EDISON MISSION ENERGY - 10-K Annual Report

Back to GetFilings.com

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

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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

FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000

COMMISSION FILE NUMBER 1-13434

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

EDISON MISSION ENERGY
(Exact name of registrant as specified in its charter)

CALIFORNIA 95-4031807
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

18101 VON KARMAN AVENUE
IRVINE, CALIFORNIA 92612
(Address of principal executive (Zip Code)
offices)

Registrant's telephone number, including area code: (949) 752-5588

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

9 7/8% CUMULATIVE MONTHLY
INCOME PREFERRED SECURITIES, SERIES A* NEW YORK STOCK EXCHANGE
- ----------------------------------------------- -----------------------------------------------
(Title of Class) (name of each exchange on which registered)

8 1/2% CUMULATIVE MONTHLY
INCOME PREFERRED SECURITIES, SERIES B* NEW YORK STOCK EXCHANGE
- ----------------------------------------------- -----------------------------------------------
(Title of Class) (name of each exchange on which registered)

Securities registered pursuant to section 12(g) of the Act:
COMMON STOCK, NO PAR VALUE
(Title of Class)

* Issued by Mission Capital, L.P., a limited partnership in which Edison
Mission Energy is the sole general partner. The payments of distributions on
the preferred securities and payments on liquidation or redemption are
guaranteed by Edison Mission Energy.

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

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 registrant's 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.

Aggregate market value of the registrant's Common Stock held by
non-affiliates of the registrant as of March 30, 2001: $0. Number of shares
outstanding of the registrant's Common Stock as of March 30, 2001: 100 shares
(all shares held by an affiliate of the registrant).

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

TABLE OF CONTENTS

PAGE
------------

PART I

Item 1. Business.................................................... 1
Item 2. Properties.................................................. 36
Item 3. Legal Proceedings........................................... 37
Item 4. Submission of Matters to a Vote of Security Holders......... 38

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 39
Item 6. Selected Financial Data..................................... 42
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition........................ 43
Item 7a. Quantitative and Qualitative Disclosures about Market
Risk...................................................... 72
Item 8. Financial Statements and Supplementary Data................. 73
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 73

PART III

Item 10. Directors and Executive Officers of the Registrant.......... 123
Item 11. Executive Compensation...................................... 126
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................ 136
Item 13. Certain Relationships and Related Transactions.............. 137

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K.................................................. 138
Signatures.................................................. 171

i

PART I

ITEM 1. BUSINESS

THE COMPANY

We are an independent power producer engaged in the business of developing,
acquiring, owning or leasing and operating electric power generation facilities
worldwide. We also conduct energy trading and price risk management activities
in power markets open to competition. Edison International is our ultimate
parent company. Edison International also owns Southern California Edison
Company, one of the largest electric utilities in the United States.

We were formed in 1986 with two domestic operating projects. As of
December 31, 2000, we owned interests in 33 domestic and 40 international
operating power projects with an aggregate generating capacity of 28,036
megawatts (MW), of which our share was 22,759 MW. At that date, one domestic and
one international project, totaling 603 MW of generating capacity, of which our
anticipated share will be approximately 462 MW, were in construction. At
December 31, 2000, we had consolidated assets of $15.0 billion and total
shareholder's equity of $2.9 billion.

We are incorporated under the laws of the State of California. Our
headquarters and principal executive offices are located at 18101 Von Karman
Avenue, Suite 1700, Irvine, California 92612, and our telephone number is
(949) 752-5588. Unless indicated otherwise or the context otherwise requires,
references in this Annual Report on Form 10-K are with respect to Edison Mission
Energy and its consolidated subsidiaries and the partnerships or limited
liability entities through which Edison Mission Energy and its partners own and
manage their project investments.

FORWARD-LOOKING STATEMENTS

This annual report includes forward-looking statements. We have based these
forward-looking statements on our current expectations and projections about
future events based upon our knowledge of facts as of the date of this annual
report and our assumptions about future events. These forward-looking statements
are subject to various risks and uncertainties that may be outside our control,
including, among other things:

- the direct and indirect effects of the current California power crisis on
us and our investments, as well as the measures adopted and being
contemplated by federal and state authorities to address the crisis;

- general political, economic and business conditions in the countries in
which we do business;

- governmental, statutory, regulatory or administrative changes or
initiatives affecting us or the electricity industry generally;

- political and business risks of international projects, including
uncertainties associated with currency exchange rates, currency
repatriation, expropriation, political instability, privatization efforts
and other issues;

- supply, demand and price for electric capacity and energy in the markets
served by our generating units;

- competition from other power plants, including new plants and technologies
that may be developed in the future;

- operating risks, including equipment failure, dispatch levels,
availability, heat rate and output;

- the cost, availability and pricing of fuel and fuel transportation
services for our generating units;

- our ability to complete the development or acquisition of current and
future projects;

1

- our ability to maintain an investment grade rating; and

- our ability to refinance short-term debt or raise additional financing for
our future cash requirements.

We use words like "believe," "expect," "anticipate," "will," "estimate,"
"project," "plan" and similar expressions to help identify forward-looking
statements in this annual report.

For additional factors that could affect the validity of our forward-looking
statements, you should read "--Project Development--Risk Factors Associated with
the California Power Crisis," "--Project Development--Risk Factors Associated
with our Liquidity," "--Project Development--Risk Factors Associated with
Project Development, Finance and Operation," "Management's Discussion and
Analysis of Results of Operations and Financial Condition" and the "Notes to
Consolidated Financial Statements" contained in Part II, Item 8. The information
contained in this report is subject to change without notice. Readers should
review future reports filed by us with the Securities and Exchange Commission.
In light of these and other risks, uncertainties and assumptions, actual events
or results may be very different from those expressed or implied in the
forward-looking statements in this annual report or may not occur. We have no
obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or otherwise.

SEGMENT INFORMATION

We operate predominantly in one line of business, electric power generation,
with reportable segments organized by geographic region: Americas, Asia Pacific
and Europe, Central Asia, Middle East and Africa. Our plants are located in
different geographic areas, which mitigate the effects of regional markets,
economic downturns or unusual weather conditions. These regions take advantage
of the increasing globalization of the independent power market. See "Edison
Mission Energy and Subsidiaries Notes to Consolidated Financial Statements,
Note 17. Business Segments."

DESCRIPTION OF BUSINESS

GENERAL OVERVIEW

We are an independent power producer engaged in the business of developing,
acquiring, owning or leasing and operating electric power generation facilities
worldwide. We also conduct energy trading and price risk management activities
in power markets open to competition. Edison International is our ultimate
parent company. Edison International also owns Southern California Edison
Company, one of the largest electric utilities in the United States. We were
formed in 1986 with two domestic operating projects. As of December 31, 2000, we
owned interests in 33 domestic and 40 international operating power projects
with an aggregate generating capacity of 28,036 MW, of which our share was
22,759 MW. One domestic and one international project totaling 603 MW of
generating capacity, of which our anticipated share was approximately 462 MW,
were then in construction stage. At December 31, 2000, we had consolidated
assets of $15.0 billion and total shareholder's equity of $2.9 billion.

Until the enactment of the Public Utility Regulatory Policies Act of 1978,
utilities were the only producers of bulk electric power intended for sale to
third parties in the United States. The Public Utility Regulatory Policies Act
encouraged the development of independent power by removing regulatory
constraints relating to the production and sale of electric energy by certain
non-utilities and requiring electric utilities to buy electricity from certain
types of non-utility power producers, qualifying facilities, under certain
conditions. The passage of the Energy Policy Act of 1992 further encouraged the
development of independent power by significantly expanding the options
available to independent power producers with respect to their regulatory status
and by liberalizing transmission access. As a result, a significant market for
electric power produced by independent power producers, such as us, has
developed in the United States since the enactment of the Public Utility
Regulatory Policies Act. In

2

1998, utility deregulation in several states led utilities to divest generating
assets, which has created new opportunities for growth of independent power in
the United States.

The movement toward privatization of existing power generation capacity in
many foreign countries and the growing need for new capacity in developing
countries have also led to the development of significant new markets for
independent power producers outside the United States. We believe that we are
well-positioned to continue to realize opportunities in these new foreign
markets. See "--Strategic Overview".

RECENT DEVELOPMENTS

THE CALIFORNIA POWER CRISIS

Edison International, our ultimate parent company, is a holding company.
Edison International is also the corporate parent of Southern California Edison
Company, an electric utility that buys and sells power in California. In the
past year, various market conditions and other factors have resulted in higher
wholesale power prices to California utilities. At the same time, two of the
three major utilities, Southern California Edison and Pacific Gas and Electric
Co., have operated under a retail rate freeze. As a result, there has been a
significant under recovery of costs by Southern California Edison and Pacific
Gas and Electric, and each of these companies has failed to make payments due to
power suppliers and others. Given these and other payment defaults, creditors of
Southern California Edison and Pacific Gas and Electric could file involuntary
bankruptcy petitions against these companies. For more information on the
current regulatory situation in California, see "--Regulatory Matters--
California Deregulation." For more information on how the current California
power crisis affects our investments in energy projects in California, see
"--Project Development--Risk Factors Associated with the California Power
Crisis."

Southern California Edison's current financial condition has had, and may
continue to have, an adverse impact on Edison International's credit quality
and, as previously reported by Edison International, has resulted in
cross-defaults under Edison International's credit facilities. Both Standard &
Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the
credit ratings of Edison International and Southern California Edison to
substantially below investment grade levels. The ratings remain under review for
potential downgrade by both Standard & Poor's and Moody's.

We have taken measures to isolate ourselves from the credit downgrades of
Edison International and Southern California Edison, and to facilitate our
ability and the ability of our subsidiaries to maintain their respective
investment grade ratings. For more information on our actions, see "Management's
Discussion and Analysis of Results of Operations and Financial
Conditions--Credit Ratings."

STRATEGIC OVERVIEW

Our business goal is to be one of the leading owners and operators of
electric generating assets in the world. We play an active role, as a long-term
owner, in all phases of power generation, from planning and development through
construction and commercial operation. We believe that this involvement allows
us to better ensure, with our experienced personnel, that our projects are
well-planned, structured and managed, thus maximizing value creation. We have
separate strategies for developed and developing countries.

In developed countries, our strategy focuses on enhancing the value of
existing assets, expanding plant capacity at existing sites and developing new
projects in locations where we have an established position or otherwise
determine that attractive financial performance can be realized. In addition,
because a number of our projects in developed countries, known as merchant
plants, sell power into markets without the certainty of long-term contracts, we
conduct power marketing, trading, and risk

3

management activities to stabilize and enhance the financial performance of
these projects. We also recognize that our principal customers are regulated
utilities. We therefore strive to understand the regulatory and economic
environment in which the utilities operate so that we may continue to create
mutually beneficial relationships and business dealings.

In developing countries, our strategy focuses on investing with strategic
partners, securing limited recourse financing based upon long-term power
purchase agreements with state owned utilities and securing government financial
support from organizations such as the Export-Import Bank of the United States,
the U.S. Overseas Private Investment Corporation and the Japan Bank for
International Cooperation. In addition, for some projects, we have obtained
political risk insurance from private companies.

In making investment decisions, we evaluate potential project returns
against our internally generated rate of return guidelines. We establish these
guidelines by identifying a base rate of return and adjusting the base rate by
potential risk factors, such as risks associated with project location and stage
of project development. We endeavor to mitigate these risks by (i) evaluating
all projects and the markets in which they operate, (ii) selecting strategic
partners with complementary skills and local experience, (iii) structuring
investments through subsidiaries, (iv) managing up front development costs,
(v) utilizing limited recourse financing and (vi) linking revenue and expense
components where appropriate.

In response to the increasing globalization of the independent power market,
we have organized our operation and development activities into three geographic
regions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia, Middle
East and Africa. Each region is served by one or more teams consisting of
business development, operations, finance and legal personnel, and each team is
responsible for all our activities within a particular geographic region. Also,
we mobilize personnel from outside a particular region when needed in order to
assist in the development of specified projects.

Below is a brief discussion of the current strategy for each of the three
regions and a summary of our projects that are currently in the construction or
early operations stage and other significant operating projects in each of the
regions. For further information regarding our 33 domestic operating projects,
see "--Our Operating Projects--Description of Domestic Operating Projects." For
further information regarding our 40 international operating projects, see
"--Our Operating Projects--Description of International Operating Projects."

AMERICAS

Our Americas region is headquartered in Irvine, California with additional
offices located in Chicago, Illinois; Boston, Massachusetts; and Washington,
D.C. The strategy for the Americas region is (i) to manage our interest in
operating and construction phase projects located throughout the United States,
(ii) to expand our generation at existing sites, sometimes referred to as
"brownfield" development, (iii) to pursue the development of new power projects
throughout the region, sometimes referred to as "greenfield" development and
(iv) to a lesser extent than we had in the past, to pursue the acquisition and
development of existing generating assets from utilities, industrial companies
and other independent power producers throughout the region. We currently have
33 operating projects in this region, all of which are presently located in the
United States and its territories.

In March 1999, we acquired 100% of the 1,884 MW Homer City Electric
Generating Station for approximately $1.8 billion. This facility is a coal fired
plant in the mid-Atlantic region of the United States and has direct, high
voltage interconnections to both the New York Independent System Operator, which
controls the transmission grid and energy and capacity markets for New York
State and is commonly known as the NYISO, and the Pennsylvania-New
Jersey-Maryland Power Pool, which is commonly known as the PJM. We operate the
plant, which we believe is one of the lowest-cost generation facilities in the
region.

4

In December 1999, we acquired the fossil-fuel generating plants of
Commonwealth Edison, a subsidiary of Exelon Corporation, which are collectively
referred to as the Illinois Plants, totaling 6,841 MW of generating capacity,
for approximately $4.1 billion. We operate these plants, which provide access to
the Mid-America Interconnected Network and the East Central Area Reliability
Council. In connection with this transaction, we entered into power purchase
agreements with Commonwealth Edison with a term of up to five years.
Subsequently, Commonwealth Edison assigned its rights and obligations under
these power purchase agreements to Exelon Generation Company, LLC. Concurrently
with this acquisition, we assigned our right to purchase the Collins Station, a
2,698 MW gas and oil-fired generating station located in Illinois, to third
party lessors. After this assignment, we entered into a lease of the Collins
Station with a term of 33.75 years. The aggregate megawatts either purchased or
leased as a result of these transactions is 9,539 MW. See "Management's
Discussion and Analysis of Results of Operations and Financial
Condition--Acquisitions, Dispositions and Sale-Leaseback
Transactions--Sale-Leaseback Transactions" for a description of the Powerton and
Joliet sale-leaseback transactions.

In September 2000, we completed a transaction with P&L Coal Holdings
Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading
operations of Citizens Power LLC and a minority interest in structured
transaction investments relating to long-term power purchase agreements. As a
result of this acquisition, we have expanded our trading operations beyond the
traditional marketing of our electric power. By the end of the third quarter of
2000, we merged our own marketing operations with the Citizens trading
operations under Edison Mission Marketing & Trading, Inc.

In November 2000, we completed a transaction with Texaco Inc. to purchase a
proposed 560 MW gas fired combined cycle project to be located in Kern County,
California, referred to as the Sunrise Project. The acquisition includes all
rights, title and interest held by Texaco in the Sunrise Project, except that
Texaco has an option to repurchase a 50% interest in the project prior to its
commercial operation. As part of this transaction, we also: (i) acquired from
Texaco an option to purchase two gas turbines which we plan to utilize in the
project, (ii) provided Texaco an option to purchase two of the turbines
available to us under the Edison Mission Energy Master Turbine Lease and
(iii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future
power plant projects we designate. For more information on the Edison Mission
Energy Master Turbine Lease, see "Management's Discussion and Analysis of
Results of Operations and Financial Condition--Commitments and
Contingencies--Edison Mission Energy Master Turbine Lease." The Sunrise Project
consists of two phases, with Phase I, construction of a single-cycle gas fired
facility (320 MW), currently scheduled to be completed in August 2001, and Phase
II, conversion to a combined-cycle gas fired facility (560 MW), currently
scheduled to be completed in June 2003. In December 2000, we received the Energy
Commission Certification and a permit to construct the Sunrise plant, which
allowed us to commence construction of Phase I. We are negotiating with the
California Department of Water Resources the detailed terms and conditions of a
long-term, cost-based-type rate power purchase agreement. We cannot assure you
that we will be successful in reaching a final agreement.

ASIA PACIFIC

Our Asia Pacific region is headquartered in Singapore with additional
offices located in Australia, Indonesia and the Philippines. The strategy for
this region is (i) to pursue projects in countries where there exist strong
political commitment and the structural framework necessary for private power,
(ii) to seek opportunities to employ indigenous fuels and (iii) to seek
strategic, complimentary alliances with partners who bring value to a project by
providing fuel, equipment and construction services. We currently have 14
operating projects in this region that are located in Australia, Indonesia,
Thailand and New Zealand.

5

The Paiton project is a 1,230 MW coal fired power plant in operation in East
Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a
$490 million investment in the Paiton project at December 31, 2000. The
project's tariff under the power purchase agreement with PT PLN is higher in the
early years and steps down over time. The tariff for the Paiton project includes
costs relating to infrastructure to be used in common by other units at the
Paiton complex. The plant's output is fully contracted with the state-owned
electric company, PT PLN. Payments are in Indonesian Rupiah, with the portion of
the payments intended to cover non-Rupiah project costs, including returns to
investors, adjusted to account for exchange rate fluctuations between the
Indonesian Rupiah and the U.S. dollar. The project received substantial finance
and insurance support from the Export-Import Bank of the United States, the
Japan Bank for International Cooperation, the U.S. Overseas Private Investment
Corporation and the Ministry of Economy, Trade and Industry of Japan. PT PLN's
payment obligations are supported by the Government of Indonesia.

The projected rate of growth of the Indonesian economy and the exchange rate
of Indonesian Rupiah into U.S. dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The Paiton project's
senior debt ratings have been reduced from investment grade to speculative grade
based on the rating agencies' determination that there is increased risk that PT
PLN might not be able to honor the power purchase agreement with P.T. Paiton
Energy, the project company. The Government of Indonesia has arranged to
reschedule sovereign debt owed to foreign governments and has entered into
discussions about rescheduling sovereign debt owed to private lenders.

In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the
Paiton project had achieved commercial operation under the terms of the power
purchase agreement and, in July 1999, that the second 615 MW unit of the plant
had similarly achieved commercial operation. Because of the economic downturn,
PT PLN was then experiencing low electricity demand and PT PLN, through
February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a
lawsuit contesting the validity of its agreement to purchase electricity from
the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in
connection with this withdrawal, the parties entered into an interim agreement
for the period through December 31, 2000, under which dispatch levels and fixed
and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made
all fixed payments due under the interim agreement totaling $115 million and all
payments due for energy delivered by the plant to PT PLN. As part of the
continuing negotiations on a long-term restructuring of the tariff, Paiton
Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period
from January 1, 2001 through June 30, 2001. This agreement provides for fixed
monthly payments aggregating $108 million over its six month duration and for
the payment for energy delivered to PT PLN from the plant during this period.
Paiton Energy and PT PLN intend to complete the negotiations of the further
phases of a new long-term tariff during the six month duration of the Phase I
Agreement. To date, PT PLN has made all fixed and energy payments due under the
Phase I Agreement.

Events, including those discussed above, have occurred which may mature into
defaults of the project's debt agreements following the passage of time, notice
or lapse of waivers granted by the project's lenders. On October 15, 1999, the
project entered into an interim agreement with its lenders pursuant to which the
lenders waived defaults during the term of the agreement and effectively agreed
to defer payments of principal until July 31, 2000. In July, the lenders agreed
to extend the term of the lender interim agreement through December 31, 2000. In
December 2000, the lenders agreed to an additional extension of the lender
interim agreement through December 31, 2001. Paiton Energy has received lender
approval of the Phase I Agreement.

Under the terms of the power purchase agreement, PT PLN has been required to
pay for capacity and fixed operating costs once each unit and the plant achieved
commercial operation. As of December 31, 2000, PT PLN had not paid invoices
amounting to $814 million for capacity charges and

6

fixed operating costs under the power purchase agreement. All arrears under the
power purchase agreement continue to accrue, minus the fixed monthly payments
actually made under the year 2000 interim agreement and under the recently
agreed Phase I Agreement, with the payment of these arrears to be dealt with in
connection with the overall tariff long-term restructuring of the tariff. In
this regard, under the Phase I Agreement, Paiton Energy has agreed that, so long
as the Phase I Agreement is complied with, it will seek to recoup no more than
$590 million of the above arrears, the payment of which is to be dealt with in
connection with the overall tariff restructuring.

Any material modifications of the power purchase agreement could require a
renegotiation of the Paiton project's debt agreements. The impact of any
renegotiations with PT PLN, the Government of Indonesia or the project's
creditors on our expected return on our investment in Paiton Energy is uncertain
at this time; however, we believe that we will ultimately recover our investment
in the project.

In May 1999, we completed a transaction with the government of New Zealand
to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in an overseas public offering resulting in
widespread ownership among the citizens of New Zealand and offshore investors.
These shares are publicly traded on stock exchanges in New Zealand and
Australia. During 2000, we increased our share of ownership in Contact Energy to
42%. Contact Energy owns and operates hydroelectric, geothermal and natural gas
fired power generating plants primarily in New Zealand with a total current
generating capacity of 2,449 MW, of which our share is 940 MW. In addition,
Contact Energy has expanded into the retail electricity and gas markets in New
Zealand since 1998 through acquisition of regional electricity supply and retail
gas supply businesses. See "--Regulatory Matters--Recent Foreign Regulatory
Matters."

In February 2001, we completed the acquisition of a 50% interest in CBK
Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year
build-rehabilitate-transfer-and-operate agreement with National Power
Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project has
been completed with equity contributions of $117 million (our 50% share is
$58.5 million) required to be made upon completion of the rehabilitation and
expansion, currently scheduled in 2003, and debt financing has been arranged for
the remainder of the cost for this project.

EUROPE, CENTRAL ASIA, MIDDLE EAST AND AFRICA

Our Europe, Central Asia, Middle East and Africa region is headquartered in
London, England with additional offices located in Italy, Spain and Turkey. The
London office was established in 1989. The region is characterized by a blend of
both mature and developing markets. Our strategy for the region is to pursue the
development and acquisition of medium to large scale power and cogeneration
facilities with diversified fuel sources and generation technology. We currently
have 26 operating projects in this region that are located in the U.K., Turkey,
Spain and Italy.

In July 1999, we acquired 100% of the Ferrybridge and Fiddler's Ferry coal
fired power plants located in the U.K. with a total generating capacity of 3,984
MW from PowerGen UK plc for approximately $2.0 billion. Ferrybridge, located in
West Yorkshire, and Fiddler's Ferry, located in Warrington, are in the middle of
the order in which plants are called upon to dispatch electric power. The plants
complement the pumped-storage hydroelectric power plants we already own in the
U.K.

The current electricity trading mechanism in the U.K. is in the process of
being abolished and replaced with trading arrangements using bilateral
contracts. The current system provides for the sale of energy to a pool. Under
the new trading arrangements, our U.K. subsidiary, Edison First Power Limited,
is required to contract with specific purchasers for the sales of energy
produced by its Ferrybridge and Fiddler's Ferry stations. Under the new system,
a generator must deliver, and a consumer must take delivery, in accordance with
their contracted agreements or face the volatility of

7

market prices. Edison First Power believes that a consequence of this will be to
increase greatly the motivation of parties to contract in advance in order to
lock in an agreed upon price for, and quantity of, energy. The U.K. Utilities
Act, which was approved on July 28, 2000, allows for implementation of the new
trading arrangements, which are to commence on March 27, 2001. As a result of
the introduction of the new electricity trading arrangements, forecasts of
future electricity prices in the markets into which Edison First Power sells its
power vary significantly. Recent experience by Edison First Power has shown that
this arrangement has placed significant downward pressure on prices to be paid
by purchasers of energy in the future, although it is uncertain how the new
trading arrangements will affect prices in the long-term.

The financial performance of the Fiddler's Ferry and Ferrybridge power
plants has not matched our expectations, largely due to lower energy prices
resulting primarily from increased competition, warmer-than-average weather and
uncertainty surrounding the new electricity trading arrangements discussed
above. As a result, Edison First Power has decided to defer some environmental
capital expenditures originally planned to increase plant utilization and
therefore is currently in breach of milestone requirements for the
implementation of the capital expenditures program set forth in the financing
documents relating to the acquisition of the plants. In addition, due to this
reduced financial performance, Edison First Power's debt service coverage ratio
during 2000 declined below the threshold set forth in the financing documents.

