300 million
is reported in current portion of long-term debt in the accompanying
consolidated balance sheet at December 31, 2002.

F-39

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 2002, the annual scheduled maturities of long-term debt
during the next five years were as follows (in millions):

2003........................................................ $1,731
2004........................................................ 2,189
2005........................................................ 236
2006........................................................ 900
2007........................................................ 517
Thereafter.................................................. 3,249

MIRANT CORPORATION -- REVOLVING BANK FACILITIES

Mirant Corporation has three revolving bank facilities: a $1.125 billion
364-Day Credit Facility maturing in July 2003, a $450 million Credit Facility C
maturing in April of 2004, and a $1.125 billion 4-Year Credit Facility maturing
in July 2005. The credit facilities generally require payment of commitment fees
based on the unused portion of the commitments. The schedule below summarizes
the revolving bank facilities of Mirant Corporation as of December 31, 2002 (in
millions).

As of April 25, 2003 the total amount of Mirant's credit facility C was
reduced to $446 million and the total amount of Mirant's 4-year credit facility
was reduced to $1,056 million.

The bank facilities contain two financial covenants, which are calculated
quarterly. Mirant Corporation is required to maintain a ratio of 1.50 to 1.00 of
cash available for corporate debt service to corporate interest, as defined, and
a ratio of recourse debt to recourse capital, as defined, of 0.55 to 1.00. In
addition to the financial covenants, the Mirant Corporation bank facilities
include other covenants, including restrictions on liens, incurrence of recourse
debt, payment of dividends and sale of assets and the requirement to provide
financial statements to its lenders within 120 days after the end of each fiscal
year and within 60 days after the end of each of its first three fiscal
quarters. Each of the bank facilities includes certain events of default
including a cross acceleration provision under which a default would be
triggered if Mirant Corporation failed to pay any principal, premium or interest
in excess of $50 million on any other outstanding debt obligation, and a change
of control default triggered by any person or group owning beneficially,
directly or indirectly, more than 50% of the voting stock of Mirant Corporation
or certain changes in the composition of the board of directors of Mirant
Corporation.

As a result of write-downs to reflect the impairment of goodwill, valuation
allowances provided for net deferred tax assets, and deferred tax liabilities
provided with respect to investments in foreign subsidiaries, Mirant Corporation
anticipated that it would not be in compliance with the recourse debt to
recourse capital financial covenant under its bank facilities (including the
Mirant Americas Development Capital turbine facility) upon delivery of its
financial statements for the year ended December 31, 2002. Therefore, Mirant
Corporation sought, and received, a waiver from the required lenders under its
bank facilities for any potential breaches with respect to non-compliance with
the recourse debt to recourse capital financial

F-40

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

covenant, any potential breaches that could arise relating to our historical
financial reporting requirements or representations or the inclusion in its
independent auditors' report on the Company's annual financial statements of an
explanatory paragraph stating that the Company has not presented the selected
quarterly financial data specified by Item 302(a) of Regulation S-K, that the
Securities and Exchange Commission requires as supplementary information to the
basic financial statements. The lenders under the respective bank facilities
agreed to such waiver through May 29, 2003, subject to certain terms and
conditions, including limiting future use of the bank facilities to issuances of
letters of credit and limiting capital expenditures and other material payments.
The terms of the waiver provide for an extension, to July 14, 2003, with the
prior written consent of lenders representing a majority of the committed amount
under each of the facilities. Upon expiration or termination of the waiver, the
lenders under the respective bank facilities would be able to restrict the
issuance of additional letters of credit and/or declare an event of default and,
after the applicable cure or grace period, accelerate the indebtedness under
such bank facilities. An acceleration of indebtedness under the bank facilities
would cross accelerate approximately $910 million of Mirant Corporation capital
markets and other indebtedness. However, the Company can provide no assurances
either with respect to whether the waiver will be extended beyond May 29, 2003
or whether the lenders under each of the Mirant Corporation bank facilities will
accelerate the loans after expiration or termination of the waiver.

MIRANT CORPORATION -- 7.4% SENIOR NOTES DUE 2004 AND 7.9% SENIOR NOTES DUE
2009

Mirant Corporation has issued $200 million and $500 million of 7.4% Senior
Notes and 7.9% Senior Notes, respectively. These senior notes are unsecured
obligations of Mirant Corporation. The senior notes are not supported by
guarantees or other commitments of subsidiaries of Mirant Corporation. In
addition to other events of default typical of senior notes, it is an event of
default under the notes if Mirant Corporation fails to pay any principal,
premium or interest in excess of $50 million on any outstanding debt obligation
when it becomes due and payable. The senior notes do not include financial
maintenance covenants. However, under the senior notes, Mirant Corporation is
restricted in its ability to grant liens or other encumbrances on or over the
non-cash assets of Mirant Corporation to secure the payment of indebtedness,
subject to certain exceptions.

MIRANT CORPORATION -- 5.75% CONVERTIBLE SENIOR NOTES DUE 2007 AND 2.5%
CONVERTIBLE SENIOR DEBENTURES DUE 2021

Mirant Corporation has issued $750 million and $370 million in aggregate
principal amount of 2.5% Convertible Debentures and 5.75% Convertible Senior
Notes, respectively. These convertible senior debentures/notes are unsecured
obligations of Mirant Corporation. The convertible senior debentures/notes are
not supported by guarantees or other commitments of subsidiaries of Mirant
Corporation to pay amounts due under such debentures/notes or to provide Mirant
Corporation with funds for the payment, whether by dividends, distributions,
loans or other payments. The convertible senior debentures/notes do not include
financial covenants. However, under the convertible senior debentures/notes,
Mirant Corporation is restricted in its ability to grant liens or encumbrance on
or over the non-cash assets of Mirant Corporation to secure the payment of
indebtedness, subject to certain exceptions.

MIRANT AMERICAS DEVELOPMENT CAPITAL, LLC -- DOMESTIC TURBINE LEASE FACILITY

Mirant Americas Development Capital, LLC ("Mirant Americas Development
Capital") is party to a warehouse operating lease facility ("turbine facility").
The turbine facility initially consisted of a $700 million "true-funding"
tranche and a $1.1 billion "treasury-backed" tranche. Pursuant to the
transaction, a trust (the "lessor") was established for the purpose of owning
certain gas turbines, steam turbines, heat recovery generators and other
equipment ("equipment"). The turbine facility provides that Mirant Americas
Development Capital may from time to time purchase the equipment from the trust
by
F-41

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

making certain termination payments or upon completion of equipment the lessor
will lease equipment to Mirant Americas Development Capital under a master
triple-net lease (the "lease"). The transaction was structured to provide that
equipment would be added to the lease on the date of its completion and
delivery, and the lease term with respect to such equipment would commence on
such date and would expire seven and one half years from the closing. The lease
is intended to qualify as an operating lease for Mirant Americas Development
Capital under SFAS No. 13, as amended (including relevant FASB Technical
Bulletins and Emerging Issues Task Force Issues). Mirant Americas Development
Capital retains ownership of the Equipment for income tax purposes.

The turbine lease provided for the lessor to fund the acquisition of the
equipment (i) by issuing Series A1 and A2 Notes (collectively, the A-Notes) and
Series B1 and B2 Notes (collectively, the B-Notes) and (ii) by issuing Series C1
and C2 certificates (collectively, the Certificates) in respect of the
investments in the Lessor (in an amount equal to approximately 3% of Equipment
cost). The $700 million anticipated maximum draw is funded with Series A1 and B1
Notes and C1 Certificates. Series A2-Notes, Series B2-Notes and C2 Certificates
were to be issued for all draws in excess of $700 million, to a maximum of $1.1
billion and were to be collateralized by a posting of collateral in an amount of
105% of amounts outstanding thereunder in the form of cash or short-term United
States treasury securities acceptable to the lessor and the holders thereof as
and when drawn. The commitment to fund the "true-funding" tranche was reduced to
$500 million on December 30, 2002. The commitment to fund the "treasury-backed"
tranche was terminated on April 18, 2003. The amounts outstanding under the
Series A1 Notes, the Series B2 Notes and the Series C1 certificates was $221
million at April 18, 2003, of which approximately $198 million was recourse to
Mirant Corporation pursuant to its guarantee of certain obligations of Mirant
Americas Development Capital. The covenants of Mirant Corporation under such
guarantee are substantially the same as the corresponding covenants under the
credit facilities of Mirant Corporation. In addition, the participation
agreement for the lease includes events of default related to Mirant Corporation
as guarantor that are substantially the same as the corresponding events of
default in the credit facilities of Mirant Corporation. The obligations of
Mirant Corporation under the guarantee are unsecured and exclusive obligations
of Mirant Corporation. The participants in the turbine lease participated as
lenders in connection with the waiver described above.