Edison First Power is currently in discussions with the relevant financing
parties to revise the required capital expenditure program, to waive: (i) the
breach of the financial ratio covenant for 2000, (ii) a technical breach of
requirements for the provision of information that was delayed due to
uncertainty regarding capital expenditures, and (iii) other related technical
defaults. Edison First Power is in the process of requesting the necessary
waivers and consents to amendments from the financing parties. We cannot assure
you that waivers and consents to amendments will be forthcoming. The financing
documents stipulate that a breach of the financial ratio covenant constitutes an
immediate event of default and, if the event of default is not waived, the
financing parties are entitled to enforce their security over Edison First
Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite
the breaches under the financing documents, Edison First Power's debt service
coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and
debt service payments, Edison First Power utilized L37 million from its debt
service reserve to meet its debt service requirements in 2000. Our net
investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry
power plants and related debt was $918 million at December 31, 2000.

Another of our subsidiaries, EME Finance UK Limited, is the borrower under
the facility made available for the purposes of funding coal and capital
expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At
December 31, 2000, L58 million was outstanding for coal purchases and zero was
outstanding to fund capital expenditures under this facility. EME Finance UK
Limited on-lends any drawings under this facility to Edison First Power. The
financing parties of this facility have also issued letters of credit directly
to Edison First Power to support their obligations to lend to EME Finance UK
Limited. EME Finance UK Limited's obligations under this facility are separate
and apart from the obligations of Edison First Power under the financing
documents related to the acquisition of these plants. We have guaranteed the
obligations of EME Finance UK Limited under this facility, including any letters
of credit issued to Edison First Power under the facility, for the amount of
L359 million, and our guarantee remains in force notwithstanding any breaches
under Edison First Power's acquisition financing documents.

In addition, Edison Mission Energy may provide guarantees in support of
bilateral contracts entered into by Edison First Power under the new electricity
trading arrangements. Edison Mission Energy has provided guarantees totaling
L19 million relating to these contracts at March 20, 2001.

8

During October 1999, we completed the acquisition of the remaining 20% of
the 220 MW natural gas fired Roosecote project located in England. Consideration
for the remaining 20% consisted of a cash payment of approximately
$16.0 million, or 9.6 million pounds sterling.

In March 2000, we completed a transaction with UPC International Partnership
CV II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian
Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of
power projects that are in operation or under development in Italy. All the
projects use wind to generate electricity from turbines. The electricity is sold
under fixed price, long-term tariffs. Assuming all the projects under
development are completed, currently scheduled for 2002, the total capacity of
these projects will be 283 MW. The total purchase price was 90 billion Italian
Lira (approximately $44 million at December 31, 2000), with equity contribution
obligations of up to 33 billion Italian Lira (approximately $16 million at
December 31, 2000), depending on the number of projects that are ultimately
developed. As of December 31, 2000, our payments in respect of these projects
included $27 million toward the purchase price and $13 million in equity
contributions.

PROJECT DEVELOPMENT

The development of power generation projects, whether through new
construction or the acquisition of existing assets, involves numerous elements,
including evaluating and selecting development opportunities, evaluating
regulatory and market risks, designing and engineering the project, acquiring
necessary land rights, permits and fuel resources, obtaining financing, managing
construction and, in some cases, obtaining power and steam sales agreements.

We initially evaluate and select potential development projects based on a
variety of factors, including the reliability of technology, the strength of the
potential partners, the feasibility of the project, the likelihood of obtaining
a long term power purchase agreement or profitably selling power without this
agreement, the probability of obtaining required licenses and permits and the
projected economic return. During the development process, we monitor the
viability of our projects and make business judgments concerning expenditures
for both internal and external development costs. Completion of the financing
arrangements for a project is generally an indication that business development
activities are substantially complete.

PROJECT TYPE

The selection of power generation technology for a particular project is
influenced by various factors, including regulatory requirements, availability
of fuel and anticipated economic advantages for a particular application.

We have ownership interests in operating projects that employ gas fired
combustion turbine technology, predominantly through an application known as
cogeneration. Cogeneration facilities sequentially produce two or more useful
forms of energy, such as electricity and steam, from a single primary source of
fuel, such as natural gas or coal. Many of our cogeneration projects are located
near large, industrial steam users or in oil fields that inject steam
underground to enhance recovery of heavy oil. The regulatory advantages for
cogeneration facilities under the Public Utility Regulatory Policies Act of
1978, as amended, have become somewhat less significant because of other federal
regulatory exemptions made available to independent power producers under the
Energy Policy Act. Accordingly, we expect that the majority of our future
projects will generate power without selling steam to industrial users.

We also have ownership interests in projects that use renewable resources
like hydroelectric energy and geothermal energy. Our hydroelectric projects,
excluding First Hydro's plants, use run-of-the-river technology to generate
electricity. The First Hydro plant utilizes pumped-storage stations that consume
electricity when it is comparatively less expensive in order to pump water for
storage in an upper

9

reservoir. Water is then allowed to flow back through turbines in order to
generate electricity when its market value is higher. This type of generation is
characterized by its speed of response, its ability to work efficiently at wide
variations of load and the basic reliance of revenue on the difference between
the peak and trough prices of electricity during the day. Our geothermal
projects included as part of our Contact Energy investment use technologies that
convert the heat from geothermal fluids and underground steam into electricity.

We also have domestic and international ownership interests in operating
projects and projects under construction and advanced development which are
large scale, coal fired projects using pulverized coal and coal fired generation
technology. In the United States, we have developed and acquired coal and waste
coal fired projects that employ traditional pulverized coal and circulating
fluidized bed technology, which allows for the use of lower quality coal and the
direct removal of sulfur from the coal. We also have acquired ownership
interests in gas-fired projects and have purchased gas-fired turbines for
combined cycle gas turbines (commonly referred to as "F" technology), which are
designed to increase efficiency of power generation due to higher firing
temperatures.

LONG-TERM POWER AND STEAM SALES CONTRACTS

Many of our operating projects in the United States sell power and steam to
domestic electric utilities and industrial steam users under long-term
contracts. Electric power generated by several of our international projects is
sold under long term contracts to electric utilities located in the country
where the power project is located. These projects' revenues from power purchase
agreements usually consist of two components: energy payments and capacity
payments. Energy payments are made based on actual deliveries of electric
energy, such as kilowatt hours, to the purchaser. Energy payments are usually
indexed to specified variable costs that the purchaser avoids by purchasing this
electric energy from our projects opposed to operating its own power plants to
produce the same amount of electric energy. The variable components typically
include fuel costs and selected operation and maintenance expenses. These costs
may be indexed to the utility's cost of fuel and/or selected inflation indices.
Capacity payments are based on a project's proven capability to reliably make
electric capacity available, whether or not the project is called to deliver
electric energy. Capacity payments compensate a project for specified fixed
costs that are incurred independent of the amount of energy sold by the project.
Such fixed costs include taxes, debt service and distributions to the project's
owners. To receive capacity payments, there are typically minimum performance
standards that must be met, and often there is a performance range that further
influences the amount of capacity payments.

Steam produced from our cogeneration facilities is sold to industrial steam
users, such as petroleum refineries or companies involved in the enhanced
recovery of oil through steam flooding of oil fields, under long term steam
sales contracts. Steam payments are generally based on formulas that reflect the
cost of water, fuel and capital to us. In some cases, we have provided steam
purchasers with discounts from their previous costs for producing this steam
and/or have partially indexed steam payments to other indices including
specified oil prices.

SALE OF POWER FROM MERCHANT PLANTS

During 1999, we acquired a number of merchant plants, which sell capacity,
energy and, in some cases, other services on a competitive basis under bilateral
arrangements or through centralized power pools that provide an institutional
framework for price setting, dispatch and settlement procedures.

Electric power generated at the Homer City plant is sold under bilateral
arrangements with utilities and power marketers under short term contracts with
terms of two years or less, or to the PJM or the NYISO. These pools have short
term markets, which establish an hourly clearing price. The Homer City plant is
situated in the PJM control area and is physically connected to high voltage

10

transmission lines serving both the PJM and NYISO markets. The Homer City plant
can also transmit power to the midwestern United States.

The majority of electric power generated at the Illinois Plants is sold
under power purchase agreements with Exelon Generation Company in which Exelon
Generation Company purchases capacity and has the right to purchase energy
generated by the Illinois Plants. The agreements, which began on December 15,
1999, and have a term of up to five years, provide for Exelon Generation Company
to make a capacity payment for the plants under contract and an energy payment
for the electricity produced by these plants. The capacity payments provide the
Illinois Plants revenue for fixed charges, and the energy payments compensate
the Illinois Plants for variable costs of production. If Exelon Generation
Company does not fully dispatch the plants under contract, the Illinois Plants
may sell, subject to specified conditions, the excess energy at market prices to
neighboring utilities, municipalities, third party electric retailers, large
consumers and power marketers on a spot basis. A bilateral trading
infrastructure already exists with access to the Mid-America Interconnected
Network and the East Central Area Reliability Council.

Our plants in the U.K. currently sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly clearing
price, also referred to as the pool price, for electrical energy. The pool price
is extremely volatile and can vary by as much as a factor of ten or more over
the course of a few hours, due to the large differentials in demand according to
the time of day. The pricing arrangements include provision for capacity
payments to be added to the basic pool price at times of capacity shortage. The
First Hydro, Ferrybridge and Fiddler's Ferry plants have the opportunity to
mitigate a portion of the market risk of the pool by entering into contracts for
differences, which are electricity rate swap agreements related to either the
selling or purchasing price of power. These contracts specify a price at which
the electricity will be traded, and the parties to the agreement make payments
based on the difference between the price in the contract and the pool price for
the element of power under contract. These contracts are sold in various
structures and act to stabilize revenues or purchasing costs by removing an
element of net exposure to pool price volatility. See "Management's Discussion
and Analysis of Results of Operations and Financial Condition--Market Risk
Exposures--United Kingdom."

The Loy Yang B plant sells its electrical energy through a centralized
electricity pool, which provides for a system of generator bidding, central
dispatch and a settlements system based on a clearing market for each half-hour
of every day. The National Electricity Market Management Company, operator and
administrator of the pool, determines a system marginal price each half-hour. To
mitigate exposure to price volatility of the electricity traded into the pool,
the Loy Yang B plant has entered into a number of financial hedges. From May 8,
1997 to December 31, 2000, approximately 53% to 64% of the plant output sold was
hedged under vesting contracts, with the remainder of the plant capacity hedged
under the State Hedge. The State Hedge agreement with the State Electricity
Commission of Victoria is a long-term contractual arrangement based upon a fixed
price commencing May 8, 1997 and terminating October 31, 2016. The State
Government of Victoria, Australia guarantees the State Electricity Commission of
Victoria's obligations under the State Hedge. From January 2001 to July 2014,
approximately 77% of the plant output sold is hedged under the State Hedge. From
August 2014 to October 2016, approximately 56% of the plant output sold is
hedged under the State Hedge. Additionally, the Loy Yang B plant has entered
into a number of fixed forward electricity contracts with terms of up to two
years, and which will further mitigate against the price volatility of the
electricity pool.

POWER MARKETING AND TRADING ACTIVITIES

When making sales under negotiated contracts, it is our policy to deal with
investment grade counterparties or counterparties that provide equivalent credit
support. Exceptions to the policy are granted only after thorough review and
scrutiny by our Risk Management Committee. Most entities

11

that have received exceptions are organized power pools and quasi-governmental
agencies. We hedge a portion of the electric output of our merchant plants in
order to stabilize and enhance the operating revenues from merchant plants. When
appropriate, we manage the "spark spread," or margin, which is the spread
between electric prices and fuel prices and use forward contracts, swaps,
futures, or options contracts to achieve those objectives.

Our power marketing and trading organization, Edison Mission Marketing &
Trading, is divided into front-, middle-, and back-office segments, with
specified duties segregated for control purposes. The personnel of Edison
Mission Marketing & Trading have a high level of knowledge of utility
operations, fuel procurement, energy marketing and futures and options trading.
We have systems in place which monitor real time spot and forward pricing and
perform option valuations. We also have a wholesale power scheduling group that
operates on a 24 hour basis.

Edison Mission Marketing & Trading markets and trades electric power and
energy related commodity products, including forwards, futures, options and
swaps. It also provides services and price risk management capabilities to the
electric power industry. Price risk management activities include the
restructuring of power sales and power supply agreements. We generally balance
forward sales and purchase contracts to mitigate market risk and secure cash
flow streams.

Energy trading and price risk management activities give rise to commodity
price risk, which represents the potential loss that can be caused by a change
in the market value of a particular commodity. Commodity price risks are
actively monitored to ensure compliance with our risk management policies.
Policies are in place which limit the amount of total net exposure we may enter
into at any point in time. Procedures exist which allow for monitoring of all
commitments and positions with daily reporting to senior management. We perform
a "value at risk" analysis in our daily business to measure, monitor and control
our overall market risk exposure. The use of value at risk allows management to
aggregate overall risk, compare risk on a consistent basis and identify the
drivers of the risk. Value at risk measures the worst expected loss over a given
time interval, under normal market conditions, at a given confidence level.
Given the inherent limitations of value at risk and relying on a single risk
measurement tool, we supplement this approach with industry "best practice"
techniques including the use of stress testing and worst-case scenario analysis,
as well as stop limits and counterparty credit exposure limits.

FUEL SUPPLY CONTRACTS

We seek to enter into long term contracts to mitigate the risks of
fluctuations in prices for coal, oil, gas and fuel transportation. We believe,
however, that our financial condition will not be substantially adversely
affected by these fluctuations for our non-merchant plants because our long term
contracts to sell power and steam typically are structured so that fluctuations
in fuel costs will produce similar fluctuations in electric energy and/or steam
revenues. The degree of linkage between these revenues and expenses varies from
project to project, but generally permits the projects with long term contracts
to operate profitably under a wide array of potential price scenarios.

PROJECT FINANCING

Each project we develop requires a substantial capital investment. Permanent
project financing is often arranged immediately prior to the construction of the
project. With limited exceptions, this debt financing is for approximately 50%
to 80% of each project's costs and is structured on a basis that is non-recourse
to us and our other projects. In addition, the collateral security for each
project's financing generally has been limited to the physical assets, contracts
and cash flow of that project and our ownership interests in that project.

In general, each of our direct or indirect subsidiaries is organized as a
legal entity separate and apart from us and our other subsidiaries. Any asset of
any of these subsidiaries may not be available to

12

satisfy our obligations or those of any of our other subsidiaries. However,
unrestricted cash or other assets that are available for distribution by a
subsidiary may, subject to applicable law and the terms of financing
arrangements of these subsidiaries, be advanced, loaned, paid as dividends or
otherwise distributed or contributed to us.

The ability to arrange project financing and the cost of such financing are
dependent upon numerous factors, including general economic and capital market
conditions, the credit attributes of a project, conditions in energy markets,
regulatory developments, credit availability from banks or other lenders,
investor confidence in the industry, us and other project participants, the
continued success of our other projects, and provisions of tax and securities
laws that are conducive to raising capital.

Our financial exposure in any equity investment is generally limited by
contractual arrangement to our equity commitment, which is usually about 20% to
50% of our share of the aggregate project cost. In some cases, we provide
additional credit support to projects in the form of debt service reserves,
contingent equity commitments, revenue shortfall support or other arrangements
designed to provide limited support.

PERMITS AND APPROVALS

Because the process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated and lengthy, often taking a
year or longer, we seek to obtain all permits, licenses and other approvals
required for the construction and operation of a project, including siting,
construction and environmental permits, rights of way and planning approvals,
early in the development process for a project. See "--Regulatory
Matters--General."

Emission allowances were acquired by us as part of the acquisition of the
Illinois Plants and the Homer City plant. Emission allowances are required by
our facilities in order to be certified by the local environmental authorities
and are required to be maintained throughout the period of operation of those
facilities located in Pennsylvania and Illinois. We purchase additional emission
allowances when necessary to meet the environmental regulations. We also use
forward sales and purchases of emission allowances, together with options, to
achieve our objective of stabilizing and enhancing the operations from these
merchant plants.

CONSTRUCTION, OPERATIONS & MAINTENANCE AND MANAGEMENT

In the project implementation stage, we often provide construction
management, start up and testing services. The detailed engineering and
construction of the projects typically are performed by outside contractors
under fixed price, turnkey contracts. Under these contracts, the contractor
generally is required to pay liquidated damages to us in the event of cost
overruns, schedule delays or the project's failure to meet specified capacity,
efficiency and emission standards.

As a project goes into operation, operation and maintenance services are
provided to the project by one of our operation and maintenance subsidiaries or
another operation and maintenance contractor. The projects that we operated in
2000 achieved an average 82% availability. Availability is a measure of the
weighted average number of hours each generator is available for generation as a
percentage of the total number of hours in a year.

An executive director generally manages the day-to-day administration of
each project. Management committees comprised of the project's partners
generally meet monthly or quarterly to review and manage the operating
performance of the project.

RISK FACTORS ASSOCIATED WITH THE CALIFORNIA POWER CRISIS

Edison International, our ultimate parent company, is a holding company.
Edison International is also the corporate parent of Southern California Edison
Company, an electric utility that buys and sells power in California. In the
past year, various market conditions and other factors have resulted in

13

higher wholesale power prices to California utilities. At the same time, two of
the three major utilities, Southern California Edison and Pacific Gas and
Electric Co., have operated under a retail rate freeze. As a result, there has
been a significant under recovery of costs by Southern California Edison and
Pacific Gas and Electric, and each of these companies has failed to make
payments due to power suppliers and others. Given these and other payment
defaults, creditors of Southern California Edison and Pacific Gas and Electric
could file involuntary bankruptcy petitions against these companies.

Southern California Edison's current financial condition has had, and may
continue to have, an adverse impact on Edison International's credit quality
and, as previously reported by Edison International, has resulted in
cross-defaults under Edison International's credit facilities. Both Standard &
Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the
credit ratings of Edison International and Southern California Edison to
substantially below investment grade levels. The credit ratings remain under
review for potential downgrade by both Standard & Poor's and Moody's.

To isolate ourselves from the credit downgrades and potential bankruptcies
of Edison International and Southern California Edison, and to facilitate our
ability and the ability of our subsidiaries to maintain their respective
investment grade credit ratings, on January 17, 2001, we amended our articles of
incorporation and our bylaws to include so-called "ring-fencing" provisions.
These ring-fencing provisions are intended to preserve us as a stand-alone
investment grade rated entity despite the current credit difficulties of Edison
International and Southern California Edison. See "Management's Discussion and
Analysis of Results of Operations and Financial Condition--Credit Ratings."

We cannot assure you that these measures will effectively isolate us from
the credit downgrades or the potential bankruptcies of Edison International and
Southern California Edison. In January 2001, Standard & Poor's and Moody's
lowered our credit ratings. Our senior unsecured credit ratings were downgraded
to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's.
Our credit ratings remain investment grade. Both Standard & Poor's and Moody's
have indicated that the credit ratings outlook for us is stable. A downgrade in
our credit ratings below investment grade could increase our cost of capital,
make efforts to raise capital more difficult and could have an adverse impact on
us and our subsidiaries.

On March 15, 2001, the California Public Utilities Commission released a
draft of a proposed order instituting an investigation into whether California's
investor-owned utilities, including Southern California Edison, have complied
with past Commission decisions authorizing the formation of their holding
companies and governing affiliate transactions, as well as applicable statutes.
Action on this agenda item repeatedly has been deferred, including at the
Commission meeting on March 27, 2001, and the item has continued to appear on
the agendas for subsequent Commission meetings. The proposed order would reopen
the past holding company decisions and initiate an investigation into the
following matters:

- whether the holding companies, including Edison International, violated
requirements to give priority to the capital needs of their respective
utility subsidiaries;

- whether the ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the
requirements to give priority to the capital needs of their utility
subsidiaries;

- whether the payment of dividends by the utilities violated requirements
that the utilities maintain dividend policies as though they were
comparable stand-alone utility companies;

- any additional suspected violations of laws or Commission rules and
decisions; and

- whether additional rules, conditions, or other changes to the holding
company decisions are necessary.

14

We cannot predict whether the Commission will institute this investigation or
what effects any investigation or subsequent actions by the Commission may have
on Edison International or indirectly on us.

We have partnership interests in eight partnerships which own power plants
in California which have power purchase contracts with Pacific Gas and Electric
and/or Southern California Edison. Three of these partnerships have a contract
with Southern California Edison, four of them have a contract with Pacific Gas
and Electric, and one of them has contracts with both. In 2000, our share of
earnings before taxes from these partnerships was $168 million, which
represented 20% of our operating income. Our investment in these partnerships at
December 31, 2000 was $345 million.

As a result of Southern California Edison's and Pacific Gas and Electric's
current liquidity crisis, each of these utilities has failed to make payments to
qualifying facilities supplying them power. These qualifying facilities include
the eight power plants which are owned by partnerships in which we have a
partnership interest. Southern California Edison did not pay any of the amounts
due to the partnerships in January, February and March of 2001 and may continue
to miss future payments. Pacific Gas and Electric made its January payment in
full but thus far has paid only a small portion of the amounts due to the
partnerships in February and March and may not pay all or a portion of its
future payments.

On March 27, 2001, the California Public Utilities Commission issued a
decision that ordered the three California investor owned utilities, including
Southern California Edison and Pacific Gas and Electric, to commence payment for
power generated from qualifying facilities beginning in April 2001. In addition,
the decision modified the pricing formula for determining short run avoided
costs for qualifying facilities subject to these provisions. Depending on how
the utilities react to this order, the immediate impact of this decision may be
to commence payment in April 2001 at significantly reduced prices for power to
qualifying facilities subject to this pricing adjustment. Furthermore, this
decision called for further study of the pricing formula tied to short run
avoided costs and, accordingly, may be subject to more changes in the future.
Finally, this decision is subject to challenge before the Commission, the
Federal Energy Regulatory Commission and, potentially, state or federal courts.
Although it is premature to assess the full effect of this recent decision, it
could have a material adverse effect on our investment in the California
partnerships, depending on how it is implemented and future changes in the
relationship between the pricing formula and the actual cost of natural gas
procured by our California partnerships. This decision did not address payment
to the qualifying facilities for amounts due prior to April 2001.

The California utilities' failure to pay has adversely affected the
operations of our eight California qualifying facilities. Continuing failures to
pay similarly could have an adverse impact on the operations of our California
qualifying facilities. Provisions in the partnership agreements stipulate that
partnership actions concerning contracts with affiliates are to be taken through
the non-affiliated partner in the partnership. Therefore, partnership actions
concerning the enforcement of rights under each qualifying facility's power
purchase agreement with Southern California Edison in response to Southern
California Edison's suspension of payments under that power purchase agreement
are to be taken through the non-Edison Mission Energy affiliated partner in the
partnership. Some of the partnerships have sought to minimize their exposure to
Southern California Edison by reducing deliveries under their power purchase
agreements. It is unclear at this time what additional actions, if any, the
partnerships will take in regard to the utilities' suspension of payments due to
the qualifying facilities. As a result of the utilities' failure to make
payments due under these power purchase agreements, the partnerships have called
on the partners to provide additional capital to fund operating costs of the
power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours
have made equity contributions totaling approximately $103 million to meet
capital calls by the partnerships. Our subsidiaries and the other partners may
be required to make additional capital contributions to the partnerships.

15

Southern California Edison has stated that it is attempting to avoid
bankruptcy and, subject to the outcome of regulatory and legal proceedings and
negotiations regarding purchased power costs, it intends to pay all its
obligations once a permanent solution to the current energy and liquidity crisis
has been reached. Pacific Gas and Electric has taken a different approach and is
seeking to invoke force majeure provisions under its power purchase agreements
to excuse its failure to pay. In either case, it is possible that the utilities
will not pay all their obligations in full. In addition, it is possible that
Southern California Edison and/or Pacific Gas and Electric could be forced into
bankruptcy proceedings. If this were to occur, payments to the qualifying
facilities, including those owned by partnerships in which we have a partnership
interest, could be subject to significant delays associated with the lengthy
bankruptcy court process and may not be paid in full. At February 28, 2001,
accounts receivable due to these partnerships from Southern California Edison
and Pacific Gas & Electric were $437 million; our share of these receivables was
$217 million. Furthermore, Southern California Edison's and Pacific Gas and
Electric's power purchase agreements with the qualifying facilities could be
subject to review by a bankruptcy court. While we believe that the generation of
electricity by the qualifying facilities, including those owned by partnerships
in which we have a partnership interest, is needed to meet California's power
needs, we cannot assure you either that these partnerships will continue to
generate electricity without payment by the purchasing utility, or that the
power purchase agreements will not be adversely affected by a bankruptcy or
contract renegotiation as a result of the current power crisis.

A number of federal and state, legislative and regulatory initiatives
addressing the issues of the California electric power industry have been
proposed, including wholesale rate caps, retail rate increases, acceleration of
power plant permitting and state entry into the power market. Many of these
activities are ongoing. These activities may result in a restructuring of the
California power market. At this time, these activities are in their preliminary
stages, and it is not possible to estimate their likely ultimate outcome. The
situation in California changes on an almost daily basis. You should monitor
developments in California for the most up to date information. For more
information on the current regulatory situation in California, see "--Regulatory
Matters--California Deregulation."

RISK FACTORS ASSOCIATED WITH OUR LIQUIDITY

As of December 31, 2000, we had $2.1 billion of debt which is recourse to
Edison Mission Energy and $5.9 billion of debt which is non-recourse to Edison
Mission Energy but is recourse to our subsidiaries appearing on our consolidated
balance sheet.

Edison Mission Energy has a substantial amount of short-term debt that will
need to be extended or refinanced. Edison Mission Energy has two credit
facilities, in a total amount of $1 billion, that are scheduled to expire in
May 2001 and one credit facility, in the amount of $500 million, that is
scheduled to expire in October 2001.

We cannot assure you that we will be able to extend our existing credit
facilities or obtain new credit facilities to finance our needs, or that any new
credit facility can be obtained under similar terms and rates as our existing
credit facilities. If we cannot extend our existing credit facilities or obtain
new credit facilities to finance our needs on similar terms and rates as our
existing credit facilities, this could have a negative impact on our liquidity.

Our substantial amount of debt and financial obligations presents the risk
that we might not have sufficient cash to service our indebtedness and that our
existing corporate and project debt could limit our ability to finance the
acquisition and development of additional projects, to compete effectively or to
operate successfully under adverse economic conditions.

16

We cannot assure you that Standard & Poor's and Moody's will not downgrade
us below investment grade, whether as a result of the California power crisis or
otherwise. If we are downgraded, we could be required to, among other things:

- provide additional guarantees, collateral, letters of credit or cash for
the benefit of counterparties in our trading activities,

- post a letter of credit or cash collateral to support our $58.5 million
equity contribution obligation in connection with our acquisition in
February 2001 of a 50% interest in the CBK project in the Philippines, and

- repay a portion of the preferred shares issued by our subsidiary in
connection with our 1999 acquisition of a 40% interest in Contact Energy
Limited, a New Zealand power company, which, based on their value at
March 20, 2001, would require a payment of approximately $19 million.

Our downgrade could result in a downgrade of Edison Mission Midwest Holdings
Co., our indirect subsidiary. In the event of a downgrade of Edison Mission
Midwest Holdings below its current credit rating, provisions in the agreements
binding on its subsidiary, Midwest Generation, LLC, limit the ability of Midwest
Generation to use excess cash flow to make distributions.

A downgrade in our credit rating below investment grade could increase our
cost of capital, increase our credit support obligations, make efforts to raise
capital more difficult and could have an adverse impact on us and our
subsidiaries.

Because substantially all our operations are conducted by our subsidiaries,
our cash flow and ability to service our indebtedness or otherwise meet our
financial obligations are dependent upon the ability of our subsidiaries to pay
dividends and make distributions to us. As mentioned above, the California power
crisis has had, and may continue to have, an adverse impact on our California
partnership investments and may adversely affect their ability to make
distributions to us. In addition, financing agreements of our subsidiaries and
affiliates generally place limitations on the ability of those subsidiaries and
affiliates to pay dividends, make distributions or otherwise transfer funds to
us. Financing agreements for our operating subsidiaries and affiliates are
generally secured and contain representations, warranties, covenants and other
agreements on our part that, if not met, could lead to a default under those
agreements. If there is a default under a project financing for any reason,
project lenders could exercise rights and remedies typically granted to secured
parties, including the ability to take control of the project's assets and/or
our ownership interest in the project company. In addition, we own a minority
interest in some of our projects, and so are unable unilaterally to cause
dividends or distributions to be made to us from those projects. Lastly, many of
our projects are located overseas and, therefore, distributions from foreign
operations could be subject to additional taxes in the United States upon
repatriation.

Any right of ours to receive any assets of any of our subsidiaries upon any
liquidation or reorganization of a subsidiary will be effectively subordinated
to the claims of the subsidiary's creditors, including trade creditors and
holders of debt incurred by the subsidiary.

One of our subsidiaries, Edison First Power, has defaulted on its financing
documents related to the acquisition of the Fiddler's Ferry and Ferrybridge
power plants. Edison First Power is currently in the process of requesting the
necessary waivers and consents to amendments from the financing parties. We
cannot assure you that these waivers and consents to amendments will be
forthcoming. The financing documents stipulate that a breach of the financial
ratio covenant constitutes an immediate event of default and, if the event of
default is not waived, the financing parties are entitled to enforce their
security over Edison First Power's assets, including the Fiddler's Ferry and
Ferrybridge plants. Due to the timing of its cash flows and debt service
payments, Edison First Power utilized L37 million from its debt service reserve
to meet its debt service requirements in 2000. Our net investment in our
subsidiary that holds the Ferrybridge and Fiddlers' Ferry power plants and
related debt was

17

$918 million at December 31, 2000. See "Management's Discussion and Analysis of
Results of Operations and Financial Condition--Financing Plans."

RISK FACTORS ASSOCIATED WITH PROJECT DEVELOPMENT, FINANCE AND OPERATION

Some of our projects do not have long-term power purchase agreements. Also,
projects which we may acquire or develop in the future may not have long-term
power purchase agreements. Because their output is not committed to be sold
under long-term contracts, these projects are subject to market forces which
determine the amount and price of power that they sell. We cannot assure you
that these plants will be successful in selling power into their markets. If
they are unsuccessful, they may not be able to generate enough cash to service
their own debt or to make distributions to us.

In 2000, 33% of our electric revenues were derived under power purchase
agreements with Exelon Generation Company, a subsidiary of Exelon Corporation,
entered into in connection with our December 1999 acquisition of the Illinois
Plants. Exelon Corporation is the holding company of Commonwealth Edison and
PECO Energy Company, major utilities located in Illinois and Pennsylvania.
Electric revenues attributable to sales to Exelon Generating Company are earned
from capacity and energy provided by the Illinois Plants under three five-year
power purchase agreements. If Exelon Generation were to fail or become unable to
fulfill its obligations under these power purchase agreements, we may not be
able to find another customer on similar terms for the output of our power
generation assets. Any material failure by Exelon Generation Company to make
payments under these power purchase agreements could adversely affect our
results of operations and liquidity.

Our international projects are subject to political and business risks,
including uncertainties associated with currency exchange rates, currency
repatriation, expropriation, political instability and other issues that have
the potential to impair the projects from making dividends or other
distributions to us and against which we may not be fully capable of insuring.
In particular, fluctuations in currency exchange rates can affect, on a U.S.
dollar equivalent basis, the amount of our equity contributions to, and
distributions from, our international projects. At times, we have hedged a
portion of our exposure to fluctuations in currency exchange rates. However,
hedge contracts may involve risks, including default by the other party to the
contract, and we cannot assure you that fluctuations in currency exchange rates
will be fully offset by these hedges.

Generally, the uncertainty of the legal structure in some foreign countries
in which we may develop or acquire projects could make it more difficult to
enforce our rights under agreements relating to the projects. In addition, the
laws and regulations of some countries may limit our ability to hold a majority
interest in some of the projects that we may develop or acquire.

The economic crisis in Indonesia has raised concerns over the ability of PT
PLN, the state owned utility, to meet its obligations under its power purchase
agreement with our Paiton project and has negatively affected and may continue
to negatively affect that project's dividends to us. See "Management's
Discussion and Analysis of Results of Operations and Financial Condition--
Commitments and Contingencies--Paiton."

The global independent power industry is characterized by numerous strong
and capable competitors, some of which may have more extensive operating
experience in the acquisition and development of power projects, larger staffs
and greater financial resources than we do. Further, in recent years some power
markets have been characterized by strong and increasing competition as a result
of regulatory changes and other factors which have contributed to a reduction in
market prices for power. These regulatory and other changes may continue to
increase competitive pressures in the markets where we operate. Increased
competition for new project investment opportunities may adversely affect our
ability to develop or acquire projects on economically favorable terms.

Our operations are subject to extensive regulation by governmental agencies
in each of the countries in which we conduct operations. See "--Regulatory
Matters." Our domestic projects are

18

subject to energy, environmental and other governmental laws and regulations at
the federal, state and local levels in connection with the development,
ownership and operation of the projects. Our projects are also subject to
federal, state and local laws and regulations that govern the geographical
location, zoning and land use of or with respect to a project. Our international
projects are subject to the energy, environmental and other laws and regulations
of the foreign jurisdictions in which these projects are located. The degree of
regulation varies according to each country and may be materially different from
the regulatory regimes in the United States.

We cannot assure you that the introduction of new laws or other future
regulatory developments in countries in which we conduct business will not have
a material adverse effect on our business, results of operations or financial
condition, nor can we assure you that we will be able to obtain and comply with
all necessary licenses, permits and approvals for our proposed energy projects.
If we cannot comply with all applicable regulations, our business, results of
operations and financial condition could be adversely affected.

In addition, if any of our projects were to lose its status as a qualifying
facility, eligible facility or foreign utility company under U.S. federal
regulations, we could become subject to regulation as a "holding company" under
the Public Utility Holding Company Act of 1935. If that were to occur, we would
be required to divest all operations not functionally related to the operation
of a single integrated utility system and would be required to obtain approval
of the Securities and Exchange Commission for various actions. See "--Regulatory
Matters--U.S. Federal Energy Regulation."

The operation of power generating plants involves many risks, including
start-up problems, the breakdown or failure of equipment or processes,
performance below expected levels of output, the inability to meet expected
efficiency standards, operator errors, strikes, work stoppages or labor disputes
and catastrophic events such as earthquakes, landslides, fires, floods,
explosions or similar calamities. The occurrence of any of these events could
significantly reduce revenues generated by our projects or increase their
generating expenses, thus diminishing distributions by the projects to us.
Equipment and plant warranties and insurance obtained by us may not be adequate
to cover lost revenues or increased expenses and, as a result, a project may be
unable to fund principal and interest payments under its financing obligations
and may operate at a loss. A default under a financing obligation of a project
subsidiary could cause us to lose our interest in the project.

Our strategy includes the development and acquisition of electric power
generation facilities. The development projects and acquisitions in which we
have invested, or in which we may invest in the future, may be large and
complex, and we may not be able to complete the development or acquisition of
any particular project. The development of a power project may require us to
expend significant sums for preliminary engineering, permitting, legal and other
expenses before we can determine whether we will win a competitive bid, or
whether a project is feasible, economically attractive or financeable. Moreover,
our access to capital for future projects is uncertain. Furthermore, due to the
effects of the California power crisis on Edison International, we do not expect
to receive capital contributions from Edison International in the near future.
We cannot assure you that we will be successful in obtaining financing for our
projects or that we will obtain sufficient additional equity capital, project
cash flow or additional borrowings to enable us to fund the equity commitments
required for future projects.

OUR OPERATING PROJECTS

DOMESTIC OVERVIEW

We currently own interests in 32 domestic operating projects in eight states
and one project in the Commonwealth of Puerto Rico. These operating projects
consist of 12 natural gas fired cogeneration projects, one coal fired
cogeneration project, seven coal fired exempt wholesale generator projects, one
waste coal project, one liquefied natural gas combined cycle cogeneration
project and 11 gas fired exempt wholesale generator projects. All our domestic
cogeneration projects, as well as the waste coal

19

project, are qualifying facilities under the Public Utility Regulatory Policies
Act. Our domestic operating projects have total generating capacity of 15,257
MW, of which our net ownership share is 13,231 MW.

The primary power sales contracts for four of our operating projects in 2000
and 1999 and five of our operating projects in 1998 are with Southern California
Edison Company. See "--Recent Developments--The California Power Crisis" for
further discussion of these projects. Our share of equity in earnings from these
projects accounted for 5% in 2000, 8% in 1999 and 13% in 1998 of our
consolidated revenues. The failure of Southern California Edison to fulfill its
contractual obligations could have a negative impact on a source of our
revenues. Under the terms of an agreement between Southern California Edison and
the Office of Ratepayer Advocates, the consumer advocacy branch of the
California Public Utilities Commission, Southern California Edison is prohibited
from entering into future power sales contracts with us or our affiliates
without Office of Ratepayer Advocates' and the California Public Utilities
Commission's consent. The terms of the agreement, however, do not affect the
terms of the existing power sales contracts between us and Southern California
Edison. Fuel supply for our projects generally is arranged through third party
suppliers and transporters.

In September 1998, the California Public Utilities Commission issued an
order which approved an agreement entered into between an operating cogeneration
project in which we have a 30% partnership interest and Southern California
Edison to terminate a power sales agreement. The termination agreement became
effective in February 1999.

20

DESCRIPTION OF DOMESTIC OPERATING PROJECTS

We have ownership or leasehold interests in the following domestic operating
projects:

ELECTRIC PRIMARY OWNERSHIP/
CAPACITY ELECTRIC TYPE OF LEASEHOLD
PROJECT LOCATION (IN MW) PURCHASER(2) FACILITY(3) INTEREST
- ------- ------------- -------- ------------ ------------------ ----------

American Bituminous(1)........ West Virginia 80 MPC Waste Coal 50%

Brooklyn Navy Yard............ New York 286 CE Cogeneration/EWG 50%

Coalinga(1)................... California 38 PG&E Cogeneration 50%

Commonwealth Atlantic......... Virginia 340 VEPCO EWG 50%

EcoElectrica(1)............... Puerto Rico 540 PREPA Cogeneration 50%

Gordonsville(1)............... Virginia 240 VEPCO Cogeneration/EWG 50%

Harbor(1)..................... California 80 Pool EWG 30%

Homer City(1)................. Pennsylvania 1,884 Pool EWG 100%

Hopewell...................... Virginia 356 VEPCO Cogeneration 25%

Illinois Plants
(12 projects)(1)............ Illinois 9,539 EG EWG 100%

James River................... Virginia 110 VEPCO Cogeneration 50%

Kern River(1)................. California 300 SCE Cogeneration 50%

March Point 1................. Washington 80 PSE Cogeneration 50%

March Point 2................. Washington 60 PSE Cogeneration 50%

Mid-Set(1).................... California 38 PG&E Cogeneration 50%

Midway-Sunset(1).............. California 225 SCE Cogeneration 50%

Nevada Sun-Peak............... Nevada 210 SPR EWG 50%

Saguaro(1).................... Nevada 90 SPR Cogeneration 50%

Salinas River(1).............. California 38 PG&E Cogeneration 50%

Sargent Canyon(1)............. California 38 PG&E Cogeneration 50%

Sycamore(1)................... California 300 SCE Cogeneration 50%

Watson........................ California 385 SCE Cogeneration 49%

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

(1) Operated by subsidiaries or affiliates of Edison Mission Energy; all other
projects are operated by unaffiliated third parties.

(2) Electric purchaser abbreviations are as follows:

CE Consolidated Edison Company of New York, Inc.
EG Exelon Generation Company
MPC Monongahela Power Company
Pool Regional electricity trading market
PG&E Pacific Gas & Electric Company
PREPA Puerto Rico Electric Power Authority
PSE Puget Sound Enery, Inc.
SCE Southern California Edison Company
SPR Sierra Pacific Resources
VEPCO Virginia Electric & Power Company

21

(3) All the cogeneration projects are gas fired facilities, except for the James
River project, which uses coal. All the exempt wholesale generator (EWG)
projects are gas fired facilities, except for the Homer City plant and six
of the Illinois Plants, which use coal.

INTERNATIONAL OVERVIEW

We own interests in 40 operating projects outside the United States. The
total generating capacity of these facilities is 12,779 MW, of which our net
ownership share is 9,528 MW.

DESCRIPTION OF INTERNATIONAL OPERATING PROJECTS

We have ownership interests in the following international operating
projects:

ELECTRIC PRIMARY
CAPACITY ELECTRIC OWNERSHIP
PROJECT LOCATION (IN MW) PURCHASER(2) INTEREST
- ------- --------------- -------- ------------ ---------

Contact (10 projects)..................... New Zealand(6) 2,449 Pool 42%

Derwent(1)................................ England 214 SE(3) 33%

Doga(1)................................... Turkey 180 TEAS 80%

Ferrybridge............................... England 1,989 Pool 100%

Fiddler's Ferry........................... England 1,995 Pool 100%

First Hydro (2 projects).................. Wales 2,088 Pool 100%

Iberian Hy-Power I (5 projects)........... Spain 43 FECSA 100%(7)

Iberian Hy-Power II (13 projects)......... Spain 43 FECSA 100%

ISAB...................................... Italy 512 GRTN 49%

Kwinana(1)................................ Australia 116 WP 70%

Loy Yang B................................ Australia 1,000 Pool(4) 100%

Paiton(1)................................. Indonesia 1,230 PLN 40%

Roosecote................................. England 220 NORWEB(5) 100%

TriEnergy................................. Thailand 700 EGAT 25%

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

(1) Operated by subsidiaries or affiliates of Edison Mission Energy; all other
projects are operated by unaffiliated third parties.

(2) Electric purchaser abbreviations are as follows:

GRTN Gestore Rete Transmissione Nazionale
EGAT Electricity Generating Authority of Thailand
FECSA Fuerzas Electricas de Cataluma, S.A.
NORWEB North Western Electricity Board
WP Western Power
Pool Electricity trading market for England,Wales, Australia and
New Zealand
PLN PT PLN
SE Southern Electric plc.
TEAS Turkiye Elektrik Urehm A.S.

(3) Sells to the pool with a long-term contract with SE.

(4) Sells to the pool with a long-term contract with the State Electricity
Commission of Victoria.

(5) Sells to the pool with a long-term contract with NORWEB.

22

(6) Minority interest in one project in Australia.

(7) Minority interest are owned by third parties in three of the projects.

OIL AND GAS INVESTMENTS

In 1988, we formed a wholly-owned subsidiary, Mission Energy Fuel Company,
to develop and invest in fuel interests. Since that time, Mission Energy Fuel
has invested in a number of oil and gas properties and a production company. Oil
and gas produced from the properties are generally sold at spot or short term
market prices.

FOUR STAR

As of December 31, 2000, we owned 36% of the stock of Four Star Oil & Gas
Company, a subsidiary of Texaco Inc. The underlying value of Four Star is
attributable to the production of oil and gas from nine producing properties.
Our proportionate interest in net quantities of proved reserves at December 31,
2000 totaled 180.6 billion cubic feet of natural gas and 10.4 million barrels of
oil.

In November 1999, we completed the sale of a portion of our interest in Four
Star to a company in which we hold a 50% interest. Net proceeds from the sale
were $20.5 million. We recorded an after-tax gain on the sale of our investment
of approximately $30 million. Our net ownership interest in Four Star was
reduced from 50% at December 31, 1998 to 34% as a result of the transaction. In
December 1999 and May and July 2000, we purchased additional shares of stock of
Four Star, increasing our ownership interest to 38%. On December 31, 2000,
shares of convertible preferred shares were converted to common shares, reducing
our net ownership interest to 36%.

COMPETITION

We compete with many other companies, including multinational development
groups, equipment suppliers and other independent power producers, including
affiliates of utilities, in selling electric power and steam. We also compete
with electric utilities in obtaining the right to install new generating
capacity. Over the past decade, obtaining a power sales contract with a utility
has generally become a progressively more difficult, expensive and competitive
process. Many power sales contracts are now awarded by competitive bidding,
which both increases the costs of obtaining these contracts and decreases the
chances of obtaining these contracts. We evaluate each potential project in an
effort to determine when the probability of success is high enough to justify
expenditures in developing a proposal or bid for the project.

Amendments to the Public Utility Holding Company Act of 1935 made by the
Energy Policy Act have increased the number of competitors in the domestic
independent power industry by reducing restrictions applicable to projects that
are not qualifying facilities under the Public Utility Regulatory Policies Act.
Retail wheeling of power, which is the offering by utilities of unbundled retail
distribution service, could also lead to increased competition in the
independent power market. See "--Regulatory Matters--Retail Competition."

TAX SHARING AGREEMENTS

We are included in the consolidated federal income tax and combined state
franchise tax returns of Edison International. We calculate our income tax
provision on a separate company basis under a tax sharing arrangement with The
Mission Group, which in turn has an agreement with Edison International. Tax
benefits generated by us and used in the Edison International consolidated tax
return are recognized by us without regard to separate company limitations.

23

SEASONALITY

Due to warmer weather during the summer months, electric revenues generated
from the Homer City plant and the Illinois Plants are usually higher during the
third quarter of each year. In addition, our third quarter revenues from energy
projects are materially higher than other quarters of the year due to a
significant number of our domestic energy projects located on the West Coast of
the United States, which generally have power sales contracts that provide for
higher payments during summer months. The First Hydro plants, Ferrybridge and
Fiddler's Ferry plants and the Iberian Hy-Power plants provide for higher
electric revenues during the winter months.

EMPLOYEES AND OFFICES

At December 31, 2000, we employed 3,391 people, all of whom were full time
employees and approximately 639, 146 and 1,294 of whom were covered by
collective bargaining agreements in the United Kingdom, Australia and the United
States, respectively. We have never experienced a work stoppage or strike. We
believe we have good relations with our employees. However, the term of the
collective bargaining agreement covering our employees at the Illinois Plants is
currently in dispute, with the union maintaining that the agreement's term could
expire as early as March 31, 2001 and we maintaining that the agreement remains
in effect until June 2002. Although we cannot predict the outcome of this
dispute, we believe that the impact on the operations of the Illinois Plants
will not be material.

We lease our corporate headquarters in Irvine, California and our principal
regional offices in London, Melbourne and Singapore. We also lease other smaller
offices in the United States and certain foreign countries.

REGULATORY MATTERS

GENERAL

Our operations are subject to extensive regulation by governmental agencies
in each of the countries in which we conduct operations. Our domestic projects
are subject to energy, environmental and other governmental laws and regulations
at the federal, state and local levels in connection with the development,
ownership and operation of, and use of electric energy, capacity and related
products, including ancillary services from, our projects. Federal laws and
regulations govern, among other things, transactions by and with purchasers of
power, including utility companies, the operations of a project and the
ownership of a project. Under limited circumstances where exclusive federal
jurisdiction is not applicable or specific exemptions or waivers from state or
federal laws or regulations are otherwise unavailable, federal and/or state
utility regulatory commissions may have broad jurisdiction over non-utility
owned electric power plants. Energy producing projects are also subject to
federal, state and local laws and regulations that govern the geographical
location, zoning, land use and operation of a project. Federal, state and local
environmental requirements generally require that a wide variety of permits and
other approvals be obtained before the commencement of construction or operation
of an energy producing facility and that the facility then operate in compliance
with these permits and approvals. While we believe the requisite approvals for
our existing projects have been obtained and that our business is operated in
substantial compliance with applicable laws, we remain subject to a varied and
complex body of laws and regulations that both public officials and private
parties may seek to enforce. Regulatory compliance for the construction of new
facilities is a costly and time consuming process. Intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures and may create a significant risk of expensive delays or
significant loss of value in a project if the project is unable to function as
planned due to changing requirements or local opposition.

24

Furthermore, each of our international projects is subject to the energy and
environmental laws and regulations of the foreign country in which this project
is located. The degree of regulation varies according to each country and may be
materially different from the regulatory regime in the United States.

U.S. FEDERAL ENERGY REGULATION

The Federal Energy Regulatory Commission has ratemaking jurisdiction and
other authority with respect to interstate sales and transmission of electric
energy under the Federal Power Act and with respect to certain interstate sales,
transportation and storage of natural gas under the Natural Gas Act of 1938. The
Securities and Exchange Commission has regulatory powers with respect to
upstream owners of electric and natural gas utilities under the Public Utility
Holding Company Act of 1935. The enactment of the Public Utility Regulatory
Policies Act of 1978 and the adoption of regulations thereunder by the Federal
Energy Regulatory Commission provided incentives for the development of
cogeneration facilities and small power production facilities using alternative
or renewable fuels by establishing certain exemptions from the Federal Power Act
and the Public Utility Holding Company Act for the owners of qualifying
facilities. The passage of the Energy Policy Act in 1992 further encouraged
independent power production by providing additional exemptions from the Public
Utility Holding Company Act for exempt wholesale generators and foreign utility
companies.

A "QUALIFYING FACILITY" under the Public Utility Regulatory Policies Act is
a cogeneration facility or a small power production facility that satisfies
criteria adopted by the Federal Energy Regulatory Commission. In order to be a
qualifying facility, a cogeneration facility must (i) sequentially produce both
useful thermal energy, such as steam, and electric energy, (ii) meet specified
operating standards, and energy efficiency standards when oil or natural gas is
used as a fuel source and (iii) not be controlled, or more than 50% owned by one
or more electric utilities (where "electric utility" is interpreted with
reference to the Public Utility Holding Company Act definition of an "electric
utility company"), electric utility holding companies (defined by reference to
the Public Utility Holding Company Act definitions of "electric utility company"
and "holding company") or affiliates of such entities. A small power production
facility seeking to be a qualifying facility must produce power from renewable
energy sources, such as geothermal energy, waste sources of fuel, such as waste
coal, or any combination thereof and must meet the ownership restrictions
discussed above. Before 1990, a small power production facility seeking to be a
qualifying facility was subject to 30 MW or 80 MW size limits, depending upon
its fuel source. In 1990, these limits were lifted for solar, wind, waste, and
geothermal qualifying facilities, provided that applications for or notices of
qualifying facility status were filed with the Federal Energy Regulatory
Commission for these facilities on or before December 31, 1994, and provided, in
the case of new facilities, the construction of these facilities commenced on or
before December 31, 1999.