MIRANT ASSET DEVELOPMENT AND PROCUREMENT B.V. -- EUROPE POWER ISLAND LEASE

Mirant Asset Development and Procurement B.V. ("Mirant BV") entered into a
Master Equipment Purchase and Sale Agreement ("Master Equipment Agreement") with
General Electric Company and General Electric International, Inc. for the
acquisition of nine 386-MW engineered equipment packages, referred to as power
islands.

To finance construction of the power islands, Mirant BV entered into a
E1,100,000,000 Power Island Acquisition Facility. European Power Island
Procurement B.V., a special purpose limited liability company, was established
to act as "owner". Pursuant to an assignment agreement, the owner acquired the
rights of Mirant BV in and to the Master Equipment Agreement. The owner was to
finance the purchase price of the power islands through advances made under a
E1,100,000,000 Power Island Acquisition Facility provided by a syndicate of
financial institutions. Mirant BV was engaged by the owner to act as its
construction and procurement agent with respect to the power islands pursuant to
the terms of a procurement agency agreement. The borrowing capacity was reduced
to E550,000,000 during 2002, and the facility was repaid and terminated on
February 28, 2003.

MIRANT AMERICAS ENERGY CAPITAL -- THREE YEAR CREDIT FACILITY

In March 2003, Mirant Americas Energy Capital terminated and repaid the
outstanding $50 million under its credit facility. As of December 31, 2002, the
outstanding borrowings were $100 million at an

F-42

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

interest rate of 3.84%. Under the terms of the credit facility, the facility was
initially unsecured with a covenant by Mirant Americas Energy Capital to secure
the obligations thereunder by transferring the borrowing base assets to a
special purpose vehicle and granting security interests in such assets upon the
occurrence of certain events, including ratings downgrades by Moody's and a
specified increase in the yield on Mirant Americas Generation's publicly traded
debt. As a result of the Moody's downgrade, the yields on Mirant Americas
Generation's publicly traded debt increased and triggered the obligation of
Mirant Americas Energy Capital to secure the obligations thereunder. In March
2002, Mirant Americas Energy Capital transferred the borrowing base assets to
the special purpose vehicle and granted security interests in such assets. The
special purpose vehicle was consolidated with Mirant Corporation.

MIRANT AMERICAS GENERATION, LLC -- CREDIT FACILITIES B AND C MATURING OCTOBER
2004

Mirant Americas Generation, an indirect subsidiary of Mirant Corporation,
has two credit facilities, each entered into in August 1999, a $250 million
5-year revolving credit agreement ("Credit Facility B") for capital expenditures
and general corporate purposes and a $50 million 5-year revolving credit
facility ("Credit Facility C") for working capital needs. The commitments under
Credit Facility B and Credit Facility C remain available through October 2004.
As of December 31, 2002, the outstanding borrowings under Credit Facility B and
Credit Facility C were $250 million and $50 million, respectively, at an
interest rate of 2.92%.

Each of the Mirant Americas Generation credit facilities is an unsecured
obligation of Mirant Americas Generation. None of the credit facilities of
Mirant Americas Generation are supported by guarantees or other commitments of
Mirant Corporation or any of its subsidiaries.

In addition to other covenants and terms, each of Mirant Americas
Generation's credit facilities include minimum debt service coverage, a maximum
leverage covenant and minimum debt service coverage tests for restricted
payments and incurrence of additional indebtedness. Under its credit facilities,
Mirant Americas Generation is required to maintain a minimum of 1.75:1 ratio of
cash available for corporate debt service to corporate interest, based on the
last twelve months of available financial statements. In addition, Mirant
Americas Generation is required to maintain a maximum of 0.60:1 ratio of
recourse debt to recourse capital, or 0.65:1 if rated investment grade. Further,
Mirant Americas Generation may not incur recourse debt unless (x) its ratio of
cash available for corporate debt service to corporate interest is at least
2.75:1.00 (if not rated investment grade) or 2.25:1.00 (if rated investment
grade), and (y) if on the date such incurrence (A) Moody's and S&P reaffirm an
investment grade rating, or (B) if not rated investment grade, the projected
ratio of cash available for corporate debt service to corporate interest shall
be at least 2.75:1.00 over the life of the credit facilities. Further, Mirant
Americas Generation may not (i) declare or make dividend payments or other
distribution of assets, properties, cash, rights, obligations or securities;
(ii) make payments with respect to affiliate subordinated debt; (iii) purchase,
redeem or otherwise acquire shares of any class of capital stock, unless its
ratio of cash available for corporate debt service to corporate interest was at
least 2.25:1.00 (if not rated investment grade) or 2.00:1.00 (if rated
investment grade).

The Mirant Americas Generation credit facilities limit the ability of its
designated generating subsidiaries -- essentially the subsidiaries that hold its
California, New England and New York assets -- to incur indebtedness. Under the
credit facilities, the maximum debt at the designated generating subsidiaries is
limited to $200 million (if investment grade) or $100 million (if non-investment
grade). In addition, the Mirant Americas Generation credit facilities provide
that, within 18 months of its receipt of the proceeds of any sale of any asset,
other than "Exempt Asset Sale Proceeds", Mirant Americas Generation (a) shall
invest such proceeds in assets in a similar or related line of line of business,
and/or (b) shall apply such proceeds to the repayment of debt under the credit
facilities. "Exempt Asset Sale Proceeds" mean (x) proceeds from the sale of
assets in the ordinary course, to conform to regulation or of short-term

F-43

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

marketable securities, (y) proceeds of any sale of an asset of Mirant Americas
Generation at the time the credit facilities were entered into ("Existing
Asset"), except proceeds from the sale of Existing Assets having a net book
value equal to the amount by which (a)(I) the aggregate net book value of all
Existing Assets sold after June 30, 1999, plus the principal amount of debt of
the designated generating subsidiaries outstanding at the time of such sale,
minus (II) the amounts reinvested or paid pursuant to the provision described
above after June 30, 1999, exceeds (b) 25% of the consolidated assets of Mirant
Americas Generation at June 30, 1999; and (z) proceeds of any sale of an asset
of Mirant Americas Generation, except proceeds from the sale of assets having a
net book value equal to the amount by which (a)(I) the aggregate net book value
of assets sold after June 30, 1999, plus the principal amount of debt of the
designated generating subsidiaries outstanding at the time of such sale, minus
(II) the amounts reinvested or paid pursuant to the provision described above
after June 30, 1999, exceeds (b) 25% of the consolidated assets of Mirant
Americas Generation at the date of its most recent balance sheet.

In addition to these covenants and terms, the Credit Facility C has a
clean-up provision, which requires that at least once during each twelve month
period there shall not be any advances outstanding for a period of 10
consecutive days.

Each of the credit facilities of Mirant Americas Generation includes
certain events of default including a cross acceleration provision pursuant to
which a default would be triggered if Mirant Americas Generation failed to pay
any principal, premium or interest or debt of Mirant Americas Generation in
excess of $50 million on any outstanding debt obligation, and a change of
control default triggered if Mirant Americas Generation ceases to be controlled
by Mirant Corporation.