An "EXEMPT WHOLESALE GENERATOR" under the Public Utility Holding Company Act
is an entity determined by the Federal Energy Regulatory Commission to be
exclusively engaged, directly or indirectly, in the business of owning and/or
operating specified eligible facilities and selling electric energy at wholesale
or, if located in a foreign country, at wholesale or retail.

A "FOREIGN UTILITY COMPANY" under the Public Utility Holding Company Act is,
in general, an entity located outside the United States that owns or operates
facilities used for the generation, distribution or transmission of electric
energy for sale or the distribution at retail of natural or manufactured gas,
but that derives none of its income, directly or indirectly, from such
activities within the United States.

FEDERAL POWER ACT. The Federal Power Act grants the Federal Energy
Regulatory Commission exclusive ratemaking jurisdiction over wholesale sales of
electricity in interstate commerce, including ongoing, as well as initial, rate
jurisdiction. This jurisdiction allows the Federal Energy Regulatory Commission
to revoke or modify previously approved rates. These rates may be based on a

25

cost-of-service approach or, in geographic and product markets determined by
Federal Energy Regulatory Commission to be workably competitive, may be
market-based. As noted, most qualifying facilities are exempt from the
ratemaking and several other provisions of the Federal Power Act. Exempt
wholesale generators and other non-qualifying facility independent power
projects are subject to the Federal Power Act and to the ratemaking jurisdiction
of the Federal Energy Regulatory Commission thereunder, but the Federal Energy
Regulatory Commission typically grants exempt wholesale generators the authority
to charge market-based rates as long as the absence of market power is shown. In
addition, the Federal Power Act grants the Federal Energy Regulatory Commission
jurisdiction over the sale or transfer of jurisdictional facilities, including
wholesale power sales contracts, and in some cases, jurisdiction over the
issuance of securities or the assumption of specified liabilities and some
interlocking directorates. In granting authority to make sales at market-based
rates, the Federal Energy Regulatory Commission typically also grants blanket
approval for the issuance of securities and partial waiver of the restrictions
on interlocking directorates.

Currently, in addition to the facilities owned or operated by us, a number
of our operating projects, including the Homer City plant, the Illinois Plants,
the Nevada Sun-Peak, Brooklyn Navy Yard, Commonwealth Atlantic and Harbor
facilities, are subject to the Federal Energy Regulatory Commission ratemaking
regulation under the Federal Power Act. Our future domestic non-qualifying
facility independent power projects will also be subject to Federal Energy
Regulatory Commission jurisdiction on rates.

THE PUBLIC UTILITY HOLDING COMPANY ACT. Unless exempt or found not to be a
holding company by the Securities and Exchange Commission, a company that falls
within the definition of a holding company must register with the Securities and
Exchange Commission and become subject to Securities and Exchange Commission
regulation as a registered holding company under the Public Utility Holding
Company Act. "HOLDING COMPANY" is defined in Section 2(a)(7) of the Public
Utility Holding Company Act to include, among other things, any company that
owns 10% or more of the voting securities of an electric utility company.
"ELECTRIC UTILITY COMPANY" is defined in Section 2(a)(3) of the Public Utility
Holding Company Act to include any company that owns facilities used for
generation, transmission or distribution of electric energy for resale. Exempt
wholesale generators and foreign utility companies are not deemed to be electric
utility companies and qualifying facilities are not considered facilities used
for the generation, transmission or distribution of electric energy for resale.
Securities and Exchange Commission precedent also indicates that it does not
consider "paper facilities," such as contracts and tariffs used to make power
sales, to be facilities used for the generation, transmission or distribution of
electric energy for resale, and power marketing activities will not, therefore,
result in an entity being deemed to be an electric utility company.

A registered holding company is required to limit its utility operations to
a single integrated utility system and to divest any other operations not
functionally related to the operation of that utility system. In addition, a
registered holding company will require Securities and Exchange Commission
approval for the issuance of securities, other major financial or business
transactions (such as mergers) and transactions between and among the holding
company and holding company subsidiaries.

Because it owns Southern California Edison, an electric utility company,
Edison International, our parent company, is a holding company. Edison
International is, however, exempt from registration pursuant to Section 3(a)(1)
of the Public Utility Holding Company Act, because the public utility operations
of the holding company system are predominantly intrastate in character.
Consequently, we are not a subsidiary of a registered holding company, so long
as Edison International continues to be exempt from registration pursuant to
Section 3(a)(1) or another of the exemptions enumerated in Section 3(a). Nor are
we a holding company under the Public Utility Holding Company Act, because our
interests in power generation facilities are exclusively in qualifying
facilities, exempt wholesale generators and foreign utility companies. All
international projects and specified U.S. projects that we are currently
developing or proposing to acquire will be non-qualifying facility independent
power

26

projects. We intend for each project to qualify as an exempt wholesale generator
or as a foreign utility company. Loss of exempt wholesale generator, qualifying
facility or foreign utility company status for one or more projects could result
in our becoming a holding company subject to registration and regulation under
the Public Utility Holding Company Act and could trigger defaults under the
covenants in our project agreements. Becoming a holding company could, on a
retroactive basis, lead to, among other things, fines and penalties and could
cause certain of our project agreements and other contracts to be voidable.

PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978

The Public Utility Regulatory Policies Act provides two primary benefits to
qualifying facilities. First, as discussed above, ownership of qualifying
facilities will not result in a company's being deemed an electric utility
company for purposes of the Public Utility Holding Company Act. In addition, all
cogeneration facilities and all small production facilities that generate power
from sources other than geothermal and whose capacity exceeds 30 MWs that are
qualifying facilities are exempt from most provisions of the Federal Power Act
and regulations of the Federal Energy Regulatory Commission thereunder. Second,
the Federal Energy Regulatory Commission regulations promulgated under the
Public Utility Regulatory Policies Act require that electric utilities purchase
electricity generated by qualifying facilities at a price based on the
purchasing utility's avoided cost, and that the utilities sell back up power to
the qualifying facility on a non discriminatory basis. The Federal Energy
Regulatory Commission's regulations define "avoided cost" as the incremental
cost to an electric utility of electric energy or capacity or both which, but
for the purchase from the qualifying facility or qualifying facilities, the
utility would generate itself or purchase from another source. The Federal
Energy Regulatory Commission's regulations also permit qualifying facilities and
utilities to negotiate agreements for utility purchases of power at prices
different than the utility's avoided costs. While it has been common for
utilities to enter into long term contracts with qualifying facilities in order,
among other things, to facilitate project financing of independent power
facilities and to reflect the deferral by the utility of capital costs for new
plant additions, increasing competition and the development of new power markets
have resulted in a trend toward shorter term power contracts that would place
greater risk on the project owner.

If one of the projects in which we have an interest were to lose its status
as a qualifying facility, the project would no longer be entitled to the
qualifying facility-related exemptions from regulation under the Public Utility
Holding Company Act and the Federal Power Act. As a result, the project could
become subject to rate regulation by the Federal Energy Regulatory Commission
under the Federal Power Act, and we could inadvertently become a holding company
under the Public Utility Holding Company Act. Under Section 26(b) of the Public
Utility Holding Company Act, any project contracts that are entered into in
violation of the Public Utility Holding Company Act, including contracts entered
into during any period of non-compliance with the registration requirement,
could be determined by the courts or the Securities and Exchange Commission to
be void. If a project were to lose its qualifying facility status, we could
attempt to avoid holding company status on a prospective basis by qualifying the
project owner as an exempt wholesale generator. However, assuming this changed
status would be permissible under the terms of the applicable power sales
agreement, rate approval from the Federal Energy Regulatory Commission would be
required. In addition, the project would be required to cease selling
electricity to any retail customers, in order to qualify for exempt wholesale
generator status, and could become subject to additional state regulation. Loss
of qualifying facility status by one project could also potentially cause other
projects with the same partners to lose their qualifying facility status to the
extent those partners became electric utilities, electric utility holding
companies or affiliates of such companies for purposes of the ownership criteria
applicable to qualifying facilities. Loss of qualifying facility status could
also trigger defaults under covenants to maintain qualifying facility status in
the project's power sales agreements, steam sales agreements and financing
agreements and result in termination, penalties or acceleration of indebtedness
under such

27

agreements. If a power purchaser were to cease taking and paying for electricity
or were to seek to obtain refunds of past amounts paid because of the loss of
qualifying facility status, we cannot assure you that the costs incurred in
connection with the project could be recovered through sales to other
purchasers. Moreover, our business and financial condition could be adversely
affected if regulations or legislation were modified or enacted that changed the
standards for maintaining qualifying facility status or that eliminated or
reduced the benefits, such as the mandatory purchase provisions of the Public
Utility Regulatory Policies Act and exemptions currently enjoyed by qualifying
facilities. Loss of qualifying facility status on a retroactive basis could lead
to, among other things, fines and penalties being levied against us, or claims
by a utility customer for the refund of payments previously made.

We endeavor to develop our qualifying facility projects, monitor regulatory
compliance by these projects and choose our customers in a manner that minimizes
the risks of losing these projects' qualifying facility status. However, some
factors necessary to maintain qualifying facility status are subject to risks of
events outside of our control. For example, loss of a thermal energy customer or
failure of a thermal energy customer to take required amounts of thermal energy
from a cogeneration facility that is a qualifying facility could cause a
facility to fail to meet the requirements regarding the minimum level of useful
thermal energy output. Upon the occurrence of this type of event, we would seek
to replace the thermal energy customer or find another use for the thermal
energy that meets the requirements of the Public Utility Regulatory Policies
Act.

NATURAL GAS ACT

Twenty-four of the domestic operating facilities that we own, operate or
have investments in use natural gas as their primary fuel. Under the Natural Gas
Act, the Federal Energy Regulatory Commission has jurisdiction over certain
sales of natural gas and over transportation and storage of natural gas in
interstate commerce. The Federal Energy Regulatory Commission has granted
blanket authority to all persons to make sales of natural gas without
restriction but continues to exercise significant oversight with respect to
transportation and storage of natural gas services in interstate commerce.

STATE ENERGY REGULATION

State public utility commissions have broad jurisdiction over non-qualifying
facility independent power projects, including exempt wholesale generators,
which are considered public utilities in many states. This jurisdiction often
includes the issuance of certificates of public convenience and necessity and/or
other certifications to construct, own and operate a facility, as well as the
regulation of organizational, accounting, financial and other corporate matters
on an ongoing basis. Qualifying facilities may also be required to obtain these
certificates of public convenience and necessity in some states. Some states
that have restructured their electric industries require generators to register
to provide electric service to customers. Many states are currently undergoing
significant changes in their electric statutory and regulatory frameworks that
result from restructuring the electric industries that may affect generators in
those states. Although the Federal Energy Regulatory Commission generally has
exclusive jurisdiction over the rates charged by a non-qualifying facility
independent power project to its wholesale customers, a state's public utility
commission has the ability, in practice, to influence the establishment of these
rates by asserting jurisdiction over the purchasing utility's ability to pass
through the resulting cost of purchased power to its retail customers. A state's
public utility commission also has the authority to determine avoided costs for
qualifying facilities and to regulate the retail rates charged by qualifying
facilities. In addition, states may assert jurisdiction over the siting and
construction of independent power projects and, among other things, the issuance
of securities, related party transactions and the sale or other transfer of
assets by these facilities. The actual scope of jurisdiction over independent
power projects by state public utility commissions varies from state to state.

28

In addition, state public utility commissions may seek to modify, suspend or
terminate a qualifying facility's power sales contract under specified
circumstances. This could occur if the state public utility commission were to
determine that the pricing mechanism of the power sales contract is unfairly
high in light of the current prevailing market cost of power for the utility
purchasing the power. In this instance, the state public utility commission
could attempt to alter the terms of the power sales contract to reflect more
accurately market conditions for the prevailing cost of power. While we believe
that these attempts are not common, and that the state public utility commission
may not have any jurisdiction to modify the terms of the wholesale power sales,
we cannot assure you that the power sales contracts of our projects will not be
subject to adverse regulatory actions.

The California Public Utilities Commission has authorized the electric
utilities in California to "monitor" compliance by qualifying facilities with
the Public Utility Regulatory Policies Act rules and regulations. However, the
United States Court of Appeals for the Ninth Circuit found in 1994 that a
California Public Utilities Commission program was preempted by the Public
Utility Regulatory Policies Act, to the extent it authorized utilities to
determine that a qualifying facility was not in compliance with the Public
Utility Regulatory Policies Act rules and regulations, to then pay a reduced
avoided cost rate and to take other action contrary to a facility's status as a
qualifying facility. The court did, however, uphold reasonable monitoring of
qualifying facility operating data. Other states, like New York and Virginia,
have also instituted qualifying facility monitoring programs.

We buy and transport the natural gas used at our domestic facilities through
local distribution companies. State public utility commissions have jurisdiction
over the transportation of natural gas by local distribution companies. Each
state's regulatory laws are somewhat different. However, all generally require
the local distribution companies to obtain approval from the relevant public
utility commission for the construction of facilities and transportation
services if the local distribution company's generally applicable tariffs do not
cover the proposed transaction. Local distribution companies' rates are usually
subject to continuing public utility commission oversight.

CALIFORNIA DEREGULATION

DEREGULATION PLAN. Efforts to restructure the California electric industry
began in 1994 in response to high electricity prices. A final restructuring
order was issued by the California Public Utility Commission in December 1995,
which led to the unanimous enactment of Assembly Bill 1890, the Restructuring
Legislation, in September 1996 and its signature by the Governor of California
at the time. The main points of this legislation included the following:

- the creation of the California System Operator and California Power
Exchange by January 1998 and simultaneous initiation of direct access
between electricity suppliers and end use customers;

- the creation of the California Electricity Oversight Board; and

- the adoption of a Competitive Transition Charge for the recovery of
stranded costs.

The state's utilities were authorized to divest much of their generation
assets and apply the proceeds to their stranded costs resulting from
deregulation of the retail markets. The restructuring also required that
California investor-owned utilities sell into and purchase most of their power
requirements from the California Power Exchange but did not permit them to hedge
their risk through long-term forward contracts. Through this mechanism, a spot
market was created that set the purchase price for power by establishing the
highest bid as the market clearing price for all bidders.

Additionally, the legislation provided for a limited transition period
ending March 31, 2002, or an earlier date at which it is determined that a
utility has recovered its stranded costs. During the transition period, there is
a rate reduction of no less than 10% for residential and small commercial
ratepayers. The rate reduction was financed through the issuance of rate
reduction bonds. The rate reduction scheme capped retail electric rates at 1996
levels. The retail rate cap and bond offering were

29

intended to assist utilities in the recovery of stranded costs incurred by their
investments made prior to deregulation. At the conclusion of the transition
period, the legislation anticipated that residential and small business
purchasers of electricity would pay 20% less for electricity due to effective
implementation of Assembly Bill 1890.

THE CURRENT POWER CRISIS IN CALIFORNIA. Wholesale power prices rose
significantly in California during 2000 and early 2001, we believe primarily as
a result of supply shortages, high natural gas and petroleum prices and a
variety of other factors. Unregulated wholesale rates rose above the fixed
retail rates the California utilities were permitted to charge their customers.
The inability of utilities to recover the full amount of wholesale prices has
led to billions of dollars in unrecovered costs by the California utilities and
to their current liquidity crisis.

Ongoing legislative and regulatory efforts seek to address both market
structure and supply problems. In September 2000, legislation was enacted in
California seeking to accelerate the power plant siting approval process. Other
initiatives may seek to stimulate entry into the market of new power generation
capacity. In December 2000, the Federal Energy Regulatory Commission issued an
order permitting California utilities to negotiate long-term supply contracts,
and establishing a "soft-cap" limiting the wholesale price that could be charged
without additional cost justification, as opposed to allowing the highest bid
price to set the market clearing price for all generators. At that time the
Federal Energy Regulatory Commission refused to set a regional price cap for
wholesale power prices as sought by state officials. On January 4, 2001, the
California Public Utilities Commission authorized an interim surcharge on
customers' bills, subject to refund, which is to be applied only to ongoing
power procurement costs and will result in rate increases of 7-15% during a
90-day period. This interim surcharge does not otherwise affect the retail rate
freeze which has been in effect since deregulation began in 1998. On March 27,
2001, the California Public Utilities Commission authorized a rate increase of
three cents per kilowatt-hour, or approximately 50%, but kept the retail rate
freeze in effect for Southern California Edison and Pacific Gas and Electric.

On February 1, 2001, legislation was enacted in California that, among other
things: authorized the California Department of Water Resources to enter into
long-term power purchase contracts; authorized the Department of Water Resources
to sell revenue bonds to finance electricity purchases; provided for rate
recovery of the Department of Water Resources' costs through rate increases,
subject to specified limits; authorized the Department of Water Resources to
sell power at its costs to retail customers and, with specified exceptions, to
local publicly owned electric utilities; appropriated a total of $500 million
toward additional spot market power purchases; and provided for suspension of
the ability of customers to choose alternative energy providers while the
Department of Water Resources is procuring power. Executive Orders promoting
energy conservation measures were also signed by the Governor of California,
including a mandatory requirement that retail businesses reduce outdoor retail
lighting during non-business hours or face fines. In addition, on February 21,
2001, the California Senate approved formation of a California state power
authority, which (if formed) will have the power to own and operate generation
and transmission facilities in the state. The formation of the state power
authority has not yet been approved by the California Assembly. The Governor of
California has also proposed that the state acquire the transmission assets of
the investor-owned utilities, including Southern California Edison, and that the
proceeds from such sales be applied against the utilities' existing debts.

As part of an investigation that the Federal Energy Regulatory Commission
has been conducting on wholesale power prices in the California market, the
Federal Energy Regulatory Commission ordered a number of power generators, not
including Edison Mission Energy, to justify charges to California utilities
during the months of January and February 2001 or refund such charges. The
Federal Energy Regulatory Commission has further required a power generator and
a marketer to justify their decision to bring plants off-line or refund to the
California utilities the increased costs resulting from such shutdowns. Also,
the Governor of California and other western states have

30

petitioned the Federal Energy Regulatory Commission and the United States
Congress for "cost-based" price caps for wholesale power rates on the spot
market, permitting power generators to recover all their costs with a small
level of profit. Further actions are anticipated as both the Federal and
California state governments have intervened to address the short- and long-term
issues associated with the power crisis. A recent Federal Energy Regulatory
Commission report estimates that it could take up to 24 months to address these
issues.

On March 15, 2001, the California Public Utilities Commission released a
draft of a proposed order instituting an investigation into whether California's
investor-owned utilities, including Southern California Edison, have complied
with past Commission decisions authorizing the formation of their holding
companies and governing affiliate transactions, as well as applicable statutes.
Action on this agenda item repeatedly has been deferred, including at the
Commission meeting on March 27, 2001, and the item has continued to appear on
the agendas for subsequent Commission meetings. The proposed order would reopen
the past holding company decisions and initiate an investigation into the
following matters:

- whether the holding companies, including Edison International, violated
requirements to give priority to the capital needs of their respective
utility subsidiaries;

- whether the ring-fencing actions by Edison International and PG&E
Corporation and their respective non-utility affiliates also violated the
requirements to give priority to the capital needs of their utility
subsidiaries;

- whether the payment of dividends by the utilities violated requirements
that the utilities maintain dividend policies as though they were
comparable stand-alone utility companies;

- any additional suspected violations of laws or Commission rules and
decisions; and

- whether additional rules, conditions, or other changes to the holding
company decisions are necessary.

We cannot predict whether the Commission will institute this investigation or
what effects any investigation or subsequent actions by the Commission may have
on Edison International or indirectly on us.

On March 27, 2001, the California Public Utilities Commission issued a
decision that ordered the three California investor owned utilities, including
Southern California Edison and Pacific Gas and Electric, to commence payment for
power generated from qualifying facilities beginning in April 2001. In addition,
the decision modified the pricing formula for determining short run avoided
costs for qualifying facilities subject to these provisions. Depending on how
the utilities react to this order, the immediate impact of this decision may be
to commence payment in April 2001 at significantly reduced prices for power to
qualifying facilities subject to this pricing adjustment. Furthermore, this
decision called for further study of the pricing formula tied to short run
avoided costs and, accordingly, may be subject to more changes in the future.
Finally, this decision is subject to challenge before the Commission, the
Federal Energy Regulatory Commission and, potentially, state or federal courts.
Although it is premature to assess the full effect of this recent decision, it
could have a material adverse effect on our investment in the California
partnerships, depending on how it is implemented and future changes in the
relationship between the pricing formula and the actual cost of natural gas
procured by our California partnerships. This decision did not address payment
to the qualifying facilities for amounts due prior to April 2001.

RECENT FOREIGN REGULATORY MATTERS

UNITED KINGDOM. The U.K.'s new electricity trading arrangements are the
direct result of an October 1997 request by the Minister for Science, Energy and
Industry who asked the U.K. Director

31

General of Electricity Supply to review the operation of the pool pricing
system. In July 1998 the Director General proposed that the current structure of
contracts for differences and compulsory trading via the pool at half-hourly
clearing prices bid a day ahead be abolished. The U.K. Government accepted the
proposals in October 1998 subject to reservations. Following this, further
proposals were published by the Government and the Director General in July and
October 1999. The proposals include, among other things, the establishment of a
spot market or voluntary short-term power exchanges operating from 24 to
3 1/2-hours before a trading period; a balancing mechanism to enable the system
operator to balance generation and demand and resolve any transmission
constraints; a mandatory settlement process for recovering imbalances between
contracted and metered volumes with strong incentives for being in balance; and
a Balancing and Settlement Code Panel to oversee governance of the balancing
mechanism. Contracting over time periods longer than the day-ahead market are
not directly affected by the proposals. Physical bilateral contracts will
replace the current contracts for differences, but will function in a similar
manner. However, it remains difficult to evaluate the future impact of the
proposals. A key feature of the new electricity trading arrangements is to
require firm physical delivery which means that a generator must deliver, and a
consumer must take delivery, against their contracted positions or face
assessment of energy imbalance penalty charges by the system operator. A
consequence of this should be to increase greatly the motivation of parties to
contract in advance and develop forwards and futures markets of greater
liquidity than at present. Recent experience has been that the new electricity
trading arrangements have placed a significant downward pressure on forward
contract prices. Furthermore, another consequence may be that counterparties may
require additional credit support, including parent company guarantees or
letters of credit. Legislation in the form of the Utilities Act, which was
approved July 28, 2000, allows for the implementation of new electricity trading
arrangements and the necessary amendments to generators' licenses. Various key
documents were designated by the Secretary of State and signed by participants
on August 14, 2000 (the Go-Active Date); however, due to difficulties
encountered during testing, implementation of the new electricity trading
arrangements has been delayed from November 21, 2000 until March 27, 2001.

A warmer-than-average winter (January to March 2000), the entry of new
operations into the generation market, the impending introduction of the new
electricity trading arrangements coupled with uncertainties surrounding the new
Utilities Act and action by the Director General to control abuse of market
power, discussed below, contributed to a drop in the energy component of pool
prices throughout the year (time weighted average System Marginal Price dropped
from L22.39/MWh in 1999 to L18.75/MWh in 2000) and depressed forward prices for
winter 2000/2001. We have entered into contracts for differences for the
majority of our forecasted generation through the winter 2000/2001, and
accordingly, have mitigated the downside risks to further decreases in energy
prices. Despite improvement in capacity prices during August, September and
early October 2000, and a slight firming of forward prices, the short-term
prices for energy continue to be below prior years. As a result of the
foregoing, we continue to expect lower revenues from our Ferrybridge and
Fiddler's Ferry plants.

The Utilities Act sets a principal objective for the Government and the
Director General to "protect the interests of consumers. .. where appropriate by
promoting competition. .. ". This represents a shift in emphasis toward the
consumer interest. But this is qualified by a recognition that license holders
should be able to finance their activities. The Act also contains new powers for
the Government to issue guidance to the Director General on social and
environmental matters, changes to the procedures for modifying licenses and a
new power for the Director General to impose financial penalties on companies
for breach of license conditions. We will be monitoring the operation of these
new provisions.