MIRANT AMERICAS GENERATION, LLC -- SENIOR NOTES

Mirant Americas Generation, LLC has five series of Senior Notes: $500
million 7.625% Senior Notes due 2006; $300 million 7.2% Senior Notes due 2008;
$850 million 8.3% Senior Notes due 2011; $450 million 8.5% Senior Notes due
2021; and $400 million 9.125% Senior Notes due 2031. The Senior Notes are
unsecured obligations of Mirant Americas Generation. The Senior Notes are not
supported by guarantees or other commitments of Mirant Corporation or any of its
subsidiaries. In addition to other events of default typically found in an
indenture governing the senior notes, it is an event of default under the Senior
Notes if Mirant Americas Generation fails to pay any principal, premium or
interest in excess of $50 million on any outstanding debt obligation when it
becomes due and payable, and such default continues unremedied for 30 business
days. In addition to other covenants, the indenture governing the Senior Notes
include restrictions on incurrence of additional indebtedness by Mirant Americas
Generation and limitations on the ability of Mirant Americas Generation to sell
assets. Mirant Americas Generation may not incur additional senior debt unless
(a) the projected senior debt service coverage ratio for the next 24 months is
at least 2.5:1.0, or (b) each rating agency confirms the then existing rating on
the Senior Notes after giving effect to such incurrence. In addition, under the
Senior Notes asset sales by Mirant Americas Generation are limited to 10% of the
consolidated net assets of Mirant Americas Generation during the most recent 12
month period, except for asset sales where the proceeds are reinvested within 18
months in related businesses, used to repay debt, or retained by Mirant Americas
Generation or its subsidiaries. In addition, under the Senior Notes, Mirant
Americas Generation is restricted in its ability to grant liens or encumbrance
on or over its non-cash assets to secure the payment of indebtedness, subject to
certain exceptions. There are no restrictions under the Senior Notes on the
ability of subsidiaries of Mirant Americas Generation to incur secured or
unsecured indebtedness.

MIRANT CURACAO INVESTMENTS II -- CREDIT FACILITY

In October 2002, Mirant Curacao entered into a $20 million 5 year partial
amortizing credit facility with RBTT Merchant Bank Limited, Trinidad. The loan
is guaranteed by Mirant Corporation. The loan

F-44

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

agreement includes various covenants, including (i) restrictions on change of
control; (ii) restrictions on the issuance or purchase of its shares; (iii)
restrictions on transactions with affiliates; (iv) limitations on the incurrence
of new debt; and (v) restrictions on dividends.

CAPITAL LEASES

The Company is obligated under capital leases covering an office building
and certain plant and equipment. These leases bear interest at rates ranging
from 8.19% to 12.5%, and expire at various dates through 2022.

PROJECT FINANCE INDEBTEDNESS

In addition to the indebtedness described above, the following subsidiaries
of Mirant Corporation have project or non-recourse indebtedness: West Georgia
Generating Company, LLC , Mirant Trinidad Investments, Inc., Jamaica Public
Service Company, Limited, Grand Bahama Power, Mirant Sual Corporation and Mirant
Pagbilao Corporation. In each instance, except for the indebtedness of Grand
Bahama Power, the indebtedness of such entities is secured by the assets of the
project being financed and/or the equity interest in such project. In addition,
in each instance the indebtedness is the exclusive obligation of respective
entity involved in the project. Such indebtedness is not supported by guarantees
or other commitments of Mirant Corporation or any of its subsidiaries (other
than subsidiaries directly involved in such project or asset). Such subsidiaries
are subject to restrictive covenants that can limit their ability to incur
indebtedness, make prepayments of indebtedness, pay dividends, make investments,
engage in transactions with affiliates, create liens, sell assets and acquire
assets or businesses.

11. INCOME TAXES

The provision (benefit) for income taxes from continuing operations is as
follows (in millions):

F-45

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A reconciliation of the Company's federal statutory income tax rate to the
effective income tax rate for continuing operations for the years ended December
31, 2002, 2001 and 2000 is as follows:

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):

F-46

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 2002, the Company recognized a valuation allowance of $1,088
million primarily related to its United States deferred tax assets.

At December 31, 2002, the Company has net operating loss carryforwards for
United States federal income tax purposes of approximately $1.0 billion which
are available to offset future federal taxable income through 2022. In addition,
the Company has various foreign and state net operating loss carryforwards with
varying expiration dates which are available to offset future taxable income in
those jurisdictions.

As of December 31, 2002, Mirant recognized additional deferred tax expense
of $468 million with respect to the unremitted earnings of all of its foreign
subsidiaries as a result of changes to its plan for reinvestment of those
earnings. Previously, Mirant had recognized deferred tax liabilities with
respect to the undistributed earnings of only a portion of the earnings of
certain foreign subsidiaries.

Mirant had been included in the consolidated federal income tax return with
Southern for the period from January 1, 2001 through April 2, 2001. Under its
income tax sharing agreement with Southern, Mirant's current and deferred taxes
were computed on a stand-alone basis, and tax payments and refunds were
allocated to Mirant based on this computation. Under this tax sharing
arrangement, in 2002 Mirant was reimbursed for its United States federal
consolidated tax losses of $282 million for the period ended April 2, 2001. In
2002, Mirant filed a consolidated federal income tax return with its
subsidiaries for the period from April 3, 2001 through December 31, 2001.

12. EMPLOYEE BENEFIT PLANS

Mirant offers pension benefits to its domestic nonunion and union employees
through various pension plans. These benefits are based on pay, service history
and age at retirement. Pension benefits 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. Plan assets are primarily invested in equity and debt
securities. Certain executive pension benefits that cannot be provided by the
tax-qualified plans are provided through unfunded non-tax-qualified plans. All
pension plans are accounted for pursuant to SFAS No. 87, "Accounting for
Pensions." The measurement date for the domestic benefit plans is September 30
for each year presented.

During 2002, Mirant accounted for the following events pursuant to SFAS No.
88, "Accounting for Settlements and Curtailments of Defined Benefit Pension
Plans and for Termination Benefits."

- Mirant reduced its domestic workforce through various reduction-in-force
initiatives. This reduction in the number of employees earning pension
benefits was recognized as a pension plan curtailment.

F-47

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- Under the reduction-in-force initiatives, terminated employees who became
eligible for retirement during the calendar year were allowed to retain
their eligibility for future early retirement benefits. This pension
benefit enhancement was recognized as a special termination benefit.

- Mirant also divested the subsidiary Mirant State Line Ventures, Inc. The
resulting reduction in the number of employees earning pension benefits
was recognized as a pension plan curtailment. Mirant retained all benefit
obligations for pensions earned by these employees through the
divestiture date.

During 2002 and 2003, Mirant purchased about $17 million of individual
annuity contracts for certain employees who were eligible for non-tax-qualified
plans and met age, years of service and benefit requirements. These annuities
were designed to provide a comparable level of retirement security for all of
our United States-based employees. The annuity contracts will offset amounts
otherwise payable by the Company for benefits under existing non-tax-qualified
plans and are not intended to increase the total benefits payable. Pursuant to
SFAS No. 88, Mirant will account for this event as a partial settlement of the
non-tax-qualified pension obligation in 2003 since this action occurred after
the 2002 measurement date for the benefit plans. It is estimated that the
annuity purchases will reduce the overall projected benefit obligation for the
non-tax-qualified pension plans by approximately $8 million and will result in a
settlement charge under SFAS No. 88 of approximately $9 million in 2003.

Grand Bahama Power participates in defined benefit, trusteed, 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.

JPSCo 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 JPSCo is
December 31 for each year presented.

The rates assumed in the actuarial calculations for the pension plans of
Mirant as of their respective measurement dates were as follows:

F-48

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables show the collective actuarial results for the defined
benefit pension plans of Mirant (in millions):

F-49

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The components of Mirant's net periodic pension plans' cost during the
years ended December 31 are shown below (in millions).

OTHER POSTRETIREMENT BENEFITS

Mirant also provides certain medical care and life insurance benefits for
eligible domestic retired employees.

Under SFAS No. 106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions," postretirement medical care and life insurance benefits
for employees are accounted for on an accrual basis using an actuarial method,
which recognizes the net periodic cost as employees render service to earn the
postretirement benefits.

In measuring the accumulated postretirement benefit obligation, the
weighted average medical care cost trend rate for pre-age 65 participants and
post-age 65 participants was assumed to be 9.3% and 12.6%, respectively, for
2002, decreasing gradually to 5.50% and 5.50%, respectively, 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 accumulated benefit obligation at September 30, 2002 by $9 million
and $8 million, respectively.

Other weighted average rates assumed in the actuarial calculations for the
other postretirement benefits of Mirant's domestic employees as of their
respective measurement dates were as follows:

F-50

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The domestic postretirement benefits were unfunded at December 31, 2002 and
2001. The components of the net expense for Mirant's postretirement benefit
plans' during the years ended December 31 are shown below (in millions).