NEW ZEALAND. The New Zealand Government has been undergoing a steady
process of electric industry deregulation since 1987. Reform in the distribution
and retail supply sector began in 1992 with legislation that deregulated
electricity distribution and provided for competition in the retail electric

32

supply function. The New Zealand Energy Market, established in 1996, is a
voluntary competitive wholesale market which allows for the trading of physical
energy on a half-hourly basis. The Electricity Industry Reform Act, which was
passed in July 1998, was designed to increase competition at the wholesale
generation level by splitting up Electricity Company of New Zealand Limited, the
large state-owned generator, into three separate generation companies. The
Electricity Industry Reform Act also prohibits the ownership of both generation
and distribution assets by the same entity.

The New Zealand Government commissioned an inquiry into the electricity
industry in February 2000. This Inquiry Board's report was presented to the
government in mid 2000. The main focus of the report was on the monopoly
segments of the industry, transmission and distribution, with substantial
limitations being recommended in the way in which these segments price their
services in order to limit their monopoly power. Recommendations were also made
with respect to the retail customer in order to reduce barriers to customers
switching. In addition, the Board made recommendations in relation to the
wholesale market's governance arrangements with the purpose of streamlining
them. The recommended changes are now being progressively implemented.

TRANSMISSION OF WHOLESALE POWER

Generally, projects that sell power to wholesale purchasers other than the
local utility to which the project is interconnected require the transmission of
electricity over power lines owned by others, also known as wheeling. The prices
and other terms and conditions of transmission contracts are regulated by the
Federal Energy Regulatory Commission, when the entity providing the wheeling
service is a jurisdictional public utility under the Federal Power Act. Until
1992, the Federal Energy Regulatory Commission's ability to compel wheeling was
very limited, and the availability of voluntary wheeling service could be a
significant factor in determining whether a site was viable for project
development.

The Federal Energy Regulatory Commission's authority under the Federal Power
Act to require electric utilities to provide transmission service on a case by
case basis to qualifying facilities, exempt wholesale generators, and other
power generators was expanded substantially by the Energy Policy Act.
Furthermore, in 1996 the Federal Energy Regulatory Commission issued a
rulemaking order, Order 888, in which the Federal Energy Regulatory Commission
asserted the power, under its authority to eliminate undue discrimination in
transmission, to compel all jurisdictional public utilities under the Federal
Power Act to file open access transmission tariffs consistent with a pro forma
tariff drafted by the Federal Energy Regulatory Commission. The Federal Energy
Regulatory Commission subsequently issued Orders 888-A, 888-B and 888-C to
clarify the terms that jurisdictional transmitting utilities are required to
include in their open access transmission tariffs. The Federal Energy Regulatory
Commission also issued Order 889, which required those transmitting utilities to
abide by specified standards of conduct when using their own transmission
systems to make wholesale sales of power, and to post specified transmission
information, including information about transmission requests and availability,
on a publicly available computer bulletin board. Although the pro forma tariff
does not cover the pricing of transmission service, Order 888 and the
subsequently issued regional transmission organization rulemaking are expected
to improve transmission access for independent power producers like us. A 1999
decision by the United States Court of Appeals for the Eighth Circuit has cast
doubt on the extent of the Federal Energy Regulatory Commission's authority to
require specified curtailment policies in the pro forma tariff. The United
States Court of Appeals for the D.C. Circuit issued an opinion on June 30, 2000
that affirmed the Federal Energy Regulatory Commission's Order 888 et seq. in
all material respects.

RETAIL COMPETITION

In response to pressure from retail electric customers, particularly large
industrial users, the state commissions or state legislatures of most states are
considering, or have considered, whether to open the retail electric power
market to competition. Retail competition is possible when a customer's local

33

utility agrees, or is required, to "unbundle" its distribution service (for
example, the delivery of electric power through its local distribution lines)
from its transmission and generation service (for example, the provision of
electric power from the utility's generating facilities or wholesale power
purchases). Several state commissions and legislatures have issued orders or
passed legislation requiring utilities to offer unbundled retail distribution
service, which is called retail wheeling, and phasing in retail wheeling over
the next several years.

The competitive pricing environment that will result from retail competition
may cause utilities to experience revenue shortfalls and deteriorating
creditworthiness. However, we expect that most, if not all, state plans will
insure that utilities receive sufficient revenues, through a distribution
surcharge if necessary, to pay their obligations under existing long-term power
purchase contracts with qualifying facilities and exempt wholesale generators.
On the other hand, qualifying facilities and exempt wholesale generators may be
subject to pressure to lower their contract prices in an effort to reduce the
stranded investment costs of their utility customers.

We believe that, as a predominantly low cost producer of electricity, we
will ultimately benefit from any increased competition that may arise from the
opening of the retail market. Although our exempt wholesale generators are
forbidden under the Public Utility Holding Company Act from selling electric
power in the retail market, our exempt wholesale generators can sell at
wholesale to a power marketer which could resell at retail. Furthermore,
qualifying facilities are permitted to market power directly to large industrial
users that could not previously be served, because of local franchise laws or
the inability to obtain retail wheeling. We also believe we will compete
effectively as a wholesale supplier to power marketers serving the newly-open
retail markets.

ENVIRONMENTAL REGULATION

We are subject to environmental regulation by federal, state and local
authorities in the United States and foreign regulatory authorities with
jurisdiction over projects located outside the United States. We believe that we
are in substantial compliance with environmental regulatory requirements and
that maintaining compliance with current requirements will not materially affect
our financial position or results of operations. However, possible future
developments, such as the promulgation of more stringent environmental laws and
regulations, and future proceedings which may be taken by environmental
authorities, could affect the costs and the manner in which we conduct our
business and could cause us to make substantial additional capital expenditures.
We cannot assure you that we would be able to recover these increased costs from
our customers or that our financial position and results of operations would not
be materially adversely affected.

Typically, environmental laws require a lengthy and complex process for
obtaining licenses, permits and approvals prior to construction and operation of
a project. Meeting all the necessary requirements can delay or sometimes prevent
the completion of a proposed project as well as require extensive modifications
to existing projects, which may involve significant capital expenditures.

The Clean Air Act provides the statutory framework to implement a program
for achieving national ambient air quality standards in areas exceeding such
standards and provides for maintenance of air quality in areas already meeting
such standards. Among other requirements, it also restricts the emission of
toxic air contaminants and provides for the reduction of sulfur dioxide
emissions to address acid deposition. In 1990, Congress passed amendments to the
Clean Air Act that greatly expanded the scope of federal regulations in several
significant respects. We expect to spend approximately $67 million in 2001 to
install upgrades to the environmental controls at the Homer City plant to
control sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate
upgrades to the environmental controls at the Illinois Plants to control
nitrogen oxide emissions to result in expenditures of approximately
$61 million, $67 million, $130 million, $123 million and $57 million for 2001,
2002, 2003, 2004 and 2005, respectively. Provisions related to nonattainment,
air toxins, permitting of new and

34

existing units, enforcement and acid rain may affect our domestic plants;
however, final details of all these programs have not been issued by the United
States Environmental Protection Agency and state agencies. In addition, at the
Ferrybridge and Fiddler's Ferry plants we anticipate environmental costs arising
from plant modification of approximately $52 million for the 2001-2005 period.

We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership
which owns and operates a liquified natural gas import terminal and cogeneration
project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection
Agency issued to EcoElectrica a notice of violation and a compliance order
alleging violations of the Federal Clean Air Act primarily related to start-up
activities. Representatives of EcoElectrica have met with the Environmental
Protection Agency to discuss the notice of violations and compliance order. To
date, EcoElectrica has not been informed of the commencement of any formal
enforcement proceedings. It is premature to assess what, if any, action will be
taken by the Environmental Protection Agency.

On November 3, 1999, the United States Department of Justice filed suit
against a number of electric utilities for alleged violations of the Clean Air
Act's "new source review" requirements related to modifications of air emissions
sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In
addition, the United States Environmental Protection Agency has also issued
administrative notices of violation alleging similar violations at additional
power plants owned by some of the same utilities named as defendants in the
Department of Justice lawsuit, as well as other utilities, and also issued an
administrative order to the Tennessee Valley Authority for similar violations at
certain of its power plants. The Environmental Protection Agency has also issued
requests for information pursuant to the Clean Air Act to numerous other
electric utilities seeking to determine whether these utilities also engaged in
activities that may have been in violation of the Clean Air Act's new source
review requirements.

To date, one utility, the Tampa Electric Company, has reached a formal
agreement with the United States to resolve alleged new source review
violations. Two other utilities, the Virginia Electric & Power Company and
Cinergy Corp., have reached agreements in principle with the Environmental
Protection Agency. In each case, the settling party has agreed to incur over
$1 billion in expenditures over several years for the installation of additional
pollution control, the retirement or repowering of coal fired generating units,
supplemental environmental projects and civil penalties. These agreements
provide for a phased approach to achieving required emission reductions over the
next 10-15 years. The settling utilities have also agreed to pay civil penalties
ranging from $3.5 million to $8.5 million.

Prior to our purchase of the Homer City plant, the Environmental Protection
Agency requested information from the prior owners of the plant concerning
physical changes at the plant. Other than with respect to the Homer City plant,
no proceedings have been initiated or requests for information issued with
respect to any of our United States facilities. However, we have been in
informal voluntary discussions with the Environmental Protection Agency relating
to these facilities, which may result in the payment of civil fines. We cannot
assure you that we will reach a satisfactory agreement or that these facilities
will not be subject to proceedings in the future. Depending on the outcome of
the proceedings, we could be required to invest in additional pollution control
requirements, over and above the upgrades we are planning to install, and could
be subject to fines and penalties.

A new ambient air quality standard was adopted by the Environmental
Protection Agency in July 1997 to address emissions of fine particulate matter.
It is widely understood that attainment of the fine particulate matter standard
may require reductions in nitrogen oxides and sulfur dioxides, although under
the time schedule announced by the Environmental Protection Agency when the new
standard was adopted, non-attainment areas were not to have been designated
until 2002 and control measures to meet the standard were not to have been
identified until 2005. In May 1999, the United States Court of Appeals for the
District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act,

35

the section of the Clean Air Act requiring the promulgation of national ambient
air quality standards, as interpreted by the Environmental Protection Agency,
was an unconstitutional delegation of legislative power. The Court of Appeals
remanded both the fine particulate matter standard and the revised ozone
standard to allow the EPA to determine whether it could articulate a
constitutional application of Section 109(b)(1). On February 27, 2001, the
Supreme Court, in WHITMAN V. AMERICAN TRUCKING ASSOCIATIONS, INC., reversed the
Circuit Court's judgment on this issue and remanded the case back to the Court
of Appeals to dispose of any other preserved challenges to the particulate
matter and ozone standards. Accordingly, as the final application of the revised
particulate matter ambient air quality standard is potentially subject to
further judicial proceedings, the impact of this standard on our facilities is
uncertain at this time.

On December 20, 2000, the Environmental Protection Agency issued a
regulatory finding that it is "necessary and appropriate" to regulate emissions
of mercury and other hazardous air pollutants from coal-fired power plants. The
agency has added coal-fired power plants to the list of source categories under
Section 112(c) of the Clean Air Act for which "maximum available control
technology" standards will be developed. Eventually, unless overturned or
reconsidered, the Environmental Protection Agency will issue technology-based
standards that will apply to every coal-fired unit owned by us or our affiliates
in the United States. This section of the Clean Air Act provides only for
technology-based standards, and does not permit market trading options. Until
the standards are actually promulgated, the potential cost of these control
technologies cannot be estimated, and we cannot evaluate the potential impact on
the operations of our facilities.

Since the adoption of the United Nations Framework on Climate Change in
1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton Administration participated in the
Kyoto, Japan negotiations, where the basis of a Climate Change treaty was
formulated. Under the treaty, known as the Kyoto Protocol, the United States
would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7%
from 1990 levels. However, because of opposition to the treaty in the United
States Senate, the Kyoto Protocol has not been submitted to the Senate for
ratification. Although legislative developments at the federal and state level
related to controlling greenhouse gas emissions are beginning, we are not aware
of any state legislative developments in the states in which we operate. If the
United States ratifies the Kyoto Protocol or we otherwise become subject to
limitations on emissions of carbon dioxide from its plants, these requirements
could have a significant impact on our operations.

The Comprehensive Environmental Response, Compensation, and Liability Act,
which is also known as CERCLA, and similar state statutes, require the cleanup
of sites from which there has been a release or threatened release of hazardous
substances. We are not aware of any material liabilities under this act;
however, we cannot assure you that we will not incur CERCLA liability or similar
state law liability in the future.

ITEM 2. PROPERTIES

We lease our principal office in Irvine, California. This lease is
approximately 142,000 square feet. The term of the lease for approximately
65,500 square feet expires on December 31, 2004 with two five-year options to
extend. The term of the lease for the balance of approximately 76,500 square
feet expires on December 31, 2004 with no options to extend. We also lease
office space in Chicago, Illinois, Chantilly, Virginia, Boston, Massachusetts,
Fairfax, Virginia and Washington, D.C. The Chicago lease is approximately 41,000
square feet and expires on December 31, 2009. The Chantilly lease is
approximately 30,000 square feet and expires on October 31, 2009. The Boston
lease is approximately 27,000 square feet and expires on June 30, 2007. Both the
Fairfax and the Washington, D.C. leases are immaterial. At December 31, 2000,
approximately 34% of above space was either available for sublease or subleased.
Our subsidiaries in the Asia Pacific region lease office space in Manila,
Philippines; Melbourne, Australia; Jakarta, Indonesia; and Singapore. Our
subsidiaries in the Europe, Central Asia,

36

Middle East and Africa region lease office space in Barcelona, Spain; Esenyurt,
Turkey; London, England; and Rome, Italy. These subsidiary leases are
immaterial.

The following table shows the material properties owned or leased by us or
our investments. Each property represents at least five percent of our income
before tax or is one in which we have an investment balance greater than
$50 million. All these properties are subject to mortgages or other liens or
encumbrances granted to the lenders providing financing for the plant or
project.

DESCRIPTION OF PROPERTIES

BUSINESS INTEREST
PLANT OR PROJECT SEGMENT LOCATION IN LAND PLANT DESCRIPTION
- ---------------- ------------ ------------------------------ ------------- ------------------------------

Brooklyn Navy Yard... Americas Brooklyn, New York Leased Natural gas-turbine
cogeneration facility

Doga................. Europe Esenyurt, Turkey Owned Combined cycle generation
technology

EcoElectrica......... Americas Penuelas, Puerto Rico Owned Liquefied natural gas
cogeneration facility

Ferrybridge.......... Europe Knottingley, West Yorkshire, Leased Coal fired generation facility
UK

Fiddler's Ferry...... Europe Warrington, Cheshire, UK Leased Coal fired generation facility

First Hydro.......... Europe Dinorwig, Wales Owned Pumped-storage electric power
facility

First Hydro.......... Europe Ffestiniog, Wales Owned Pumped-storage electric power
facility

Homer City........... Americas Pittsburgh, Pennsylvania Owned Coal fired generation facility

Illinois Plants...... Americas Northeast Illinois Owned/Leased Coal, oil/gas fired generation
facilities

Kern River........... Americas Oildale, California Leased Natural gas-turbine
cogeneration facility

Loy Yang B........... Asia Pacific Victoria, Australia Owned Coal fired generation facility

Midway-Sunset........ Americas Fellows, California Leased Natural gas-turbine
cogeneration facility

Paiton............... Asia Pacific East Java, Indonesia Leased Coal fired generation facility

Roosecote............ Europe Barrow-in-Furness, Cumbria, UK Owned Combined cycle generation
technology

Sycamore............. Americas Oildale, California Leased Natural gas-turbine
cogeneration facility

Watson............... Americas Carson, California Leased Natural gas-turbine
cogeneration facility

ITEM 3. LEGAL PROCEEDINGS

PMNC LITIGATION

In February 1997, a civil action was commenced in the Superior Court of the
State of California, Orange County, entitled THE PARSONS CORPORATION AND PMNC V.
BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P., MISSION ENERGY NEW YORK, INC.
AND B-41 ASSOCIATES, L.P., Case No. 774980, in which the plaintiffs asserted
general monetary claims under the Construction Turnkey Agreement in the amount
of $136.8 million. Brooklyn Navy Yard has also filed an action entitled BROOKLYN
NAVY YARD COGENERATION PARTNERS, L.P. V. PMNC, PARSONS MAIN OF NEW YORK, INC.,
NAB CONSTRUCTION CORPORATION, L.K. COMSTOCK & CO., INC. AND THE PARSONS
CORPORATION, in the Supreme Court of the State of New York, Kings County, Index
No. 5966/97 asserting general monetary claims in excess of $13 million under the
Construction

37

Turnkey Agreement. On March 26, 1998, the Superior Court in the California
action granted PMNC's motion for attachment in the amount of $43 million against
Brooklyn Navy Yard and attached a Brooklyn Navy Yard bank account in the amount
of $0.5 million. Brooklyn Navy Yard is appealing the attachment order. On the
same day, the court stayed all proceedings in the California action pending the
New York action. PMNC's motion to dismiss the New York action was denied by the
New York Supreme Court and further denied on appeal in September 1998. On
March 9, 1999, Brooklyn Navy Yard filed a motion for partial summary judgment in
the New York action. The motion was denied and Brooklyn Navy Yard has appealed.
The appeal and the commencement of discovery were suspended until June 2000 to
allow for voluntary mediation between the parties. The mediation ended
unsuccessfully on March 23, 2000. On November 13, 2000, a New York appellate
court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard,
striking PMNC's cause of action for quantum meruit, and limiting PMNC to its
claims under the construction contract. Discovery is continuing. We agreed to
indemnify Brooklyn Navy Yard and our partner in the venture from all claims and
costs arising from or in connection with this litigation. We believe that the
outcome of this litigation will not have a material adverse effect on our
consolidated financial position or results of operations.

ECOELECTRICA POTENTIAL ENVIRONMENTAL PROCEEDING

We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership
which owns and operates a liquified natural gas import terminal and cogeneration
project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection
Agency issued to EcoElectrica a notice of violation and a compliance order
alleging violations of the federal Clean Air Act primarily related to start-up
activities. Representatives of EcoElectrica have met with the Environmental
Protection Agency to discuss the notice of violations and compliance order. To
date, EcoElectrica has not been informed of the commencement of any formal
enforcement proceedings. It is premature to assess what, if any, action will be
taken by the Environmental Protection Agency. At December 31, 2001, no loss
accrual had been recorded by EcoElectrica. We do not believe the outcome of this
matter will have a material adverse effect on our consolidated financial
position or results of operations.

We experience other routine litigation in the normal course of our business.
None of our pending litigation is expected to have a material adverse effect on
our consolidated financial position or results of operations. See
"Business--Regulatory Matters--Environmental Regulation."

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

Inapplicable.

38

PART II

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

All the outstanding Common Stock of Edison Mission Energy is, as of the date
hereof, owned by The Mission Group, which is a wholly-owned subsidiary of Edison
International. There is no market for the Common Stock. Dividends on the Common
Stock will be paid when declared by our Board of Directors. We made cash
dividend payments to The Mission Group totaling $88 million in 2000. In
February 2001, we made a $32.5 million cash dividend payment to The Mission
Group.

Our articles of incorporation and bylaws contain restrictions on our ability
to declare or pay dividends or distributions. These restrictions require the
unanimous approval of our board of directors, including at least one independent
director, before we can declare or pay dividends or distributions, unless either
of the following are true:

- we then have an investment grade rating and receive rating agency
confirmation that the dividend or distribution will not result in a
downgrade; or

- the dividends do not exceed $32.5 million in any fiscal quarter and we
then meet an interest coverage ratio of not less than 2.2 to 1 for the
immediately preceding four fiscal quarters. We currently meet this
interest coverage ratio.

For more information on these restrictions, see "Management's Discussion and
Analysis of Results of Operations and Financial Condition--Credit Ratings."

COMPANY OBLIGATED MANDATORILY REDEEMABLE SECURITIES OF PARTNERSHIP HOLDING
SOLELY PARENT DEBENTURES. In November 1994, Mission Capital, L.P., a limited
partnership of which Edison Mission Energy is the sole general partner, issued
3.5 million of 9.875% Cumulative Monthly Income Preferred Securities, Series A
at a price of $25 per security. These securities are redeemable at the option of
Mission Capital, in whole or in part, with mandatory redemption in 2024 at a
redemption price of $25 per security, plus accrued and unpaid distributions.
None of these securities have been redeemed as of December 31, 2000. During
August 1995, Mission Capital issued 2.5 million of 8.5% Cumulative Monthly
Income Preferred Securities, Series B at a price of $25 per security. These
securities are redeemable at the option of Mission Capital, in whole or in part,
with mandatory redemption in 2025 at a redemption price of $25 per security,
plus accrued and unpaid distributions. None of these securities were redeemed as
of December 31, 2000. We have guarantees in favor of the holders of the
preferred securities, which guarantee the payments of distributions declared on
the preferred securities, payments upon a liquidation of Mission Capital and
payments on redemption with respect to our preferred securities called for
redemption by Mission Capital. So long as any preferred securities remain
outstanding, we will not be able to declare or pay, directly or indirectly, any
dividend on, or purchase, acquire or make a distribution or liquidation payment
with respect to, any of our common stock if at such time (i) we shall be in
default with respect to our payment obligations under the guarantees,
(ii) there shall have occurred any event of default under the subordinated
indenture, or (iii) we shall have given notice of our selection of an extended
interest payment period as provided in the indenture and such period, or any
extension thereof, shall be continuing.

NOT SUBJECT TO MANDATORY REDEMPTION. In connection with the 40% acquisition
of Contact Energy in May 1999, Edison Mission Energy Global Management, Inc., an
indirect, wholly-owned affiliate of Edison Mission Energy, issued $120 million
of Flexible Money Market Cumulative Preferred Stock. The stock issuance
consisted of (1) 600 Series A shares and (2) 600 Series B shares, both with
liquidation preference of $100,000 per share and a dividend rate of 5.74% until
May 2004.

On December 20, 2000, Edison Mission Energy Global Management, Inc. was
dissolved and its $120 million of Flexible Money Market Cumulative Preferred
Stock was redeemed. The 600 Series A

39

and 600 Series B shares were redeemed at their liquidation preference of
$100,000 per share, together with a liquidation premium of $3,785 per share, and
all accrued and unpaid dividends. The redemption of Edison Mission Energy Global
Management's preferred shares was funded by return of capital from Edison
Mission Energy Taupo Limited. Edison Mission Energy Taupo Limited sold its
entire interest in Contact Energy Limited to EME Pacific Holdings, an indirect,
wholly-owned subsidiary of Edison Mission Energy, to permit Edison Mission
Energy Taupo to make the necessary distribution to Edison Mission Energy Global
Management. In connection with the transfer of ownership of Contact, Edison
Mission Energy entered into a further Deed of Covenant in favor of the
institutional subscriber of 160 million New Zealand dollars of the preferred
stock issued by Edison Mission Energy Taupo in June 1999, discussed below. This
further Deed of Covenant requires Edison Mission Energy to compensate the
institutional preferred stock subscriber in the event that a private binding
ruling issued to it by the New Zealand Inland Revenue Department ceases to apply
as a direct result of the transfer. The amount of any compensation that may
become payable by Edison Mission Energy under the further Deed of Covenant is
limited to that necessary to keep the preferred stock subscriber in the same
position that it would have been had the private binding ruling continued to
apply.

The support agreement between Edison Mission Energy and Edison Mission
Energy Global Management, which required Edison Mission Energy to make capital
contributions to Edison Mission Energy Global Management, was terminated
immediately following the dissolution of Edison Mission Energy Global Management
and the redemption of the preferred shares as described above.

SUBJECT TO MANDATORY REDEMPTION. During June 1999, Edison Mission Energy
Taupo Limited, a New Zealand corporation, an indirect, wholly-owned affiliate of
Edison Mission Energy, issued $84 million of Class A Redeemable Preferred Shares
(16,000 shares at a price of 10,000 New Zealand dollars per share) to an
institutional investor. The dividend rate ranges from 6.19% to 6.86%. The shares
are mandatorily redeemable in June 2003 at 10,000 New Zealand dollars per share,
plus accrued and unpaid dividends. If an event of default occurs at any time,
without prejudice to any other remedies which the redeemable preferred share
subscriber may have, the redeemable preferred share subscriber may, by notice to
the issuer, require redemption of, and the issuer must redeem, the redeemable
preferred shares on the date specified in that notice. Each dividend will rank
for payment in priority to the rights in respect of dividends and the rights, if
any, in respect of interest on arrears thereof of all holders of other classes
of shares of Edison Mission Energy Taupo other than redeemable preferred shares
issued by Edison Mission Energy Taupo. Edison Mission Energy Taupo shall not pay
or make, or allow to be paid or made, any distribution, other than dividends or
the redemption amount or similar amounts payable in respect of the retail
redeemable preferred shares described below, if an event of default or potential
event of default has occurred, which remains unremedied, unless the redeemable
preferred share subscriber has given its prior written consent which may be
given on such conditions as the redeemable preferred share subscriber deems
reasonable.