JPSCo provides certain medical care and life insurance benefits for its
eligible retired employees. At December 31, 2002 the accumulated postretirement
benefit obligation was $6 million based on a discount rate of 9.0%, rate of
compensation increase of 7.0% and rate of increase of health care costs of 7.0%.

An annual increase or decrease in the assumed rate of increase of health
care costs of 1% would correspondingly increase or decrease the accumulated
benefit obligation for JPSCo at December 31, 2002 by $1 million and $1 million,
respectively.

The postretirement benefits provided by JPSCo were unfunded at December 31,
2002.

Grand Bahama Power does not provide postretirement benefits other than
pensions for its employees.

STOCK-BASED COMPENSATION

Pursuant to SFAS No. 123, Mirant has elected to account for its stock-based
compensation plan under APB Opinion No. 25, "Accounting for Stock Issued to
Employees" and adopt the disclosure-only provisions of SFAS No. 123. Accounting
for cash-settled awards under SFAS No. 123 is consistent with the accounting for
such awards under APB Opinion No. 25.

MIRANT CORPORATION 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 Mirant options granted is equal to the stock price on the
date of grant.

F-51

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A summary of options granted, exercised and forfeited is as follows:

- ---------------

(1) The 2001 grants include 2,177,258 options that were granted to replace
2,028,533 Southern stock options as discussed below.

The following table provides information with respect to stock options
outstanding at December 31, 2002:

F-52

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The weighted average fair value at date of grant for options granted during
2002, 2001 and 2000 was $5.80, $10.06 and $7.94, respectively, and was estimated
using the Black-Scholes option valuation model with the following weighted
average assumptions:

MIRANT CORPORATION PHANTOM STOCK AND RESTRICTED STOCK

During 2002 and 2001, respectively, Mirant made awards of 1,244,185 and
235,893 shares of phantom stock and restricted stock to certain employees and
officers. The vesting for the phantom stock awards is based on stock price
appreciation, and the outstanding units as of December 31, 2002 have hurdle
prices ranging from $14.53 to $51.20. The vesting for 300,000 shares of Mirant
restricted stock is based on time and will vest between October 2004 and October
2006. Compensation expense recognized during 2002, 2001 and 2000 was
approximately $5 million, $15 million and $2 million, respectively. A summary of
phantom stock and restricted stock is as follows:

SOUTHERN STOCK-BASED COMPENSATION

Stock option grants to purchase Southern common stock were previously made
from Southern's performance stock plan. These grants vested equally on each of
the first, second and third anniversaries of the grant date, and fully vested
upon termination resulting from death, total disability or retirement. The
exercise price was determined based on the average of the high and low fair
market value of Southern's common stock on the date granted. All of the
outstanding Southern stock options were converted to Mirant stock options on
April 2, 2001.

F-53

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table provides information with respect to Southern options:

The weighted average fair values at date of grant for Southern stock
options granted during 2001 and 2000 were $4.37 and $3.36, respectively, and
were estimated using the Black-Scholes option valuation model with the following
weighted-average assumptions:

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. Under the terms of
the ESPP, which was adopted in September 2000, 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 985,421 and 913,426 shares to employees in 2002 and 2001,
respectively. Compensation cost is recognized for the fair value of the
employees' purchase rights, which was estimated using the Black-Scholes model
with the following weighted average assumptions for 2002, 2001 and 2000,
respectively: dividend yield of 0% for all years; an expected life of 0.5 years
for all plan cycles; expected volatility of 136%, 106% and 40%; and risk-free
interest rates of 1.474%, 2.800% and 6.295%. The weighted-average fair value of
the purchase rights granted in 2002, 2001 and 2000 was $2.75, $29.18 and $18.70,
respectively.

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

F-54

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 matching
and profit sharing contributions were as follows (in millions):

13. COMPANY OBLIGATED MANDATORILY REDEEMABLE SECURITIES OF A SUBSIDIARY HOLDING
SOLELY PARENT COMPANY SUBORDINATED DEBENTURES

In October 2000, Mirant Trust I sold 6.9 million shares of 6.25%
convertible trust preferred securities at $50.00 per share, for total proceeds
of $345 million. The net proceeds from the offering, after deducting
underwriting discounts and commissions payable by Mirant, were $334 million.
Mirant issued debentures to the trust with a principal amount equal to the
principal amount of the preferred securities.

The subordinated debentures are unsecured and exclusive obligations of
Mirant Corporation. The subordinated debentures are not supported by guarantees
or other commitments of subsidiaries of Mirant Corporation. Mirant Corporation
has guaranteed the payment obligations of Mirant Trust I on the preferred
securities but only to the extent the Mirant Trust I has sufficient funds to
make such payments. Mirant Corporation can defer interest payments on the
subordinated debentures for up to 20 consecutive quarterly periods (but not
beyond October 1, 2030) unless an event of default on the subordinated
debentures has occurred and is continuing. If Mirant Corporation defers interest
payments on the subordinated debentures, Mirant Trust I will defer distribution
payments on the preferred securities. During a deferral period, distributions
continue to accumulate on the preferred securities. Additional cash
distributions accumulate on any deferred distributions and compound interest
accrues on any deferred interest payments on the subordinated debentures. While
interest payments on the subordinated debentures are deferred, Mirant
Corporation generally is not permitted to pay cash dividends on its common stock
or pay debt that is pari passu with or junior to the subordinated debentures.

The preferred securities are reported as company obligated mandatorily
redeemable securities of a subsidiary holding solely parent company subordinated
debentures in the accompanying consolidated balance sheets. Cash distributions
on the preferred securities are payable quarterly in arrears at an annual rate
of 6.25% of the $50,000 liquidation preference per share. These distributions
are reported as a component of "Minority Interest" in the accompanying
consolidated statements of operations.

Holders of preferred securities have the right to convert the preferred
securities into shares of the Company's common stock at any time prior to
October 1, 2030. The preferred securities are convertible into Mirant's common
stock at an initial conversion rate of 1.8182 shares of common stock for each
preferred security. This conversion rate is equivalent to the conversion price
of $27.50 per share of its common stock. The initial conversion rate may be
subject to adjustment. Upon conversion of a preferred security, a corresponding
debenture held by the trust will be canceled.

Mirant may redeem all or some of the preferred securities at any time on or
after October 1, 2003 by redeeming the subordinated debentures at the applicable
redemption price, plus any accrued and unpaid distributions; provided that
Mirant may only redeem the subordinated debentures if the closing price of its
common stock exceeds 125% of the conversion price for a specified period of time
before the notice of redemption is given.

F-55

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

14. STOCKHOLDERS' EQUITY

COMMON STOCK

In December 2001, Mirant completed a public offering of 60 million shares
of its common stock for a price of $13.70 per share. The net proceeds from the
offering, after deducting underwriting discounts and commissions payable by
Mirant, were $759 million.

In September 2001, Mirant's Board of Directors approved the repurchase of
up to 10 million shares of its common stock. The authorization was effective for
a period of 30 days. Pursuant to the authorization, 100,000 shares of its common
stock were purchased for approximately $2 million in the open market.

During 2000, Mirant completed an initial public offering of 66.7 million
shares of its common stock for a price of $22.00 per share. The net proceeds
from the offering, after deducting underwriting discounts and commissions
payable by Mirant, were $1.38 billion.

COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes unrealized gains and losses on certain
derivatives that qualify as cash flow hedges and hedges of net investments, the
translation effects of foreign net investments and adjustments for additional
minimum pension liabilities and share of other comprehensive income or loss of
affiliates. Components of accumulated other comprehensive loss consisted of the
following (in millions):

BALANCE, DECEMBER 31, 1999.................................. $ (95)
Other comprehensive income (loss) for the period:
Cumulative translation adjustment (as restated)........... (21)
------
Other comprehensive loss (as restated).................... (21)
------
BALANCE, DECEMBER 31, 2000, AS RESTATED..................... (116)
Other comprehensive income (loss) for the period:
Transitional adjustment from adoption of SFAS No. 133, net
of tax effect of $259 (as restated).................... (363)
Net change in fair value of derivative financial
instruments, net of tax effect of $31 (as restated).... (49)
Reclassification to earnings, net of tax effect of $(209)
(as restated).......................................... 305
Cumulative translation adjustment (as restated)........... (6)
Share of other comprehensive income of affiliates (as
restated).............................................. 7
------
Other comprehensive loss (as restated).................... (106)
------
BALANCE, DECEMBER 31, 2001, AS RESTATED..................... (222)
Other comprehensive income (loss) for the period:
Net change in fair value of derivative hedging
instruments, net of tax effect of $4................... (16)
Reclassification of derivative net gains to earnings, net
of tax effect of $(22)................................. 41
Cumulative translation adjustment......................... 109
Minimum pension liability adjustment...................... (2)
Share of other comprehensive income of affiliates......... (12)
------
Other comprehensive income.................................. 120
------
BALANCE, DECEMBER 31, 2002.................................. $ (102)
======

F-56

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The $102 million balance of accumulated other comprehensive loss as of
December 31, 2002 includes the impact of a $3 million loss related to interest
rate hedges, a $66 million loss related to deferred interest rate swap hedging
losses, $24 million of foreign currency translation losses, $7 million
representing Mirant's share of accumulated other comprehensive losses of
unconsolidated affiliates and $2 million of minimum pension liability.

Mirant estimates that $9 million of after-tax losses relating to interest
rate hedges included in OCI as of December 31, 2002 will be reclassified into
earnings or otherwise settled within the next twelve months as certain
transactions relating to interest payments are realized.

Mirant was exposed to currency risks associated with its investment in
CEMIG in Brazil. These risks were not hedged due to the high cost and the
uncertain effectiveness of implementing such a hedge. In December 2002, the
Company sold its investment in CEMIG (See Note 7). As a result, currency
translation losses of approximately $84 million previously included in OCI were
recognized in the 2002 statement of operations.

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
ultimate amount of potential losses. 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.

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 (the "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 Department of Justice, 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, Potential FERC Show Cause Proceedings Arising Out of Its
Investigation of Western Power Markets, and DWR Power Purchases, relating to its
operations in California and the western power markets. The Company has reserved
approximately $295 million for losses related to the Company's operations in
California and the western power markets during 2000 and 2001. Resolution of
these matters 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 ("SCE") and
Pacific Gas and Electric ("PG&E") suspended payments to the California Power
Exchange Corporation ("PX") and CAISO for certain power purchases, including
purchases from Mirant. Both the PX and PG&E filed for bankruptcy

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

protection in 2001. As of December 31, 2002, the Company has outstanding
receivables for power sales made in California totaling $352 million. The
Company does not expect any payments to be received for these sales until the
FERC issues final rulings regarding the related matters discussed in the next
paragraph.

In July 2001, the FERC issued an order requiring hearings to determine the
amount of any refunds and amounts owed for sales made to the CAISO or the PX
from October 2, 2000 through June 20, 2001. Various parties have appealed these
FERC orders to the United States Court of Appeals for the Ninth Circuit seeking
review of a number of issues, including changing the potential refund date to
include periods prior to October 2, 2000 and expanding the sales of electricity
subject to potential refund to include sales made to the DWR. On December 12,
2002, an administrative law judge ("ALJ") determined the preliminary amounts
currently owed to each supplier in the proceeding. The ALJ determined that the
CAISO and the PX owed Mirant approximately $122 million, which is net of refunds
owed by Mirant to the CAISO and the PX. The ALJ decision indicated that these
amounts do 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 and other sellers by
the PX 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 by the PX, and the net amount owed Mirant by the
CAISO and the PX after taking into account the proposed refunds, would increase
by approximately $37 million.

On March 3, 2003, the California Attorney General, the EOB, the CPUC, PG&E
and SCE (the "California Parties") filed submittals with the FERC in the
California refund proceeding alleging that owners of generating facilities in
California and energy marketers, including Mirant entities, had engaged in
extensive manipulation of the California wholesale electricity market during
2000 and 2001. The California Parties argued that the FERC should expand the
transactions subject to the refund proceeding to include short-term and
long-term bilateral transactions entered into by the DWR that were not conducted
through the CAISO and PX and should begin the refund period as of January 1,
2000 rather than October 2, 2000. Expansion of the scope of the transactions
subject to refund in the manner sought by the California Parties could
materially affect the amount of any refunds that Mirant might be determined to
owe, and any such additional refunds could negatively impact the Company's
consolidated financial position, results of operations or cash flows. On March
20, 2003, the Company filed reply comments denying that it had engaged in any
conduct that violated the Federal Power Act or any tariff provision applicable
to its transactions in California. The Company stated that the purported
evidence presented by the California Parties did not support the allegations
that it had engaged in market manipulation, had violated the Federal Power Act
or had not complied with any applicable tariff or order of the FERC.

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 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 and therefore to reduce the net
amount that would remain owed to Mirant from the CAISO and 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 by the CAISO and PX to approximately $49 million. The
FERC will 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 intends to demonstrate to the
FERC that its actual
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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, although the amount of such potential decrease and the resulting net
amount owed to Mirant cannot at this time be determined. In its March 26, 2003
order, the FERC also ruled that any future findings of market manipulation
resulting from its ongoing review of conduct in the California market in 2000
and 2001 discussed below in Potential FERC Show Cause Proceedings Arising Out of
Its Investigation of Western Power Markets would not result in a resetting of
the refund effective date or the mitigated market prices developed for the
refund period. Instead, the remedy for any such market manipulation that is
found to have occurred will be disgorgement of profits and other appropriate
remedies and such remedies could apply to conduct both prior to and during the
refund period. Various parties, including the California parties, have filed
motions with the FERC seeking rehearing of the FERC's March 26, 3002 order. The
amount owed to Mirant from either the CAISO or the PX, the amount of any refund
that Mirant might be determined to owe to the CAISO or the PX, and whether
Mirant 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.

Potential FERC Show Cause Proceedings Arising Out of Its Investigation of
Western Power Markets: On March 26, 2003, the FERC stated at its meeting that it
would consider issuing show cause orders to those entities that a FERC Staff
report issued on March 26, 2003 indicated may have engaged in one or more of the
trading strategies of the type portrayed in the Enron memos released by the FERC
in May 2002, which would include Mirant. The show cause order, if issued, could
require Mirant to demonstrate why it should not have to disgorge any profits
obtained from such practices in the California market from January 1, 2000
through June 20, 2001. The FERC further stated that it would consider issuing
additional show cause orders to those entities, including Mirant, that the staff
report identified as having bid generation resources to the PX and CAISO at
prices unrelated to costs. That show cause order, if issued, could require
Mirant to demonstrate why its bidding behavior in the PX and CAISO markets from
May 1, 2000 through October 1, 2000 did not constitute a violation of the CAISO
and PX tariffs and why it should not be required to disgorge any profits
resulting from such bidding practices. If Mirant is found by the FERC to have
engaged in any market manipulation or to have otherwise violated the PX or CAISO
tariffs, the amount of any disgorgement of profits required or other remedy
imposed by the FERC could negatively impact the Company's consolidated financial
position, results of operations or cash flows.

DWR Power Purchases: On May 22, 2001, Mirant 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. On February 25,
2002, the CPUC and the EOB filed separate complaints at the FERC against Mirant
and other sellers of energy under long-term agreements with the DWR, alleging
that the terms of these contracts are 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 December
17, 2002, the FERC issued an order indicating that it will rule upon the
complaint with respect to the contracts of certain parties, including Mirant,
without first obtaining an initial decision from an ALJ. If the FERC were to
determine that the rate charged by Mirant in its May 22, 2001 contract with the
DWR was unreasonable and therefore required refunds to be made, such refunds
could be material to the Company's consolidated financial position, results of
operations and cash flows.

"Reliability-Must-Run" Agreements: Certain of the Company's generating
facilities acquired from PG&E are operated subject to reliability-must-run
("RMR") agreements. These agreements allow the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CAISO to require the Company, under certain conditions, to operate these
facilities to support the California electric transmission system. Mirant
assumed these agreements from PG&E subject to the outcome of a 1997 FERC
proceeding to determine the amount of the charges to be paid by the CAISO under
the agreements with respect to those plants out of which Mirant could also
receive additional revenues from market sales. For those plants that are subject
to the RMR agreements and from which Mirant has exercised its right to also make
market sales, Mirant has been collecting from the CAISO since April 1999 an
amount equal to fifty percent of the annual fixed revenue requirement of those
plants. The amounts the Company collects from the CAISO are subject to refund
pending final review and approval by the FERC. In June 2000, an ALJ issued a
decision finding that the amount the Company should be allowed to charge the
CAISO for such plants was approximately three and one-half percent of the annual
fixed revenue requirement. In July 2000, Mirant sought review by the FERC of the
ALJ decision, and a decision is pending at the FERC.

The Company recognizes revenue related to these agreements based on the
rates ruled to be reasonable by the ALJ. If the Company is unsuccessful in its
appeal of the ALJ's decision, it will be required to refund amounts collected in
excess of those rates for the period from June 1, 1999. For the Potrero plant
the period for which such refunds would be owed would run through December 31,
2001, for Mirant'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 the final disposition of the appeal. Amounts collected
in excess of those rates, which totaled $328 million and $219 million,
respectively, as of December 31, 2002 and 2001, are deferred and included in
accounts payable in the accompanying consolidated balance sheets. In addition,
the Company records accrued interest on such amounts, which amounted to $36
million and $24 million, respectively, as of December 31, 2002 and 2001, and
includes such amounts in accounts payable in the accompanying consolidated
balance sheets. If resolution of the proceeding results in refunds of that
magnitude and the Company were unable to arrange to make the refunds over a
multi-year period, it would have a material impact on the Company's liquidity;
however it would have no effect on net income for the periods under review as
adequate reserves have been recorded.

In the Fall of 2001, the Company filed with the FERC to increase the amount
of the annual fixed revenue requirement for the generating assets subject to the
RMR agreements. On February 5, 2003, FERC approved a settlement agreement
setting the annual fixed revenue requirement for the plants subject to the RMR
agreements through 2004. The settlement agreement will result in refunds being
made by the Company of a portion of the amounts collected by the Company for
2002. The amount of such refunds will not materially exceed the amounts
currently being reserved for by the Company that are described above.

SHAREHOLDER LITIGATION

Twenty lawsuits have been filed since May 2002 against Mirant and four of
its officers alleging, among other things, that defendants violated federal
securities laws by making material misrepresentations and omissions to the
investing public regarding Mirant's business operations and future prospects.
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 Company, 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 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.

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Under its separation agreement with Southern Company, Mirant indemnified
Southern Company against losses arising from acts or omissions by Mirant in the
conduct of its business. Under various underwriting agreements, Mirant has also
indemnified certain underwriters named in these lawsuits for losses arising from
acts or omissions by Mirant in the conduct of its business.

SHAREHOLDER DERIVATIVE LITIGATION

Four purported shareholders' derivative suits have been filed against
Mirant, its directors and certain officers. These lawsuits allege 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 in the shareholder litigation, the rate payer litigation, and the
California attorney general lawsuits discussed above.

ERISA LITIGATION

On April 17, 2003, a purported class action lawsuit alleging violations of
ERISA was filed in the United States District Court for the Northern District of
Georgia entitled James Brown v. Mirant Corporation, et al., Civil Action No.
1:03-CV-1027 (the "ERISA Litigation"). The ERISA Litigation names as defendants
Mirant Corporation, certain of its current and former officers and directors,
and Southern Company. The plaintiff, who seeks to represent a putative class of
participants and beneficiaries of Mirant's 401(k) plans (the "Plans"), alleges
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 plaintiff seeks
unspecified damages, injunctive relief, attorneys' fees and costs. The factual
allegations underlying this lawsuit are substantially similar to those described
above in California Attorney General Litigation, California Rate Payer
Litigation, and Shareholder Litigation.

UNITED STATES GOVERNMENT INQUIRIES

In August 2002, Mirant received a notice from the Division of Enforcement
of the Securities and Exchange Commission ("SEC") that it was conducting an
informal investigation of Mirant. The Division of Enforcement has asked for
information and documents relating to various topics such as accounting issues
(including the issues announced 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. Mirant intends to cooperate fully with the Securities
and Exchange Commission.

In addition, the Company has been contacted by the United States Department
of Justice regarding the Company's disclosure of accounting issues, energy
trading matters and allegations contained in the amended complaint discussed
above in Shareholder Litigation 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
informal inquiry, and the Company intends to cooperate fully.

In August 2002, the Commodities Futures Trading Commission ("CFTC") asked
the Company for information about certain buy and sell transactions occurring
during 2001. The Company provided information regarding such trades to the CFTC,
none of which it considers to be wash trades. The CFTC subsequently requested
additional information, including information about all trades conducted on the
same day with the same counterparty that were potentially offsetting during the
period from January 1, 1999 through June 17, 2002, which information the Company
provided. In March 2003, the Company received a subpoena from the CFTC
requesting a variety of documents and information related to the
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Company'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. Among the documents requested are any
documents previously produced to the FERC, the SEC, the Department of Justice,
any state's Attorney General, and any federal or state grand jury. The Company
intends to cooperate fully with the CFTC.

PANDA-BRANDYWINE POWER PURCHASE AGREEMENT

In connection with the Company's acquisition of the Mid-Atlantic assets
from PEPCO in 2000, PEPCO granted the Company certain rights to purchase from
PEPCO all power it received under a power purchase agreement between it and
Panda-Brandywine L.P. ("Panda"). Mirant agreed in return to pay PEPCO amounts
equal to the amounts owed by PEPCO to Panda for that power. In July 2002, the
Maryland Court of Special Appeals ruled that the contractual arrangement between
Mirant and PEPCO resulted in PEPCO improperly assigning its contract with Panda
to Mirant. However, the Court of Special Appeals also ruled that the Maryland
Public Service Commission has the authority to approve the assignment on public
policy grounds. In December 2002, the Maryland Court of Appeals, its highest
court, granted petitions filed by PEPCO and Panda to appeal the decision of the
Court of Special Appeals. Mirant had also entered into an agreement with PEPCO
that provided if the agreement between Mirant and PEPCO with respect to the
power received under the Panda agreement was voided by a binding court order
prior to March 2005, the price paid by Mirant for its December 2000 acquisition
of PEPCO assets would be adjusted to compensate PEPCO for the termination of
that arrangement but to hold Mirant economically indifferent. Consequently, an
adverse ruling may have a material adverse effect on the Company's liquidity but
would not be expected to have a material adverse effect on its financial
position or results of operations.

ENRON BANKRUPTCY PROCEEDINGS

Since December 2, 2001, Enron and a number of its subsidiaries have filed
for bankruptcy. As of December 31, 2002, the total amount owed to Mirant by
Enron was approximately $72 million. Mirant has filed formal claims in the Enron
bankruptcy proceedings. Based on a reserve for potential bad debts recorded in
2001, the Company does not expect the outcome of the bankruptcy proceeding to
have a material adverse effect on the Company's consolidated financial position,
results of operations or cash flows.

EDISON MISSION ENERGY 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. EME seeks damages in excess of $50 million, plus
interest and attorneys' fees. The Company believes it did not breach its
agreement with EME. 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 to purchase an additional 47.5% ownership interest in
EcoElectrica. That purchase also was not completed.

ENVIRONMENTAL LIABILITIES

In 2000, the State of New York issued a notice of violation concerning air
permitting and air emission control implications under the Environmental
Protection Agency's ("EPA") new source review regulations promulgated under the
Clean Air Act ("NSR") to the previous owner of Mirant New York's Lovett facility
related to operation of that plant prior to its acquisition by Mirant New York.
The notice does not specify corrective actions that the state may require.
Mirant New York is currently engaged in discussions

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

with the state to try to resolve this matter. In January 2001, the EPA requested
information from Mirant concerning the air permitting and air emission control
implications under NSR of repair and maintenance activities at the Company's
Potomac River plant in Virginia and Chalk Point, Dickerson, and Morgantown
plants in Maryland related to operation of those plants prior to their
acquisition by the Company.

If violations are determined to have occurred at these plants, the previous
owners would be responsible for fines and penalties arising from such violations
occurring prior to their acquisition by the Company. If a violation is
determined to have occurred after the Company acquired the plants or, if
occurring prior to the acquisition, is determined to constitute a continuing
violation, the Company would be subject to fines and penalties by the state or
federal government for the period subsequent to its acquisition of the plants,
the cost of which could be material. In the event violations are determined to
have occurred, the Company may be responsible for the costs of acquiring and
installing emission control equipment, the costs of which may be material. Such
costs would generally be capitalized and amortized as a component of property,
plant and equipment.