From July through November 1999, Edison Mission Energy Taupo issued
$125 million of retail redeemable preferred shares (240 million shares at a
price of one New Zealand dollar per share). The dividend rate ranges from 5.00%
to 6.37%. The shares are redeemable at one New Zealand dollar per share in
June 2001 (64 million), June 2002 (43 million), and June 2003 (133 million),
plus accrued and unpaid dividends. Edison Contact Finance is a special purpose
company established to raise funds by the issuance of retail redeemable
preferred shares to assist Edison Mission Energy Taupo to refinance in part the
funding used by it for its acquisition of 40% of the ordinary shares in Contact
Energy. Edison Contact Finance and Edison Mission Energy Taupo are parties to a
subscription and indemnity agreement, which contains the terms of subscription
by Edison Contact Finance for Edison Mission Energy Taupo retail shares. Edison
Contact Finance will subscribe for Edison Mission Energy Taupo retail shares as
and when Edison Contact Finance issues retail shares. The principal terms of
issuance of Edison Mission Energy Taupo retail shares are set out in the
Subscription Agreement and are substantially the same as the terms of issue of
the Class A Redeemable Preferred Shares. If an event of

40

default occurs at any time, under the terms of issue of the retail shares, early
redemption of the shares may be required by the holders of the shares by special
resolution, by 15% of the holders of shares, in instances of non-payment, by
written notice to Edison Contact Finance, or Edison Contact Finance by written
notice to the holders of shares. If only part of the retail shares are redeemed
earlier than their scheduled redemption date, in some cases, a minimum number of
retail shares must be redeemed, and unless the redemption occurs on a dividend
payment date, Edison Mission Energy Taupo must redeem all Edison Mission Energy
Taupo shares in any class, with the same scheduled redemption date and fixed
dividend rate. Edison Contact Finance will redeem the same shares of a class
corresponding to the redeemed Edison Mission Energy Taupo shares. Not all
classes of shares need be affected by a partial redemption of Edison Mission
Energy Taupo retail shares. Redemption of retail shares can be accelerated if
Edison Mission Energy Taupo exercises its option under the terms of the
subscription and indemnity agreement to redeem any of the Edison Mission Energy
Taupo retail shares at its discretion. Edison Contact Finance will pay fully
imputed dividends, in arrears, to the holder of each retail share on the record
date. Edison Contact Finance may change the annual dividend rates, which will
attach to the shares at any time before acceptance by Edison Contact Finance of
an application for those shares.

In connection with the preferred shares issued by Edison Mission Energy
Taupo Limited to partially finance the acquisition of the 40% interest in
Contact Energy, Edison Mission Energy provided a guaranty of Edison Mission
Energy Taupo Limited's obligation to pay a minimum level of non-cumulative
dividends on the preferred shares through June 30, 2002, including
NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending
June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts
required to ensure that Edison Misison Energy Taupo Limited will satisfy two
financial ratio covenants on specified dates. The first financial ratio, called
a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is
based on historical and projected dividends received from Contact Energy and the
dividends payable to preferred shareholders. The second financial ratio, called
a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based
on the fair value of our Contact Energy shares and the outstanding preferred
shares. If, however, Edison Mission Energy's senior unsecured credit rating by
Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be
called to perform on its guaranty of Edison Mission Energy Taupo Limited's
financial covenants before the specified calculation dates. Based on the fair
value of our ownership in Contact Energy at March 20, 2001, had Edison Mission
Energy been required to perform on its guarantee of the debt to valuation ratio
as of that date, Edison Mission Energy's obligation would have been
approximately $19 million.

EDISON MISSION ENERGY TAUPO
PREFERRED STOCK REDEMPTION REQUIREMENTS
(TRANSLATED AT DECEMBER 31, 2000 EXCHANGE RATES)

2001 2002 2003 2004 2005
----------- ----------- ------------ -------- --------

Edison Mission Energy Taupo Limited Class
A Redeemable Preferred Shares........... $ 0 $ 0 $ 70,704,000 $0 $0
Edison Mission Energy Taupo Limited Retail
Redeemable Preference Shares............ 28,339,931 18,813,451 58,902,619 0 0
----------- ----------- ------------ -- --
Total..................................... $28,339,931 $18,813,451 $129,606,619 $0 $0
=========== =========== ============ == ==

41

ITEM 6. SELECTED FINANCIAL DATA

YEARS ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(IN MILLIONS)

INCOME STATEMENT DATA
Operating revenues............................. $3,241.0 $1,635.9 $ 893.8 $ 975.0 $ 843.6
Operating expenses............................. 2,410.2 1,209.5 543.3 581.1 476.5
-------- -------- ------- ------- -------
Operating income............................... 830.8 426.4 350.5 393.9 367.1
Interest expense............................... (721.5) (375.5) (196.1) (223.5) (164.2)
Interest and other income...................... 74.0 55.8 50.9 53.9 40.7
Minority interest.............................. (3.2) (3.0) (2.8) (38.8) (69.5)
-------- -------- ------- ------- -------
Income before income taxes..................... 180.1 103.7 202.5 185.5 174.1
Provision (benefit) for income taxes........... 72.5 (40.4) 70.4 57.4 82.0
-------- -------- ------- ------- -------
Income before accounting change and
extraordinary loss........................... 107.6 144.1 132.1 128.1 92.1
Cumulative effect on prior years of change in
accounting for major maintenance costs, net
of tax....................................... 17.7 -- -- -- --
Cumulative effect on prior years of change in
accounting for start-up costs, net of tax.... -- (13.8) -- -- --
Extraordinary loss on early extinguishment of
debt, net of income tax benefit.............. -- -- -- (13.1) --
-------- -------- ------- ------- -------
Net income..................................... $ 125.3 $ 130.3 $ 132.1 $ 115.0 $ 92.1
======== ======== ======= ======= =======

AS OF DECEMBER 31,
------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- -------- -------- --------
(IN MILLIONS)

BALANCE SHEET DATA
Assets..................................... $15,017.1 $15,534.2 $5,158.1 $4,985.1 $5,152.5
Current liabilities........................ 3,911.0 1,772.8 358.7 339.8 270.9
Long-term obligations...................... 5,334.8 7,439.3 2,396.4 2,532.1 2,419.9
Preferred securities of subsidiaries....... 326.8 476.9 150.0 150.0 150.0
Shareholder's equity....................... 2,948.2 3,068.5 957.6 826.6 1,019.9

YEARS ENDED DECEMBER 31,
-----------------------------------------------------
2000 1999 1998 1997 1996
-------- --------- -------- -------- --------
(IN MILLIONS)

CASH FLOW DATA
Cash provided by operating activities........... $ 665.2 $ 417.2 $ 266.6 $259.5 $ 294.5
Cash provided by (used in) financing
activities.................................... (783.0) 8,363.5 17.9 55.4 184.9
Cash provided by (used in) investing
activities.................................... 718.1 (8,837.8) (408.2) (91.4) (246.3)

42

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

THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS. THESE
STATEMENTS ARE BASED ON OUR CURRENT PLANS AND EXPECTATIONS AND INVOLVE RISKS AND
UNCERTAINTIES WHICH COULD CAUSE ACTUAL FUTURE ACTIVITIES AND RESULTS OF
OPERATIONS TO BE MATERIALLY DIFFERENT FROM THOSE SET FORTH IN THE
FORWARD-LOOKING STATEMENTS. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO
DIFFER INCLUDE RISKS SET FORTH IN "BUSINESS--PROJECT DEVELOPMENT--RISK FACTORS."
UNLESS OTHERWISE INDICATED, THE INFORMATION PRESENTED IN THIS SECTION IS WITH
RESPECT TO EDISON MISSION ENERGY AND OUR CONSOLIDATED SUBSIDIARIES.

GENERAL

We are an independent power producer engaged in the business of developing,
acquiring, owning or leasing and operating electric power generation facilities
worldwide. We also conduct energy trading and price risk management activities
in power markets open to competition. Edison International is our ultimate
parent company. Edison International also owns Southern California Edison
Company, one of the largest electric utilities in the United States. We were
formed in 1986 with two domestic operating projects. As of December 31, 2000, we
owned interests in 33 domestic and 40 international operating power projects
with an aggregate generating capacity of 28,036 MW, of which our share was
22,759 MW. At that date, one domestic and one international project, totaling
603 MW of generating capacity, of which our anticipated share will be
approximately 462 MW, were in construction. At December 31, 2000, we had
consolidated assets of $15.0 billion and total shareholder's equity of
$2.9 billion.

Our operating revenues are derived primarily from electric revenues and
equity in income from power projects. Electric revenues accounted for 91%, 83%
and 74% of our total operating revenues during 2000, 1999 and 1998,
respectively. Our consolidated operating revenues during those years also
include equity in income from oil and gas investments, net losses from energy
trading and price risk management activities and revenues attributable to
operation and maintenance services.

ACQUISITIONS, DISPOSITIONS AND SALE-LEASEBACK TRANSACTIONS

ACQUISITION OF SUNRISE PROJECT

On November 17, 2000, we completed a transaction with Texaco Inc. to
purchase a proposed 560 MW gas fired combined cycle project to be located in
Kern County, California, referred to as the Sunrise Project. The acquisition
included all rights, title and interest held by Texaco in the Sunrise Project,
except that Texaco has an option to repurchase a 50% interest in the project
prior to its commercial operation. As part of this transaction, we also:
(i) acquired from Texaco an option to purchase two gas turbines which we plan to
utilize in the project, (ii) provided Texaco an option to purchase two of the
turbines available to us under the Edison Mission Energy Master Turbine Lease
and (iii) granted Texaco an option to acquire a 50% interest in 1,000 MW of
future power plant projects we designate. For more information on the Edison
Mission Energy Master Turbine Lease, see "--Commitments and
Contingencies--Edison Mission Energy Master Turbine Lease." The Sunrise Project
consists of two phases, with Phase I, construction of a single-cycle gas fired
facility (320 MW), currently scheduled to be completed in August 2001, and Phase
II, conversion to a combined-cycle gas fired facility (560 MW), currently
scheduled to be completed in June 2003. In December 2000, we received the Energy
Commission Certification and a permit to construct the Sunrise plant, which
allowed us to commence construction of Phase I. We are negotiating with the
California Department of Water Resources the detailed terms and conditions of a
long-term cost-based-type rate power purchase agreement. We cannot assure you
that we will be successful in reaching a final agreement.

The total purchase price of the Sunrise Project was $27 million. We funded
the purchase with cash. The total estimated construction cost of this project is
approximately $400 million. As of December 31, 2000, we had spent $17.8 million
on construction costs for the Sunrise Project.

43

ACQUISITION OF TRADING OPERATIONS OF CITIZENS POWER LLC

On September 1, 2000, we completed a transaction with P&L Coal Holdings
Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading
operations of Citizens Power LLC and a minority interest in structured
transaction investments relating to long-term power purchase agreements. The
purchase price of $44.9 million was based on the sum of: (a) fair market value
of the trading portfolio and the structured transaction investments at the date
of the acquisition and (b) $25 million. The acquisition was funded with cash. As
a result of this acquisition, we have expanded our trading operations beyond the
traditional marketing of our electric power. By the end of the third quarter of
2000, the Citizens trading operations were merged into our own marketing
operations under Edison Mission Marketing & Trading, Inc.

ACQUISITION OF INTEREST IN ITALIAN WIND

On March 15, 2000, we completed a transaction with UPC International
Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly
known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50%
interest in a series of power projects that are in operation or under
development in Italy. All the projects use wind to generate electricity from
turbines which is sold under fixed-price, long-term tariffs. Assuming all the
projects under development are completed, currently scheduled for 2002, the
total capacity of these projects will be 283 MW. The total purchase price is
90 billion Italian Lira (approximately $44 million at December 31, 2000), with
equity contribution obligations of up to 33 billion Italian Lira (approximately
$16 million at December 31, 2000), depending on the number of projects that are
ultimately developed. As of December 31, 2000, our payments in respect of these
projects included $27 million toward the purchase price and $13 million in
equity contributions.

ACQUISITION OF ILLINOIS PLANTS

On December 15, 1999, we completed a transaction with Commonwealth Edison, a
subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel
power generating plants located in Illinois, which are collectively referred to
as the Illinois Plants. These plants provide access to Mid-America
Interconnected Network and the East Central Area Reliability Council. In
connection with this transaction, we entered into power purchase agreements with
Commonwealth Edison with terms of up to five years, pursuant to which
Commonwealth Edison purchases capacity and has the right to purchase energy
generated by the plants. Subsequently, Commonwealth Edison assigned its rights
and obligations under these power purchase agreements to Exelon Generation
Company, LLC.

Concurrently with the acquisition of the Illinois Plants, we assigned our
right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating
station located in Illinois, to third party lessors. After this assignment, we
entered into leases of the Collins Station with terms of 33.75 years. The
aggregate megawatts either purchased or leased as a result of these transactions
with Commonwealth Edison and the third party lessors is 9,539 MW.

Consideration for the Illinois Plants, excluding $860 million paid by the
third party lessors to acquire the Collins Station, consisted of a cash payment
of approximately $4.1 billion. The acquisition was funded primarily with a
combination of approximately $1.6 billion of non-recourse debt secured by a
pledge of the stock of specified subsidiaries, $1.3 billion of Edison Mission
Energy's debt and $1.2 billion in equity contributions to us from Edison
International.

ACQUISITION OF FERRYBRIDGE AND FIDDLER'S FERRY PLANTS

On July 19, 1999, we completed a transaction with PowerGen UK plc to acquire
the Ferrybridge and Fiddler's Ferry coal fired electric generating plants
located in the U.K. Ferrybridge, located in West

44

Yorkshire, and Fiddler's Ferry, located in Warrington, each has a generating
capacity of approximately 2,000 MW.

Consideration for the purchase of the Ferrybridge and Fiddler's Ferry plants
by our indirect subsidiary, Edison First Power, consisted of an aggregate of
approximately $2.0 billion (L1.3 billion sterling at the time of the
acquisition) for the two plants. The acquisition was funded primarily with a
combination of net proceeds of L1.15 billion from the Edison First Power Limited
Guaranteed Secured Variable Rate Bonds due 2019, a $500 million equity
contribution to us from Edison International and cash. The Edison First Power
Bonds were issued to a special purpose entity formed by Merrill Lynch
International. Merrill Lynch International sold the variable rate coupons
portion of the bonds to a special purpose entity that borrowed $1.3 billion
(830 million pounds sterling at the time of the acquisition) under a term loan
facility due 2012 to finance the purchase.

ACQUISITION OF INTEREST IN CONTACT ENERGY

On May 14, 1999, we completed a transaction with the New Zealand government
to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in an overseas public offering resulting in
widespread ownership among the citizens of New Zealand and offshore investors.
These shares are publicly traded on stock exchanges in New Zealand and
Australia. During 2000, we increased our share of ownership in Contact Energy to
42%. Contact Energy owns and operates hydroelectric, geothermal and natural gas
fired power generating plants primarily in New Zealand with a total current
generating capacity of 2,449 MW.

Consideration for Contact Energy consisted of a cash payment of
approximately $635 million (1.2 billion New Zealand dollars at the time of the
acquisition), which was financed by $120 million of preferred securities, a
$214 million (400 million New Zealand dollars at the time of the acquisition)
credit facility, a $300 million equity contribution to us from Edison
International and cash. The credit facility was subsequently paid off with
proceeds from the issuance of additional preferred securities.

ACQUISITION OF HOMER CITY PLANT

On March 18, 1999, we completed a transaction with GPU, Inc., New York State
Electric & Gas Corporation and their respective affiliates to acquire the 1,884
MW Homer City Electric Generating Station. This facility is a coal fired plant
in the mid-Atlantic region of the United States and has direct, high voltage
interconnections to both the New York Independent System Operator, which
controls the transmission grid and energy and capacity markets for New York
State and is commonly known as the NYISO, and the Pennsylvania-New
Jersey-Maryland Power Pool, which is commonly known as the PJM.

Consideration for the Homer City plant consisted of a cash payment of
approximately $1.8 billion, which was partially financed by $1.5 billion of new
loans, combined with our revolver borrowings and cash.

ACQUISITION OF INTEREST IN ECOELECTRICA

In December 1998, we acquired 50% of the 540 MW EcoElectrica liquefied
natural gas combined-cycle cogeneration facility under construction in Penuelas,
Puerto Rico for approximately $243 million. The project also includes a
desalination plant and liquefied natural gas storage and vaporization
facilities. Commercial operation commenced in March 2000.

ACCOUNTING TREATMENT OF ACQUISITIONS

Each of the acquisitions described above has been accounted for utilizing
the purchase method. The purchase price was allocated to the assets acquired and
liabilities assumed based on their

45

respective fair market values. Amounts in excess of the fair value of the net
assets acquired have been assigned to goodwill. Our consolidated statement of
income reflects the operations of Citizens beginning September 1, 2000, Italian
Wind beginning April 1, 2000, EcoElectrica beginning March 1, 2000, the Homer
City plant beginning March 18, 1999, Contact Energy beginning May 1, 1999, the
Ferrybridge and Fiddler's Ferry plants beginning July 19, 1999, and the Illinois
Plants beginning December 15, 1999.

DISPOSITIONS

On August 16, 2000, we completed the sale of 30% of our interest in the
Kwinana cogeneration plant to SembCorp Energy. We retain the remaining 70%
ownership interest in the plant. Proceeds from the sale were $12 million. We
recorded a gain on the sale of $8.5 million ($7.7 million after tax).

On June 30, 2000, we completed the sale of our 50% interest in the
Auburndale project to the existing partner. Proceeds from the sale were
$22 million. We recorded a gain on the sale of $17 million ($10.5 million after
tax).

SALE-LEASEBACK TRANSACTIONS

On August 24, 2000, we entered into a sale-leaseback transaction for the
Powerton and Joliet power facilities located in Illinois to third party lessors
for an aggregate purchase price of $1.367 billion. Under the terms of the leases
(33.75 years for Powerton and 30 years for Joliet), our subsidiary makes
semi-annual lease payments on each January 2 and July 2, beginning January 2,
2001. Edison Mission Energy guarantees the subsidiary's payments under the
leases. If a lessor intends to sell its interest in the Powerton or Joliet power
facility, we have a right of first refusal to acquire the interest at fair
market value. Minimum lease payments during the next five years are
$83.3 million for 2001, $97.3 million for 2002, $97.3 million for 2003,
$97.3 million for 2004, and $141.1 million for 2005. At December 31, 2000, the
total remaining minimum lease payments are $2.4 billion. Lease costs of these
power facilities will be levelized over the terms of the respective leases. The
gain recognized on the sale of the power facilities has been deferred and is
being amortized over the term of the leases.

On July 10, 2000, one of our subsidiaries entered into a sale-leaseback of
equipment, primarily Illinois peaker power units, to a third party lessor for
$300 million. Under the terms of the 5-year lease, we have a fixed price
purchase option at the end of the lease term of $300 million. We guarantee the
monthly payments under the lease. In connection with the sale-leaseback, a
subsidiary of ours purchased $255 million of notes issued by the lessor which
accrue interest at LIBOR plus 0.65% to 0.95%, depending on our credit rating.
The notes are due and payable in five years. The gain recognized on the sale of
equipment has been deferred and is being amortized over the term of the lease.

RESULTS OF OPERATIONS

We operate predominantly in one line of business, electric power generation,
with reportable segments organized by geographic region: Americas, Asia Pacific,
and Europe, Central Asia, Middle East and Africa.

Operating revenues are derived from our majority-owned domestic and
international entities. Equity in income from investments relates to energy
projects where our ownership interest is 50% or less in the projects. The equity
method of accounting is generally used to account for the operating results of
entities over which we have a significant influence but in which we do not have
a controlling interest. With respect to entities accounted for under the equity
method, we recognize our proportional share of the income or loss of such
entities.

46

AMERICAS

YEARS ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN MILLIONS)

Operating revenues............................ $1,571.0 $378.6 $ 29.9
Net losses from energy trading and price risk
management.................................. (17.3) (6.4) --
Equity in income from investments............. 257.2 224.8 184.6
-------- ------ ------
Total operating revenues.................... 1,810.9 597.0 214.5
Fuel and plant operations..................... 1,131.6 237.7 22.2
Depreciation and amortization................. 191.2 52.5 9.8
Administrative and general.................... 21.1 -- --
-------- ------ ------
Operating Income.............................. $ 467.0 $306.8 $182.5
======== ====== ======

OPERATING REVENUES

Operating revenues increased $1.2 billion in 2000 compared to 1999, and
increased $348.7 million in 1999 compared to 1998. The 2000 increase resulted
from a full-year of electric revenues from the Illinois Plants acquired in
December 1999 and the Homer City plant acquired in March 1999. The 1999 increase
resulted from electric revenues from the Homer City plant. There were no
comparable electric revenues for the Homer City plant for 1998.

Electric power generated at the Illinois Plants is sold under three
five-year power purchase agreements with Exelon Generation Company, terminating
in December 2004. Exelon Generation is obligated to make capacity payments for
the plants under contract and an energy payment for electricity produced by
these plants. Our revenues under these power purchase agreements were
$1.1 billion for the year ended December 31, 2000. This represented 33% of our
consolidated operating revenues in 2000.

On September 1, 2000, we acquired the trading operations of Citizens Power
LLC. As a result of this acquisition, we have expanded our trading operations
beyond the traditional marketing of our electric power. Our energy trading
activities are accounted for using the fair value method under EITF 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." Net gains from energy trading activities since the date of this
acquisition were $62.2 million. Our price risk management activities included
economic hedge transactions that required mark to market accounting. Total
losses from price risk management activities were $79.5 million and
$6.4 million in 2000 and 1999, respectively. The increase in losses was
primarily due to realized and unrealized losses for a gas swap entered into as
an economic hedge of a portion of our gas price risk related to our share of gas
production in Four Star (an oil and gas company in which we have a minority
interest and which we account for under the equity method). Although we believe
the gas swap hedges our gas price risk, hedge accounting is not permitted for
our investments accounted for on the equity method.

Partially offsetting this loss in 2000 was a gain realized for calendar year
2001 financial options entered into beginning August 2000 as a hedge of our
price risk associated with expected natural gas purchases at the Illinois
Plants. During the fourth quarter, we determined that it was no longer probable
that we would purchase natural gas at the Illinois Plants during 2001. This
decision resulted from sustained gas prices far greater than were contemplated
when we originally projected our 2001 gas needs and the fact that we can use
fuel oil interchangeably with natural gas at some of the Illinois Plants. At the
time we made our revised determination, the fair value of our financial option
was $38 million. This gain is being deferred as required by hedge accounting and
will be recognized upon either purchasing natural gas in 2001 or determining
that it is probable we will not purchase natural gas

47

in 2001. Subsequent to our revised determination, we settled the option for a
$56 million gain. Accordingly, $18 million of gain was recognized in the fourth
quarter. Concurrent with our revised determination of our 2001 natural gas
requirements at the Illinois Plants, we entered into some additional fuel
contracts to offset our financial option and economically hedge the price risk
associated with fuel oil. We recognized a $12 million loss at December 31, 2000
on these additional fuel contracts.

Equity in income from investments rose 14% in 2000 over 1999, and 22% in
1999 over 1998. The 2000 increase was primarily the result of higher revenues
from cogeneration projects due to higher energy pricing and higher revenues from
oil and gas investments due to higher oil and gas prices. The 1999 increase was
primarily the result of higher revenues from several cogeneration projects due
to a final settlement on energy prices tied to short-run avoided cost with the
applicable public utilities and, second, from one cogeneration project as a
result of a gain on termination of a power sales agreement. In addition, the
1999 increase resulted from higher revenues from oil and gas investments
primarily due to higher oil and gas prices.

Many of the domestic energy projects in which our ownership interest is 50%
or less rely on one power sales contract with a single electric utility customer
for the majority, and in some cases all, of their power sales revenues over the
life of the power sales contract. The primary power sales contracts for four of
our operating projects in 2000 and 1999 and five of our operating projects in
1998 are with Southern California Edison. Our share of equity in earnings from
these projects accounted for 5% in 2000, 8% in 1999 and 13% in 1998 of our
consolidated revenues for the respective years. For more information on these
projects and other projects in California, see "--Commitments and
Contingencies--California Power Crisis."

Due to warmer weather during the summer months, electric revenues generated
from the Homer City plant and the Illinois Plants are usually higher during the
third quarter of each year. In addition, our third quarter equity in income from
investments in energy projects is materially higher than other quarters of the
year due to higher summer pricing for our West Coast power investments.

OPERATING EXPENSES

Fuel and plant operations increased $893.9 million in 2000 compared to 1999,
and increased $215.5 million in 1999 compared to 1998. The 2000 increase
resulted from a full year of expenses at the Illinois Plants and the Homer City
plant. The 1999 increase in fuel and plant operations resulted from having no
comparable expenses for the Homer City plant and the Illinois Plants for 1998.