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.

16. COMMITMENTS AND CONTINGENCIES

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

LETTERS OF CREDIT AND CASH COLLATERAL

In order to participate in commodity trading activities in the market,
companies, in general, are required to provide trade credit support to their
counterparties. Trade credit support includes letters of credit provided on
behalf of Mirant Americas Energy Marketing and cash collateral. The total amount
of letters of credit issued in connection with commodity trading contracts was
$674 million as of December 31, 2002. None of these letters of credit were drawn
on as of December 31, 2002. The letters of credit expire in 2003. Upon
expiration, these letters of credit for the commodity trading activities of
Mirant Americas Energy Marketing may be renewed by Mirant Corporation or
replaced with another form of support to the counterparty, if required.

As of December 31, 2002, Mirant Corporation had posted $95 million in cash
collateral for commodity trading contracts. In the event of default by Mirant
Americas Energy Marketing, the counterparty can draw on the collateral to
satisfy the existing amounts outstanding under an open contract.

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CONTRACTUAL OBLIGATIONS

As of December 31, 2002, Mirant has the following annual commitments under
various agreements as follows (in millions):

Turbine Purchases and Other Construction-Related Commitments

Mirant has entered into commitments to purchase turbine equipment, both
directly from the vendor and through two equipment procurement facilities.

During the first quarter of 2002, Mirant committed to a restructuring plan,
which included cancellation of certain turbine purchase commitments. The Company
recorded a restructuring accrual for turbine purchase commitments that were
expected to be canceled over the twelve-month period following the restructuring
commitment date. Until termination orders are issued, Mirant continues to have
the option to purchase the turbines. A summary of turbine purchase commitments
is as follows:

- ---------------

(1) The power island was terminated in January 2003.

The remaining aggregate commitments relating to turbine purchase
commitments at December 31, 2002 was $18 million. The cost to terminate the four
domestic lease turbines at December 31, 2002 was $70 million.
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Construction-Related Commitments

The Company has other construction-related commitments related to
developments at its various generation facility sites. At December 31, 2002,
these construction-related commitments totaled approximately $483 million.
Although the Company intends to complete these construction-related activities,
generally these commitments may be terminated by the Company. At December 31,
2002, the minimum cost to terminate these commitments was approximately $76
million.

Long-Term Service Agreements

Mirant has entered into long-term service agreements for the maintenance
and repair of many of its combustion-turbine generating plants. As of December
31, 2002, the total estimated commitments for long-term service agreements
associated with turbines installed or in storage were approximately $791
million. These commitments are payable over the term of the respective
agreements, which range from ten to twenty years. Some of these agreements have
terms that allow for cancellation of the contract at mid-term. If the Company
were to cancel these contracts at mid-term, the estimated commitments for the
remaining long-term service agreements would be reduced to approximately $638
million. Estimates for future commitments for the long-term service agreements
are based on the stated payment terms in the contracts at the time of execution.
These payments are subject to an annual inflationary adjustment.

As a result of the turbine cancellations during 2002, the long-term service
agreements associated with the canceled turbines have been or will be canceled.
Generally, if the associated turbine is cancelled prior to delivery, then these
agreements may be terminated at little or no cost.

Fuel Commitments

Mirant has a contract with BP whereby BP is obligated to deliver fixed
quantities of natural gas at identified delivery points. The negotiated purchase
price of delivered gas is generally equal to the monthly spot rate then
prevailing at each delivery point. Because this contract is based on the monthly
spot price at the time of delivery, Mirant has the ability to sell the gas at
the same spot price, thereby offsetting the full amount of its commitment
related to this contract. In July 2002, Mirant and BP restructured this
contract. The contract term has been extended to December 31, 2009, unless
terminated sooner. Mirant has the ability to reduce the purchase obligation on
this contract annually. Based on current contract volumes, the estimated minimum
commitment for the term of this agreement based on current spot prices is $2.1
billion as of December 31, 2002. The Company has entered into a master netting
agreement which provides that the amounts due to BP under the contract will be
netted against payments due between Mirant and BP under various other gas and
power contracts, and that collateral will be posted by one party for the benefit
to the other based on the net amount of credit exposure.

In April 2002, Mirant Mid-Atlantic entered into a long-term fuel purchase
agreement. The fuel supplier will convert 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, 2002, total estimated minimum commitments under
this agreement were $509 million.

In addition to the coal commitment described above, Mirant has fixed
volumetric purchase commitments under fuel purchase and transportation
agreements, which are in effect through 2012, totaling $467 million at December
31, 2002. Approximately $344 million of these commitments relates to an
arrangement between Mirant Americas Energy Marketing and the synthetic fuel
supplier whereby the

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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. Since the inception of this arrangement, the synthetic fuel
supplier has purchased 100% of Mirant Americas Energy Marketing's minimum coal
purchase commitment thereby reducing the amount of coal required to be purchased
under the contracts.

Operating Leases

In conjunction with the purchase of the PEPCO assets, the Company, through
Mirant Mid-Atlantic, leased the Morgantown and the Dickerson baseload units and
associated property. The leases are for terms of 28.5 and 33.75 years,
respectively. Mirant Mid-Atlantic is accounting for these leases as operating
leases. Rent expenses associated with the Dickerson and Morgantown operating
leases totaled approximately $96 million for each of the years ended December
31, 2002 and 2001. As of December 31, 2002, the total notional minimum lease
payments for the remaining life of the leases was approximately $2.7 billion.

The owner lessors of the Dickerson and Morgantown baseload units have
issued notes backed by the leases. The lease payment obligations are unsecured
and exclusive obligations of Mirant Mid-Atlantic. Except as described below, the
lease obligations are not supported by guarantees or other commitments of Mirant
Corporation or any of its subsidiaries to pay amounts due under such credit
facilities or to provide Mirant Mid-Atlantic with funds for the payment, whether
by dividends, distributions, loans or other payments. Pursuant to a capital
contribution agreement, Mirant Corporation has agreed to make capital
contributions to Mirant Mid-Atlantic of cash available for distribution from
Mirant Peaker and Mirant Potomac River. The agreement contains a number of
restrictive covenants, including (i) restrictions on asset sales, (ii)
restrictions on mergers, consolidations or sales of all or substantially all the
assets, (iii) restrictions on liens, except for permitted liens, (iv)
maintenance of properties, (v) maintenance of tax status, (vi) maintenance of
insurance, (vii) limitations on transactions with affiliates, based on projected
ratio calculations, (viii) restrictions on dividends and distributions and (ix)
limitations on the incurrence of debt, other than permitted debt.

Mirant Mid-Atlantic has an option to renew the lease for a period that
would cover up to 75% of the economic useful life of the facility, as measured
near the end of the lease term. However, the extended term of the lease will
always be less than 75% of the revised economic useful life of the facility.

Upon an event of default under the lease documents, the lessors are
entitled to a termination value payment as defined in the agreements. At
December 31, 2002, the termination value was approximately $1.5 billion, which,
in general, declines over time. Upon expiration of the original lease term, the
termination value will be $300 million.

Mirant has commitments under other operating leases with various terms and
expiration dates. Minimum lease payments under non-cancelable operating leases
approximate $38 million in 2003, $36 million in 2004, $36 million in 2005, $35
million in 2006, $32 million in 2007, and $266 million thereafter. Expenses
associated with these commitments totaled approximately $53 million, $28 million
and $17 million during 2002, 2001 and 2000, respectively.