Depreciation and amortization expense increased $138.7 million in 2000
compared to 1999, and increased $42.7 million in 1999 compared to 1998. The 2000
increase was primarily due to a full year of depreciation and amortization
expense related to the Illinois Plants. The 1999 increase in depreciation and
amortization compared to 1998 resulted primarily from the 1999 acquisition of
the Homer City plant.

Administrative and general expenses for 2000 consist of administrative and
general expenses incurred at our trading operations in Boston, Massachusetts
from September 1, 2000, the acquisition date of Citizens Power LLC, through
December 31, 2000. Prior to September 1, 2000, administrative and general
expenses incurred by our own marketing operations were reflected in
Corporate/Other administrative and general expenses.

OPERATING INCOME

Operating income increased $160.2 million in 2000 compared to 1999, and
increased $124.3 million in 1999 compared to 1998. The 2000 increase was
primarily due to operating income from the Illinois Plants, the Homer City plant
and equity in income from investments in oil and gas. The 1999 increase

48

resulted from operating income from the Homer City plant and equity in income
from investments in energy projects.

ASIA PACIFIC

YEARS ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN MILLIONS)

Operating revenues............................. $184.2 $213.6 $205.1
Equity in income from investments.............. 14.6 18.1 1.3
------ ------ ------
Total operating revenues..................... 198.8 231.7 206.4

Fuel and plant operations...................... 61.5 73.8 69.6
Depreciation and amortization.................. 35.0 40.5 31.6
------ ------ ------
Operating Income............................... $102.3 $117.4 $105.2
====== ====== ======

OPERATING REVENUES

Operating revenues decreased $29.4 million in 2000 compared to 1999, and
increased $8.5 million in 1999 compared to 1998. The 2000 decrease was
attributable to lower electric revenues from our Loy Yang B plant. During
May 2000, we experienced a major outage due to damage to the generator at one of
our two 500 MW units at the Loy Yang B power plant complex in Australia. The
unit was restored to operation in September 2000. Under our insurance program,
we are obligated for the property damage insurance deductible of $2 million and
for loss of profits during the first 15 days following the insurable event. The
repair costs in excess of the deductible amount together with the loss of
profits after the first 15 days and until the unit was back in operation were
partially recovered from insurance as of December 31, 2000. The 1999 increase
was primarily due to higher electric revenues from the Loy Yang B plant due to
increased generation in 1999; as compared to 1998, when the plant experienced
longer planned outages.

Equity in income from investments decreased $3.5 million in 2000 compared to
1999, and increased $16.8 million in 1999 compared to 1998. The 2000 decrease is
primarily due to lower profitability of our interest in Contact Energy resulting
from lower electricity prices caused by milder winter weather conditions. The
1999 increase reflects the purchase of our 40% ownership interest in Contact
Energy in May 1999.

OPERATING EXPENSES

Fuel and plant operations decreased $12.3 million in 2000 compared to 1999,
and increased $4.2 million in 1999 compared to 1998. The 2000 decrease resulted
primarily from lower fuel costs at the Loy Yang B plant due to the major outage
at one of its two 500 MW units. The 1999 increase in fuel expense and plant
operations resulted from higher fuel costs from the Loy Yang B plant due to
increased production in 1999; as compared to 1998, when the plant had lower fuel
expenses and longer planned outages.

Depreciation and amortization expense decreased $5.5 million in 2000
compared to 1999, and increased $8.9 million in 1999 compared to 1998. The 2000
decrease was primarily due to favorable changes in foreign exchange rates. The
1999 increase in depreciation and amortization expense related to the
acquisition of our interest in 1999 in the Contact Energy project.

49

OPERATING INCOME

Operating income decreased $15.1 million in 2000 compared to 1999, and
increased $12.2 million in 1999 compared to 1998. The 2000 decrease was due to
lower operating income from the Loy Yang B plant resulting from the major outage
at one of its two 500 MW units and a decrease in the value of the Australian
dollar compared to the U.S. dollar. We recorded pre-tax losses of $8.4 million
in 2000 related to this outage. The 1999 increase resulted from the acquisition
of Contact Energy.

EUROPE, CENTRAL ASIA, MIDDLE EAST AND AFRICA

YEARS ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN MILLIONS)

Operating revenues............................ $1,236.3 $805.8 $469.4
Equity in income (loss) from investments...... (5.0) 1.4 3.5
-------- ------ ------
Total operating revenues.................. 1,231.3 807.2 472.9
Fuel and plant operations..................... 730.1 456.6 241.3
Depreciation and amortization................. 144.8 88.3 40.3
-------- ------ ------
Operating Income.............................. $ 356.4 $262.3 $191.3
======== ====== ======

OPERATING REVENUES

Operating revenues increased $430.5 million in 2000 compared to 1999, and
increased $336.4 million in 1999 compared to 1998. The 2000 increase resulted
from a full year of electric revenues from the Ferrybridge and Fiddler's Ferry
plants acquired in July 1999 and the Doga project, which commenced commercial
operation in May 1999. Despite the overall increase in operating revenues in
2000 which resulted from the inclusion of a full year of operations of these
projects, electric revenues from Ferrybridge and Fiddler's Ferry in 2000 were
adversely affected by lower energy prices during the year, primarily due to
increased competition, warmer-than-average weather and uncertainty surrounding
planned changes in electricity trading arrangements described under "--Market
Risk Exposures--United Kingdom." The time weighted average System Marginal Price
dropped from L22.39/MWh in 1999 to L18.75/MWh in 2000. We have entered into
electricity rate price swaps for the majority of our forecasted generation
through the winter 2000/2001, and accordingly, have mitigated the downside risks
to further decreases in energy prices during this period. Despite improvement in
capacity prices during August, September and early October 2000, and a slight
firming of forward prices, the short-term prices for energy continue to be below
the prices in prior years. As a result of the foregoing, we continue to expect
lower revenues from our Ferrybridge and Fiddler's Ferry plants in 2001. The 1999
increase as compared to 1998 was primarily due to inclusion of electric revenues
from the Ferrybridge and Fiddler's Ferry plants and the Doga project. There were
no comparable electric revenues for the Ferrybridge and Fiddler's Ferry plants
and the Doga project for 1998. The First Hydro plants, Ferrybridge and Fiddler's
Ferry plants and the Iberian Hy-Power plants are expected to provide for higher
electric revenues during the winter months.

Equity in income from investments decreased $6.4 million in 2000 compared to
1999, and decreased $2.1 million in 1999 compared to 1998. The 2000 decrease
reflects losses from initial commercial operation of the ISAB project in
April 2000. We had no comparable results for the ISAB project in 1999.

OPERATING EXPENSES

Fuel and plant operations increased $273.5 million in 2000 compared to 1999,
and increased $215.3 million in 1999 compared to 1998. The 2000 increase
resulted from a full year of expenses at the

50

Ferrybridge and Fiddler's Ferry plants and the Doga project, partially offset by
lower fuel expense at the First Hydro plant. Fuel expense at First Hydro
decreased primarily due to a drop in energy prices throughout the year and lower
pumping costs. The 1999 increase in fuel expense and plant operations resulted
from having no comparable expenses for the Ferrybridge and Fiddler's Ferry
plants and the Doga project for 1998.

Depreciation and amortization expense increased $56.5 million in 2000
compared to 1999, and increased $48 million in 1999 compared to 1998. The 2000
increase was primarily due to a full year of depreciation and amortization
expense associated with the Ferrybridge and Fiddler's Ferry plants. The 1999
increase in depreciation and amortization resulted primarily from the 1999
acquisition of the Ferrybridge and Fiddler's Ferry plants.

OPERATING INCOME

Operating income increased $94.1 million in 2000 compared to 1999, and
increased $71 million in 1999 compared to 1998. The 2000 increase was primarily
due to operating income from the Ferrybridge and Fiddler's Ferry plants, the
Doga project and higher operating income from the First Hydro plant. The 1999
increase resulted from the inclusion of operating income from the Ferrybridge
and Fiddler's Ferry plants and the Doga project.

CORPORATE/OTHER

YEARS ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN MILLIONS)

Depreciation and amortization................. $ 11.1 $ 8.9 $ 5.6
Long-term incentive compensation.............. (56.0) 136.3 39.0
Administrative and general.................... 139.8 114.9 83.9
------ ------- -------
Operating Loss................................ $(94.9) $(260.1) $(128.5)
====== ======= =======

Long-term incentive compensation expense consists of charges related to our
now terminated phantom option plan. Long-term incentive compensation expenses
decreased $192.3 million in 2000 compared to 1999, and increased $97.3 million
in 1999 compared to 1998. The 2000 decrease was due to the absence of new
accruals, as the plan had been terminated, and to a reduction in the liability
for previously accrued incentive compensation by approximately $60 million. This
decrease resulted from the lower valuation implicit in the August 2000 exchange
offer pursuant to which the phantom option plan was terminated compared to the
value previously accrued. The 1999 increase was primarily due to the impact of
the 1999 acquisitions of the Illinois Plants, the Ferrybridge and Fiddler's
Ferry plants, the Homer City plant and a 40% interest in Contact Energy. No
further phantom option plan grants were made in 2000 and, since the plan and all
of the outstanding phantom stock options have been terminated, no further
phantom stock options will be granted or exercised.

Administrative and general expenses increased $24.9 million in 2000 compared
to 1999, and increased $31 million in 1999 compared to 1998. The increases in
both periods were primarily due to additional salaries and facilities costs
incurred to support the 1999 acquisitions. We recorded a pretax charge of
approximately $9 million against earnings for severance and other related costs,
which contributed to the 2000 increase. The charge resulted from a series of
actions undertaken by us designed to reduce administrative and general operating
costs, including reductions in management and administrative personnel.

51

OTHER INCOME (EXPENSE)

On August 16, 2000, we completed the sale of 30% of our interest in the
Kwinana cogeneration plant to SembCorp Energy. We retain the other 70% ownership
interest in the plant. Proceeds from the sale were $12 million. We recorded a
gain on the sale of $8.5 million ($7.7 million after tax).

On June 30, 2000, we completed the sale of our 50% interest in the
Auburndale project to the existing partner. Proceeds from the sale were
$22 million. We recorded a gain on the sale of $17 million ($10.5 million after
tax).

During the fourth quarter of 1999, we completed the sale of 31.5% of our
50.1% interest in Four Star Oil & Gas for $34.2 million in cash and a 50%
interest in the acquirer, Four Star Holdings. Four Star Holdings financed the
purchase of the interest in Four Star Oil & Gas from $27.5 million in loans from
affiliates, including $13.7 million from us, and $13.7 million from cash. Upon
completion of the sale, we continue to own an 18.6% direct interest in Four Star
Oil & Gas and an indirect interest of 15.75% which is held through Four Star
Holdings. As a result of this transaction, our total interest in Four Star
Oil & Gas has decreased from 50.1% to 34.35%. Cash proceeds from the sale were
$34.2 million ($20.5 million net of the loan to Four Star Holdings). The gain on
the sale of the 31.5% interest in Four Star Oil & Gas was $11.5 million of which
we deferred 50%, or $5.6 million, due to our equity interest in Four Star
Holdings. The after-tax gain on the sale was approximately $30 million.

Interest expense increased $336.2 million in 2000 compared to 1999, and
increased $170.3 million in 1999 compared to 1998. The 2000 increase was
primarily the result of additional debt financing associated with the
acquisitions of the Illinois Plants, Ferrybridge and Fiddler's Ferry plants and
the Homer City plant. The 1999 increase was also the result of debt financing of
the Homer City plant, Ferrybridge and Fiddler's Ferry plants and the Illinois
Plants acquisition.

Dividends on mandatorily redeemable preferred securities increased
$9.7 million in 2000 compared to 1999 and increased $9.2 million in 1999
compared to 1998. The 2000 and 1999 increases reflect the issuance of preferred
securities in connection with the Contact Energy acquisition.

PROVISION (BENEFIT) FOR INCOME TAXES

We had effective tax provision (benefit) rates of 40.3%, (39.0)% and 34.8%
in 2000, 1999 and 1998, respectively. Income taxes increased in 2000 principally
due to a higher foreign income tax expense compared to 1999, nonrecurring 1999
tax benefits discussed below and higher state income taxes due to the Homer City
plant and Illinois Plants. Income taxes decreased in 1999, principally due to
lower pre-tax income and income tax benefits. In 1999, we recorded tax benefits
associated with a capital loss attributable to the sale of a portion of our
interest in Four Star Oil & Gas Company, refunds of advanced corporation tax
payments from the United Kingdom and a reduction in deferred taxes in Australia
as a result of a decrease in statutory rates. In addition, our effective tax
rate has decreased as a result of lower foreign income taxes that result from
the permanent reinvestment of earnings from foreign affiliates located in
different foreign tax jurisdictions. The Australian corporate tax rate decreased
from 36% to 34% effective in July 2000, and is scheduled to decrease from 34% to
30% effective in July 2001. The 1998 tax provision reflects a benefit from
reductions in the U.K corporate tax rate from 33% to 31% effective in
April 1997, and from 31% to 30% effective in April 1999. In accordance with
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes," the reductions in the Australia and U.K. income tax rates resulted in
reductions in income tax expense of approximately $5.9 million and $11 million
in 1999 and 1998, respectively.

We are, and may in the future be, under examination by tax authorities in
varying tax jurisdictions with respect to positions we take in connection with
the filing of our tax returns. Matters raised upon audit may involve substantial
amounts, which, if resolved unfavorably, an event not currently

52

anticipated, could possibly be material. However, in our opinion, it is unlikely
that the resolution of any such matters will have material adverse effect upon
our financial condition or results of operations.

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE

Through December 31, 1999, we accrued for major maintenance costs incurred
during the period between turnarounds (referred to as the "accrue in advance"
accounting method). The accounting policy has been widely used by independent
power producers as well as several other industries. In March 2000, the
Securities and Exchange Commission issued a letter to the Accounting Standards
Executive Committee, stating its position that the Securities and Exchange
Commission staff does not believe it is appropriate to use an "accrue in
advance" method for major maintenance costs. The Accounting Standards Executive
Committee agreed to add accounting for major maintenance costs as part of an
existing project and to issue authoritative guidance by August 2001. Due to the
position taken by the Securities and Exchange Commission staff, we voluntarily
decided to change our accounting policy to record major maintenance costs as an
expense as incurred. Such change in accounting policy is considered preferable
based on the recent guidance provided by the Securities and Exchange Commission.
In accordance with Accounting Principles Board Opinion No. 20, "Accounting
Changes," we have recorded a $17.7 million, after tax, increase to net income,
as a cumulative change in the accounting for major maintenance costs during the
quarter ended March 31, 2000.

In April 1998, the American Institute of Certified Public Accountants issued
Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities,"
which became effective in January 1999. The Statement requires that specified
costs related to start-up activities be expensed as incurred and that specified
previously capitalized costs be expensed and reported as a cumulative change in
accounting principle. The reduction to our net income that resulted from
adopting SOP 98-5 was $13.8 million, after tax.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2000, we had cash and cash equivalents of $962.9 million and
had available a total of $41 million of borrowing capacity under a $500 million
revolving credit facility that expires on October 11, 2001 and a $300 million
senior credit facility that expires on May 29, 2001. We also had available
$127.3 million of borrowing capacity under a $700 million senior credit facility
that is now scheduled to expire on May 29, 2001. The revolving credit facility
provides credit available in the form of cash advances or letters of credit, and
bears interest on advances under the London Interbank Offered Rate, LIBOR, which
was 6.66% at December 31, 2000, plus the applicable margin as determined by our
long-term credit ratings (0.175% margin at December 31, 2000). In addition to
the interest component described above, we pay a facility fee as determined by
our long-term credit ratings (0.09% at December 31, 2000) on the entire credit
facility independent of the level of borrowings.

Net working capital at December 31, 2000 was ($1,703.9) million compared to
($815.5) million at December 31, 1999. The decrease reflects the
reclassification to current maturities of long-term obligations from long-term
obligations at December 31, 2000 of indebtedness under the financing documents
entered into to finance the acquisition of the Ferrybridge and Fiddler's Ferry
plants in 1999. See "--Financing Plans" for further discussion.

Cash provided by operating activities is derived primarily from operations
of the Illinois Plants and the Homer City plant, distributions from energy
projects and dividends from investments in oil and gas. Net cash provided by
operating activities increased $248.1 million in 2000 compared to 1999 and
$150.6 million in 1999 compared to 1998. The 2000 increase primarily reflects
higher pre-tax earnings from projects acquired in 1999 and higher dividends from
oil and gas investments. The 1999 increase was primarily due to higher
distributions from energy projects and higher dividends from oil and gas
investments.

53

Net cash used in financing activities totaled $783 million in 2000, compared
to net cash provided by financing activities of $8,363.5 million and
$17.9 million in 1999 and 1998, respectively. Payments made on our credit
facilities totaling $1.4 billion, a $500 million payment on our floating rate
notes and the redemption of the Flexible Money Market Cumulative Preferred Stock
for $124.7 million were the primary contributors of the net cash used in
financing activities during 2000. Edison Mission Energy used the proceeds from
the August 2000 Powerton and Joliet sale-leaseback transaction for a significant
portion of those payments on the credit facilities, commercial paper facilities
and the floating rate notes. We also paid dividends of $88 million to Edison
International. In 2000, we also had borrowings of $1.2 billion under our credit
facilities and commercial paper facilities. In February 2000, Edison Mission
Midwest Holdings Co. issued $1.7 billion of commercial paper under its credit
facility and repaid a similar amount of its outstanding bank borrowings for the
Illinois Plants. Subsequently, Edison Mission Midwest Holdings Co. repaid
$769.3 million of commercial paper under its credit facility and issued a
similar amount of its bank borrowings for the Illinois Plants in December 2000.
In January 2000, one of our foreign subsidiaries borrowed $242.7 million from
Edison Capital, an indirect affiliate. In 1999, financings related to the
acquisition of four new projects in 1999 contributed to net cash provided by
financing activities. A term loan facility of $1.3 billion related to the
Ferrybridge and Fiddler's Ferry plants, senior secured bonds totaling
$830 million related to the Homer City plant, $120 million Flexible Money Market
Cumulative Preferred Stock and $125 million Retail Redeemable Preference Shares
and $84 million Class A Redeemable Preferred Shares related to Contact Energy
and credit facilities totaling $1.7 billion related to the Illinois Plants. In
addition, our financings in connection with the aforementioned acquisitions
consisted of floating rate notes of $500 million, borrowings of $215 million
under our revolving credit facility and commercial paper facilities totaling
$1.2 billion. In addition, we also received $2 billion in equity contributions
from Edison International, which amount was 100% financed in the capital
markets, to finance our 1999 acquisitions. In June 1999, we issued $600 million
of 7.73% Senior Notes due 2009. As of December 31, 2000, we had recourse debt of
$2.1 billion, with an additional $5.9 billion of non-recourse debt (debt which
is recourse to specific assets or subsidiaries, but not to Edison Mission
Energy) on our consolidated balance sheet.

Net cash provided by investing activities totaled $718.1 million in 2000,
compared to net cash used in investing activities of $8,837.8 million and
$408.2 million in 1999 and 1998, respectively. In 2000, net cash provided by
investing activities was primarily due to proceeds of $1.367 billion and
$300 million received from the sale leaseback transactions with respect to the
Powerton and Joliet power facilities in August 2000 and the Illinois peaker
power units in July 2000, respectively. In connection with the Illinois peaker
power units transaction, we purchased $255 million of notes issued by the
lessor. In 2000, $27 million was paid toward the purchase price and $13 million
in equity contributions for the Italian Wind projects, $44.9 million for the
Citizens trading operations and structured transaction investments, and
$27 million for the acquisition of the Sunrise project. In addition,
$33.5 million, $21.2 million and $20 million was made in equity contributions
for the EcoElectrica project (June 2000), the Tri Energy project (July 2000) and
the ISAB project (September 2000), respectively. In 1999, cash used in investing
activities was primarily due to the purchase of the Homer City plant,
Ferrybridge and Fiddler's Ferry generating facilities, the Illinois Plants and
the 40% interest in Contact Energy. We invested $352.3 million, $216.4 million
and $73.4 million in 2000, 1999 and 1998, respectively, in new plant and
equipment principally related to the Homer City plant and Illinois Plants in
2000, the Homer City plant and Ferrybridge and Fiddler's Ferry plants in 1999,
and the Doga project in 1998.

CREDIT RATINGS

On January 17, 2001, we amended our articles of incorporation and our bylaws
to include so-called "ring-fencing" provisions to isolate ourselves from the
credit downgrades and potential bankruptcies of Edison International and
Southern California Edison and to facilitate our ability and the ability of our

54

subsidiaries to maintain their respective investment grade ratings. These
ring-fencing provisions are intended to preserve us as a stand-alone investment
grade rated entity despite the current credit difficulties of Edison
International and Southern California Edison. These provisions require the
unanimous approval of our board of directors, including at least one independent
director, before we can do any of the following:

- declare or pay dividends or distributions unless:

- we then have an investment grade rating and receive rating agency
confirmation that the dividend or distribution will not result in a
downgrade; or

- the dividends do not exceed $32.5 million in any fiscal quarter and we
meet an interest coverage ratio of not less than 2.2 to 1 for the
immediately preceding four fiscal quarters. We currently meet this
interest coverage ratio;

- institute or consent to bankruptcy, insolvency or similar proceedings or
actions; or

- consolidate or merge with any entity or transfer substantially all our
assets to any entity, except to an entity that is subject to similar
restrictions.

We cannot assure you that these measures will effectively isolate us from
the credit downgrades or the potential bankruptcies of Edison International and
Southern California Edison. In January 2001, Standard & Poor's and Moody's
lowered our credit ratings. Our senior unsecured credit ratings were downgraded
to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's.
Our credit ratings remain investment grade. Both Standard & Poor's and Moody's
have indicated that the credit ratings outlook for us is stable.

We cannot assure you that Standard & Poor's and Moody's will not downgrade
us below investment grade, whether as a result of the California power crisis or
otherwise. If we are downgraded, we could be required to, among other things:

- provide additional guarantees, collateral, letters of credit or cash for
the benefit of counterparties in our trading activities,

- post a letter of credit or cash collateral to support our $58.5 million
equity contribution obligation in connection with our acquisition in
February 2001 of a 50% interest in the CBK project in the Philippines, and

- repay a portion of the preferred shares issued by our subsidiary in
connection with our 1999 acquisition of a 40% interest in Contact Energy
Limited, a New Zealand power company, which, based on their value at
March 20, 2001, would require a payment of approximately $19 million.

Our downgrade could result in a downgrade of Edison Mission Midwest Holdings
Co., our indirect subsidiary. In the event of a downgrade of Edison Mission
Midwest Holdings below its current credit rating, provisions in the agreements
binding on its subsidiary, Midwest Generation, LLC, limit the ability of Midwest
Generation to use excess cash flow to make distributions.

On March 15, 2001, the California Public Utilities Commission released a
draft of a proposed order instituting an investigation into whether California's
investor-owned utilities, including Southern California Edison, have complied
with past Commission decisions authorizing the formation of their holding
companies and governing affiliate transactions, as well as applicable statutes.
Action on this agenda item repeatedly has been deferred, including at the
Commission meeting on March 27, 2001, and the item has continued to appear on
the agendas for subsequent Commission meetings. The proposed order would reopen
the past holding company decisions and initiate an investigation into the
following matters:

- whether the holding companies, including Edison International, violated
requirements to give priority to the capital needs of their respective
utility subsidiaries;

55

- whether the ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the
requirements to give priority to the capital needs of their utility
subsidiaries;

- whether the payment of dividends by the utilities violated requirements
that the utilities maintain dividend policies as though they were
comparable stand-alone utility companies;

- any additional suspected violations of laws or Commission rules and
decisions; and

- whether additional rules, conditions, or other changes to the holding
company decisions are necessary.

We cannot predict whether the Commission will institute this investigation or
what effects any investigation or subsequent actions by the Commission may have
on Edison International or indirectly on us.

A downgrade in our credit rating below investment grade could increase our
cost of capital, increase our credit support obligations, make efforts to raise
capital more difficult and could have an adverse impact on us and our
subsidiaries.

RESTRICTED ASSETS OF SUBSIDIARIES

Each of our direct or indirect subsidiaries is organized as a legal entity
separate and apart from us and our other subsidiaries. Assets of our
subsidiaries may not be available to satisfy our obligations or the obligations
of any of our other subsidiaries. However, unrestricted cash or other assets
which are available for distribution may, subject to applicable law and the
terms of financing arrangements of the parties, be advanced, loaned, paid as
dividends or otherwise distributed or contributed to us or to an affiliate of
ours.