MINORITY SHAREHOLDER PUT OPTION

The Sual project ("MSC") and the Pagbilao project ("MPagC") 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 MSC put
options, collectively representing the remaining 8.09% ownership interest in the
Sual project, can be exercised between December 21, 2002 and December 21, 2005,
or in the event of any change in control, a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

change in MSC'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 MPagC put options, collectively representing the
remaining 12.78% ownership interest in the Pagbilao project, can be exercised
between August 5, 2002 and August 5, 2008 or, in the event of any change in
control, a change in MPagC's charter documents or the transfer of the sponsor in
violation of the sponsor completion support agreement. The MPagC put option may
be exercised on the earlier of the date of such changes/events or August 5,
2008. The price for the put options would be determined by a formula including
discounted future net cash flow less total liabilities plus current assets as of
the date of the put notice. Two of the three Pagbilao project minority
shareholders have served notice to exercise their respective put options.
Subsequent to December 31, 2002, Mirant Asia-Pacific Limited's subsidiary paid
approximately $30 million to acquire an additional 4.26% ownership interest in
the Pagbilao project. The remaining minority interest subject to the put
agreement is 8.52%.

EMPLOYEE CONTRACTS

Certain executives of the Company have contracts, which generally provide
benefits in the event of termination or involuntary termination for "good
reason" accompanied by a change in control of Mirant, as defined. Employment
agreements provide for severance payments not in excess of three times annual
base salary and bonus and the continuation for stipulated periods of other
benefits. Upon a preliminary change in control, a Rabbi trust is funded to
protect the benefits described above for all covered employees.

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, which consist of
five power purchase agreements ("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.

The PPAs, which are with parties unrelated to PEPCO, 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 earnings. The
Company recognized $35 million of unrealized gains in 2002 and $211 million of
unrealized losses in 2001 in connection with the PPA's. At December 31, 2002,
the estimated commitments under the PPA agreements were $1.47 billion based on
the total remaining MW commitment at contractual prices. As of December 31,
2002, the fair value of the PPAs recorded in price risk management liabilities
in the consolidated balance sheet totaled $880 million, of which $142 million is
classified as current.

The TPA agreements state that Mirant will sell a quantity of megawatt-hours
over the life of the contracts based on PEPCO's load requirements. The TPA
agreement related to load in Maryland expires in June 2004, while the TPA
agreement related to load in the District of Columbia expires in January 2005.
The proportion of megawatt-hours supplied under the two agreements is currently
64% and 36%, respectively. As actual megawatt-hours 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 $423 million, $417 million,
and $12 million during the years ended December 31, 2002, 2001 and 2000. The
remaining TPA obligation will be amortized as an increase in revenue through
January 2005. As of December 31, 2002, the remaining

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

obligations for the TPAs recorded in obligations under energy delivery and
purchase commitments totaled $883 million, of which $498 million is classified
as current.

Other obligations of approximately $19 million related to other
out-of-market contracts are also recorded in obligations under energy delivery
and purchase commitments in the consolidated balance sheet at December 31, 2002,
of which $6 million is current.

18. RELATED-PARTY ARRANGEMENTS AND TRANSACTIONS

SOUTHERN COMPANY AGREEMENTS AND TRANSACTIONS

Prior to Mirant's spin-off from Southern Company in 2001, Mirant had
agreements with Southern Company Services, Inc. ("SCS") a wholly owned
subsidiary of Southern Company, and each of the system operating companies owned
by Southern Company ("Southern") under which those companies provided various
services to Mirant. These transitional services agreements generally provided
for a fee equal to the greater of the cost, including the actual direct and
indirect costs, of providing the services or the market value for such services.
Management believes that the costs incurred are substantially similar to the
costs the Company would have incurred on a stand-alone basis. During 2001, SCS
provided primarily administrative services to Mirant at cost. During 2000, SCS
and each of Southern's operating companies provided the following services to
Mirant at cost: general engineering, design engineering, accounting and
statistical budgeting, business promotion and public relations, systems and
procedures, training, and administrative and financial services. Such costs
amounted to approximately $4 million and $21 million during 2001 and 2000,
respectively. Included in these costs are both directly incurred costs and
allocated costs prior to Mirant's separation from Southern. The allocated costs
are based on a variety of factors, including employee headcount, net fixed
assets, operating expenses, operating revenues and other cost causal methods.
The allocated costs related to SCS's corporate general and administrative
overhead were less than $1 million for 2001 and amounted to approximately $7
million during 2000. Mirant also incurred interest expense on a note payable to
Southern of $1 million during 2000.

In addition to the transactions above, the Company also earned interest
income from Southern during 2001 and 2000 related to a note receivable from
Southern. During 2001 and 2000, interest income was $12 million and $75 million,
respectively. This note receivable was transferred to Southern as part of the
Company's separation from Southern in April 2001.

MIRANT AMERICAS ENERGY MARKETING AGREEMENTS

Prior to taking full ownership of Mirant Americas Energy Marketing, Mirant
had various agreements with Mirant Americas Energy Marketing in which Mirant
Americas Energy Marketing had agreed to develop and manage the bidding strategy,
manage fuel requirements, sell the energy and provide accounting and settlement
services for several generating plants of Mirant. These agreements applied to
Mirant's California, New York and New England operating entities and generally
covered a term of 1 to 2.5 years. During 2000, prior to taking full ownership of
Mirant Americas Energy Marketing, total fees paid under the marketing
arrangements totaled $52 million, and payments made for fuel to Mirant Americas
Energy Marketing totaled $261 million. The payments to Mirant Americas Energy
Marketing prior to the Company's 100% acquisition in 2000 were ordinary
purchases of fuel, which management believes would have approximated the costs
the Company would have incurred on a stand-alone basis.

During 2000, prior to acquiring the minority interest in Mirant Americas
Energy Marketing, Mirant's revenues and expenses related to its agreements with
Mirant Americas Energy Marketing were $767 million and $313 million,
respectively. Intercompany profits and losses recognized by Mirant Americas
Energy Marketing on a mark-to-market accounting basis have been appropriately
eliminated in consolidation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 each of 2002
and 2001. 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 Company would have incurred with an unrelated party. Mirant completed the
sale of its 50% ownership interest in Perryville in June 2002.

Mirant has an operating and maintenance contract with respect to its
investment in Birchwood. Mirant has a 50% ownership interest in Birchwood and
accounts for its investment under the equity method. Fees paid to Mirant under
the Birchwood operating and maintenance contract were approximately $8 million
in each of 2002 and 2001. Management believes that the fees paid by Birchwood
for these services are equivalent to the fees that would be charged by an
unrelated party.

19. EARNINGS (LOSS) PER SHARE

Mirant calculates basic earnings (loss) per share by dividing the income
(loss) available to common stockholders by the weighted average number of common
shares outstanding. Diluted earnings (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 earnings (loss) per share for 2002, 2001
and 2000 (in millions, except per share data).

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MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following potential common shares were excluded from the earnings per
share calculations (in millions):

Historically, the Company has not considered the common shares that could
potentially be issued to redeem Mirant's $750 million in 2.5% convertible
debentures as potential common shares based upon the Company's intent and
ability at that time to redeem such debentures in cash. These securities could
result in the issuance of 11 million common shares, if redeemed with common
shares rather than cash.

20. SEGMENT REPORTING

The Company has two reportable segments: North America and International.
The North America segment consists of the Company's interrelated power
generation and commodity trading 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, including
Jamaica, the Bahamas, Curacao and Trinidad. 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 Company's reportable segments are
strategic businesses that are geographically separated and managed separately.
The accounting policies of the segments are the same as those described in the
Note 2 -- Accounting and Reporting Policies. Certain corporate costs, including
corporate overhead and interest are not allocated to a reporting segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

BUSINESS SEGMENTS

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MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-72

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-73

MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

GEOGRAPHIC AREAS

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MIRANT CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

21. VALUATION AND QUALIFYING ACCOUNTS

F-75

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on this 29th day of
April, 2003.

MIRANT CORPORATION

By: /s/ S. MARCE FULLER
------------------------------------
S. Marce Fuller
President and Chief Executive
Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below on April 29, 2003 by the following persons on
behalf of the registrant and in the capacities indicated.

* By attorney-in-fact.

CERTIFICATIONS

I, Marce Fuller, certify that:

1. I have reviewed this annual report on Form 10-K of Mirant Corporation;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

By: /s/ S. MARCE FULLER
------------------------------------
S. Marce Fuller
President and Chief Executive
Officer
(Principal Executive Officer)

Date: April 29, 2003

I, Harvey A. Wagner, certify that:

1. I have reviewed this annual report on Form 10-K of Mirant Corporation;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

By: /s/ HARVEY A. WAGNER
------------------------------------
Harvey A. Wagner
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: April 29, 2003