FINANCING PLANS

CORPORATE FINANCING PLANS

We have three corporate credit facilities that are scheduled to expire in
May 2001 (in a total amount of $1 billion) and October 2001 (in an amount of
$500 million). As of March 16, 2001, we have borrowed or issued letters of
credit aggregating $1.49 billion under these credit facilities and have an
unused capacity of approximately $10 million. We plan to refinance these credit
facilities through modifications to our existing credit facilities or by
entering into new short-term facilities prior to their expiration. Our corporate
cash requirements in 2001 are expected to exceed cash distributions from our
subsidiaries. Our corporate cash requirements in 2001 include:

- debt service under our senior notes and intercompany notes resulting from
sale-leaseback transactions which aggregate $149 million;

- capital requirements for projects in development and under construction of
$251 million; and

- development costs, general and administrative expenses.

We plan to finance these activities through new short-term facilities and
through the use of project or subsidiary financings or capital markets debt,
depending on market conditions. However, while we cannot assure you that we will
be able to enter into modifications to our existing credit facilities or obtain
additional debt to finance our needs or that the credit facilities can be
modified or obtained under similar terms and rates as our agreements, we believe
our corporate financing plans will be successful in meeting our cash
requirements in 2001. In addition, to reduce debt and to provide additional
liquidity, we may sell our interest in individual projects in our project
portfolio. Under one of our credit facilities, we are required to use 50% of the
net proceeds from the sale of assets and 75% of the net proceeds from the
issuance of capital markets debt to repay senior bank indebtedness, in

56

each case in excess of $300 million in the aggregate. There is no assurance that
we will be able to sell assets on favorable terms or that the sale of individual
assets will not result in a loss.

SUBSIDIARY FINANCING PLANS

During 2001, the estimated capital expenditures of our subsidiaries is
$262 million, including environmental expenditures disclosed under
"--Environmental Matters and Regulations." These capital expenditures are
planned to be financed by existing subsidiary credit agreements and cash
generated from their operations. Other than as described under "--Commitments
and Contingencies," we do not plan to make additional capital contributions to
our subsidiaries.

One of our subsidiaries, Edison First Power, has defaulted on its financing
documents related to the acquisition of the Fiddler's Ferry and Ferrybridge
power plants. The financial performance of the Fiddler's Ferry and Ferrybridge
power plants has not matched our expectations, largely due to lower energy power
prices resulting primarily from increased competition, warmer-than-average
weather and uncertainty surrounding the new electricity trading arrangements.
See "--Market Risk Exposures--United Kingdom." As a result, Edison First Power
has decided to defer some environmental capital expenditures originally planned
to increase plant utilization and therefore is currently in breach of milestone
requirements for the implementation of the capital expenditures program set
forth in the financing documents relating to the acquisition of these plants. In
addition, due to this reduced financial performance, Edison First Power's debt
service coverage ratio during 2000 declined below the threshold set forth in the
financing documents.

Edison First Power is currently in discussions with the relevant financing
parties to revise the required capital expenditure program, to waive (i) the
breach of the financial ratio covenant for 2000, (ii) a technical breach of
requirements for the provision of information that was delayed due to
uncertainty regarding capital expenditures, and (iii) other related technical
defaults. Edison First Power is in the process of requesting the necessary
waivers and consents to amendments from the financing parties. We cannot assure
you that waivers and consents to amendments will be forthcoming. The financing
documents stipulate that a breach of the financial ratio covenant constitutes an
immediate event of default and, if the event of default is not waived, the
financing parties are entitled to enforce their security over Edison First
Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite
the breaches under the financing documents, Edison First Power's debt service
coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and
debt service payments, Edison First Power utilized L37 million from its debt
service reserve to meet its debt service requirements in 2000.

Another of our subsidiaries, EME Finance UK Limited, is the borrower under
the facility made available for the purposes of funding coal and capital
expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At
December 31, 2000, L58 million was outstanding for coal purchases and zero was
outstanding to fund capital expenditures under this facility. EME Finance UK
Limited on-lends any drawings under this facility to Edison First Power. The
financing parties of this facility have also issued letters of credit directly
to Edison First Power to support their obligations to lend to EME Finance UK
Limited. EME Finance UK Limited's obligations under this facility are separate
and apart from the obligations of Edison First Power under the financing
documents related to the acquisition of these plants. We have guaranteed the
obligations of EME Finance UK Limited under this facility, including any letters
of credit issued to Edison First Power under the facility, for the amount of
L359 million, and our guarantee remains in force notwithstanding any breaches
under Edison First Power's acquisition financing documents.

In addition, Edison Mission Energy may provide guarantees in support of
bilateral contracts entered into by Edison First Power under the new electricity
trading arrangements. Edison Mission Energy has provided guarantees totalling
L19 million relating to these contracts at March 20, 2001.

In accordance with SFAS No. 121, "ACCOUNTING FOR THE IMPAIRMENT OF
LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED", we have evaluated
impairment of the Ferrybridge and Fiddler's Ferry

57

power plants. The undiscounted projected cash flow from these power plants
exceeds the net book value at December 31, 2000, and, accordingly, no impairment
of these power plants is permitted under SFAS No. 121. As a result of the change
in the prices of power in the U.K., we are considering the sale of Ferrybridge
and Fiddler's Ferry power plants. Management has not made a decision whether or
not the sale of these power plants will ultimately occur and, accordingly, these
assets are not classified as held for sale. However, if a decision to sell the
Ferrybridge and Fiddler's Ferry power plants were made, it is likely that the
fair value of the assets would be substantially below their book value at
December 31, 2000. Our net investment in our subsidiary that holds the
Ferrybridge and Fiddler's Ferry power plants and related debt was $918 million
at December 31, 2000.

COMMITMENTS AND CONTINGENCIES

CAPITAL COMMITMENTS

The following table summarizes our consolidated capital commitments as of
December 31, 2000. Details regarding these capital commitments are discussed in
the sections referenced.

U.S.
TYPE OF COMMITMENT ESTIMATED TIME PERIOD DISCUSSED UNDER
- ------------------ ------------- ----------- ----------------------------------
(IN MILLIONS)

New Gas-Fired Generation.......... $250 by 2003 Illinois Plants--Power Purchase
Agreements

New Gas-Fired Generation.......... 346 2001-2003 Acquisition of Sunrise Project

New Gas-Fired Generation.......... 986* 2001-2004 Edison Mission Energy Master
Turbine Lease

Environmental Improvements at our
Project Subsidiaries............ 557 2001-2005 Environmental Matters and
Regulations

Project Acquisition for the
Italian Wind.................... 17 2001-2002 Firm Commitment for Asset Purchase

Equity Contribution for the
Italian Wind.................... 3 2001-2002 Firm Commitments to Contribute
Project Equity

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

* Represents the total estimated costs related to four projects using the
Siemens Westinghouse turbines procured under the Edison Mission Energy
Master Turbine Lease. One of these projects may be used to meet the new gas
fired generation commitments resulting from the acquisition of the Illinois
Plants. See "--Illinois Plants--Power Purchase Agreements."

In addition, in February 2001, we purchased a 50% interest in the CBK
project for $20 million. Financing for this $460 million project will require
equity contributions of $117 million, of which our share is $58.5 million. See
"--Recent Developments."

CALIFORNIA POWER CRISIS

We have partnership interests in eight partnerships which own power plants
in California which have power purchase contracts with Pacific Gas and Electric
and/or Southern California Edison. Three of these partnerships have a contract
with Southern California Edison, four of them have a contract with Pacific Gas
and Electric, and one of them has contracts with both. In 2000, our share of
earnings before taxes from these partnerships was $168 million, which
represented 20% of our operating income. Our investment in these partnerships at
December 31, 2000 was $345 million.

58

As a result of Southern California Edison's and Pacific Gas and Electric's
current liquidity crisis, each of these utilities has failed to make payments to
qualifying facilities supplying them power. These qualifying facilities include
the eight power plants which are owned by partnerships in which we have a
partnership interest. Southern California Edison did not pay any of the amounts
due to the partnerships in January, February and March of 2001 and may continue
to miss future payments. Pacific Gas and Electric made its January payment in
full but thus far has paid only a small portion of the amounts due to the
partnerships in February and March and may not pay all or a portion of its
future payments.

On March 27, 2001, the California Public Utilities Commission issued a
decision that ordered the three California investor owned utilities, including
Southern California Edison and Pacific Gas and Electric, to commence payment for
power generated from qualifying facilities beginning in April 2001. In addition,
the decision modified the pricing formula for determining short run avoided
costs for qualifying facilities subject to these provisions. Depending on how
the utilities react to this order, the immediate impact of this decision may be
to commence payment in April 2001 at significantly reduced prices for power to
qualifying facilities subject to this pricing adjustment. Furthermore, this
decision called for further study of the pricing formula tied to short run
avoided costs and, accordingly, may be subject to more changes in the future.
Finally, this decision is subject to challenge before the Commission, the
Federal Energy Regulatory Commission and, potentially, state or federal courts.
Although it is premature to assess the full effect of this recent decision, it
could have a material adverse effect on our investment in the California
partnerships, depending on how it is implemented and future changes in the
relationship between the pricing formula and the actual cost of natural gas
procured by our California partnerships. This decision did not address payment
to the qualifying facilities for amounts due prior to April 2001.

The California utilities' failure to pay has adversely affected the
operations of our eight California qualifying facilities. Continuing failures to
pay similarly could have an adverse impact on the operations of our California
qualifying facilities. Provisions in the partnership agreements stipulate that
partnership actions concerning contracts with affiliates are to be taken through
the non-affiliated partner in the partnership. Therefore, partnership actions
concerning the enforcement of rights under each qualifying facility's power
purchase agreement with Southern California Edison in response to Southern
California Edison's suspension of payments under that power purchase agreement
are to be taken through the non-Edison Mission Energy affiliated partner in the
partnership. Some of the partnerships have sought to minimize their exposure to
Southern California Edison by reducing deliveries under their power purchase
agreements. It is unclear at this time what additional actions, if any, the
partnerships will take in regard to the utilities' suspension of payments due to
the qualifying facilities. As a result of the utilities' failure to make
payments due under these power purchase agreements, the partnerships have called
on the partners to provide additional capital to fund operating costs of the
power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours
have made equity contributions totaling approximately $103 million to meet
capital calls by the partnerships. Our subsidiaries and the other partners may
be required to make additional capital contributions to the partnerships.

Southern California Edison has stated that it is attempting to avoid
bankruptcy and, subject to the outcome of regulatory and legal proceedings and
negotiations regarding purchased power costs, it intends to pay all its
obligations once a permanent solution to the current energy and liquidity crisis
has been reached. Pacific Gas and Electric has taken a different approach and is
seeking to invoke force majeure provisions under its power purchase agreements
to excuse its failure to pay. In either case, it is possible that the utilities
will not pay all their obligations in full. In addition, it is possible that
Southern California Edison and/or Pacific Gas and Electric could be forced into
bankruptcy proceedings. If this were to occur, payments to the qualifying
facilities, including those owned by partnerships in which we have a partnership
interest, could be subject to significant delays associated with the lengthy
bankruptcy court process and may not be paid in full. At February 28, 2001,
accounts receivable due to these partnerships from Southern California Edison
and Pacific Gas & Electric were

59

$437 million; our share of these receivables was $217 million. Furthermore,
Southern California Edison's and Pacific Gas and Electric's power purchase
agreements with the qualifying facilities could be subject to review by a
bankruptcy court. While we believe that the generation of electricity by the
qualifying facilities, including those owned by partnerships in which we have a
partnership interest, is needed to meet California's power needs, we cannot
assure you either that these partnerships will continue to generate electricity
without payment by the purchasing utility, or that the power purchase agreements
will not be adversely affected by a bankruptcy or contract renegotiation as a
result of the current power crisis.

A number of federal and state, legislative and regulatory initiatives
addressing the issues of the California electric power industry have been
proposed, including wholesale rate caps, retail rate increases, acceleration of
power plant permitting and state entry into the power market. Many of these
activities are ongoing. These activities may result in a restructuring of the
California power market. At this time, these activities are in their preliminary
stages, and it is not possible to estimate their likely ultimate outcome. The
situation in California changes on an almost daily basis. You should monitor
developments in California for the most up to date information. For more
information on the current regulatory situation in California, see
"Business--Regulatory Matters--California Deregulation."

CREDIT SUPPORT FOR TRADING AND PRICE RISK MANAGEMENT ACTIVITIES

Our trading and price risk management activities are conducted through our
subsidiary, Edison Mission Marketing & Trading, Inc., which is currently rated
investment grade ("BBB-" by Standard and Poor's). As part of obtaining an
investment grade rating for this subsidiary, we have entered into a support
agreement, which commits us to contribute up to $300 million in equity to Edison
Mission Marketing & Trading, if needed to meet cash requirements. An investment
grade rating is an important benchmark used by third parties when deciding
whether or not to enter into master contracts and trades with us. The majority
of Edison Mission Marketing & Trading's contracts have various standards of
creditworthiness, including the maintenance of specified credit ratings. If
Edison Mission Marketing & Trading does not maintain its investment grade rating
or if other events adversely affect its financial position, a third party could
request Edison Mission Marketing & Trading to provide adequate assurance.
Adequate assurance could take the form of supplying additional financial
information, additional guarantees, collateral, letters of credit or cash.
Failure to provide adequate assurance could result in a counterparty liquidating
an open position and filing a claim against Edison Mission Marketing & Trading
for any losses.

The California power crisis has adversely affected the liquidity of West
Coast trading markets, and to a lesser extent, other regions in the United
States. Our trading and price risk management activity has been reduced as a
result of these market conditions and uncertainty regarding the effect of the
power crisis on our affiliate, Southern California Edison. It is not certain
that resolution of the California power crisis will occur in 2001 or that, if
resolved, we will be able to conduct trading and price risk management
activities in a manner that will be favorable to us.

PAITON

The Paiton project is a 1,230 MW coal fired power plant in operation in East
Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a
$490 million investment in the project at December 31, 2000. The project's
tariff under the power purchase agreement with PT PLN is higher in the early
years and steps down over time. The tariff for the Paiton project includes costs
relating to infrastructure to be used in common by other units at the Paiton
complex. The plant's output is fully contracted with the state-owned electricity
company, PT PLN. Payments are in Indonesian Rupiah, with the portion of the
payments intended to cover non-Rupiah project costs, including returns to
investors, adjusted to account for exchange rate fluctuations between the
Indonesian Rupiah and the U.S. dollar. The project received substantial finance
and insurance support from the Export-Import Bank of the United States, the
Japan Bank for International Cooperation (formerly known as The Export-Import
Bank of Japan), the U.S. Overseas Private Investment Corporation and the
Ministry of Economy, Trade and Industry of Japan (formerly known as the Ministry
of International Trade and Industry). PT PLN's payment obligations are supported
by the Government of Indonesia.

60

The projected rate of growth of the Indonesian economy and the exchange rate
of Indonesian Rupiah into U.S. dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The Paiton project's
senior debt ratings have been reduced from investment grade to speculative grade
based on the rating agencies' determination that there is increased risk that PT
PLN might not be able to honor the power purchase agreement with P.T. Paiton
Energy, the project company. The Government of Indonesia has arranged to
reschedule sovereign debt owed to foreign governments and has entered into
discussions about rescheduling sovereign debt owed to private lenders.

In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the
Paiton project had achieved commercial operation under the terms of the power
purchase agreement and, in July 1999, that the second 615 MW unit of the plant
had similarly achieved commercial operation. Because of the economic downturn,
PT PLN was then experiencing low electricity demand and PT PLN, through
February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a
lawsuit contesting the validity of its agreement to purchase electricity from
the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in
connection with this withdrawal, the parties entered into an interim agreement
for the period through December 31, 2000, under which dispatch levels and fixed
and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made
all fixed payments due under the interim agreement totaling $115 million and all
payments due for energy delivered by the plant to PT PLN. As part of the
continuing negotiations on a long-term restructuring of the tariff, Paiton
Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period
from January 1, 2001 through June 30, 2001. This agreement provides for fixed
monthly payments aggregating $108 million over its six month duration and for
the payment for energy delivered to PT PLN from the plant during this period.
Paiton Energy and PT PLN intend to complete the negotiations of the future
phases of a new long-term tariff during the six month duration of the Phase I
Agreement. To date, PT PLN has made all fixed and energy payments due under the
Phase I Agreement.

Events, including those discussed above, have occurred which may mature into
defaults of the project's debt agreements following the passage of time, notice
or lapse of waivers granted by the project's lenders. On October 15, 1999, the
project entered into an interim agreement with its lenders pursuant to which the
lenders waived defaults during the term of the agreement and effectively agreed
to defer payments of principal until July 31, 2000. In July, the lenders agreed
to extend the term of the lender interim agreement through December 31, 2000. In
December 2000, the lenders agreed to an additional extension of the lender
interim agreement through December 31, 2001. Paiton Energy has received lender
approval of the Phase I Agreement.

Under the terms of the power purchase agreement, PT PLN has been required to
pay for capacity and fixed operating costs once each unit and the plant achieved
commercial operation. As of December 31, 2000, PT PLN had not paid invoices
amounting to $814 million for capacity charges and fixed operating costs under
the power purchase agreement. All arrears under the power purchase agreement
continue to accrue, minus the fixed monthly payments actually made under the
year 2000 interim agreement and under the recently agreed Phase I Agreement,
with the payment of these arrears to be dealt with in connection with the
overall long-term restructuring of the tariff. In this regard, under the Phase I
Agreement, Paiton Energy has agreed that, so long as the Phase I Agreement is
complied with, it will seek to recoup no more than $590 million of the above
arrears, the payment of which is to be dealt with in connection with the overall
tariff restructuring.

Any material modifications of the power purchase agreement resulting from
the continuing negotiation of a new long-term tariff could require a
renegotiation of the Paiton project's debt agreements. The impact of any such
renegotiations with PT PLN, the Government of Indonesia or the project's
creditors on our expected return on our investment in Paiton Energy is uncertain
at this time; however, we believe that we will ultimately recover our investment
in the project.

61

BROOKLYN NAVY YARD

Brooklyn Navy Yard is a 286 MW gas fired cogeneration power plant in
Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims
under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners,
L.P. for damages in the amount of $136.8 million. Brooklyn Navy Yard
Cogeneration Partners has asserted general monetary claims against the
contractor. In connection with a $407 million non-recourse project refinancing
in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its
partner from all claims and costs arising from or in connection with the
contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard
Cogeneration Partners' lenders. At this time, we cannot reasonably estimate the
amount that would be due, if any, related to this litigation. Additional
amounts, if any, which would be due to the contractor with respect to completion
of construction of the power plant would be accounted for as an additional part
of its power plant investment. Furthermore, our partner has executed a
reimbursement agreement with us that provides recovery of up to $10 million over
an initial amount, including legal fees, payable from its management and royalty
fees. At December 31, 2000, no accrual had been recorded in connection with this
litigation. We believe that the outcome of this litigation will not have a
material adverse effect on our consolidated financial position or results of
operations.

HOMER CITY

Edison Mission Energy has guaranteed to the bondholders, banks and other
secured parties which financed the acquisition of the Homer City plant the
performance and payment when due by Edison Mission Holdings Co. of its
obligations in respect of specified senior debt, up to $42 million. This
guarantee will be available until December 31, 2001, after which time Edison
Mission Energy will have no further obligations under this guarantee.

To satisfy the requirements under the Edison Mission Holdings Co. bond
financing to have a debt service reserve account balance in an amount equal to
six months' debt service projected to be due following the payment of a
distribution, Edison Mission Energy agreed to guarantee the payment and
performance of the obligations of Edison Mission Holdings, in the amount of
approximately $35 million, pursuant to a debt service reserve guarantee. In
addition, Edison Mission Energy provides a guarantee of Edison Mission Holdings'
obligations in the amount of $3 million to the lenders involved in the bank
financing. As a result of Edison Mission Energy's downgrade in January 2001,
Edison Mission Holdings is in the process of finalizing the arrangement of a
letter of credit of approximately $35 million to replace the bond debt service
reserve guarantee.

PREFERRED SHARES OF EDISON MISSION ENERGY TAUPO LIMITED

In connection with the preferred shares issued by Edison Mission Energy
Taupo Limited to partially finance the acquisition of the 40% interest in
Contact Energy, Edison Mission Energy provided a guaranty of Edison Mission
Energy Taupo Limited's obligation to pay a minimum level of non-cumulative
dividends on the preferred shares through June 30, 2002, including
NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending
June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts
required to ensure that Edison Misison Energy Taupo Limited will satisfy two
financial ratio covenants on specified dates. The first financial ratio, called
a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is
based on historical and projected dividends received from Contact Energy and the
dividends payable to preferred shareholders. The second financial ratio, called
a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based
on the fair value of our Contact Energy shares and the outstanding preferred
shares. If, however, Edison Mission Energy's senior unsecured credit rating by
Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be
called to perform on its guaranty of Edison Mission Energy Taupo Limited's
financial covenants before the specified calculation dates. Based on

62

the fair value of our ownership in Contact Energy at March 20, 2001, had Edison
Mission Energy been required to perform on its guarantee of the debt to
valuation ratio as of that date, Edison Mission Energy's obligation would have
been approximately $19 million.

EDISON MISSION ENERGY MASTER TURBINE LEASE

In December 2000, we entered into a master lease and other agreements for
the construction of new projects using nine turbines that are being procured
from Siemens Westinghouse. The aggregate total construction cost of these
projects is estimated to be approximately $986 million. Under the terms of the
master lease, the lessor, as owner of the projects, is responsible for the
development and construction costs of the new projects using these turbines. We
have agreed to supervise the development and construction of the projects as the
agent of the lessor. Upon completion of construction of each project, we have
agreed to lease the projects from the lessor. In connection with the lease, we
have provided a residual value guarantee to the lessor at the end of the lease
term. We are required to deposit treasury notes equal to 103% of the
construction costs as collateral for the lessor which can only be used under
circumstances involving our default of the obligations we have agreed to perform
during the construction of each project. Lease payments are scheduled to begin
in November 2003. Minimum lease payments under this agreement are $3.1 million
in 2003, $27.7 million in 2004, and $50.2 million in 2005. The term of the
master lease ends in 2010. The master lease grants us, as lessee, a purchase
option based on the lease balance which can be exercised at any time during the
term.

SALE-LEASEBACK COMMITMENTS

At December 31, 2000, we had minimum lease payments related to purchased
power generation assets from Commonwealth Edison that were leased back to us in
three separate transactions. In connection with the 1999 acquisition of the
Illinois Plants, we assigned the right to purchase the Collins gas and oil-fired
power plant to third party lessors. The third party lessors purchased the
Collins Station for $860 million and leased the plant to us. During 2000, we
entered into sale-leaseback transactions for equipment, primarily the Illinois
peaker power units, and for two power facilities, the Powerton and Joliet coal
fired stations located in Illinois, to third party lessors. Total minimum lease
payments during the next five years are $146.6 million in 2001, $168.6 million
in 2002, $168.6 million in 2003, $168.8 million in 2004, and $191.4 million in
2005. At December 31, 2000, the total remaining minimum lease payments were
$3.9 billion.

ILLINOIS PLANTS-POWER PURCHASE AGREEMENTS

During 2000, 33% of our electric revenues were derived under power purchase
agreements with Exelon Generation Company, a subsidiary of Exelon Corporation,
entered into in connection with our December 1999 acquisition of the Illinois
Plants. Exelon Corporation is the holding company of Commonwealth Edison and
PECO Energy Company, major utilities located in Illinois and Pennsylvania.
Electric revenues attributable to sales to Exelon Generating Company are earned
from capacity and energy provided by the Illinois Plants under three five-year
power purchase agreements. If Exelon Generation were to fail to or became unable
to fulfill its obligations under these power purchase agreements, we may not be
able to find another customer on similar terms for the output of our power
generating assets. Any material failure by Exelon Generation to make payments
under these power purchase agreements could adversely affect our results of
operations and liquidity.

Pursuant to the acquisition documents for the purchase of generating assets
from Commonwealth Edison, our subsidiary committed to install one or more
gas-fired power plants having an additional gross dependable capacity of 500 MWs
at existing or adjacent power plant site in Chicago. The acquisition documents
require that commercial operations of this project be completed by

63

December 15, 2003. The estimated cost to complete the construction of this 500
MW gas-fired power plant is approximately $250 million.

FUEL SUPPLY CONTRACTS

At December 31, 2000, we had contractual commitments to purchase and/or
transport coal and fuel oil. Based on the contract provisions, which consist of
fixed prices, subject to adjustment clauses in some cases, these minimum
commitments are currently estimated to aggregate $2.4 billion in the next five
years summarized as follows: 2001--$838 million; 2002--$653 million;
2003--$386 million; 2004--$308 million; 2005--$241 million.

FIRM COMMITMENT FOR ASSET PURCHASE

PROJECTS LOCAL CURRENCY U.S. ($ IN MILLIONS)
- -------- ----------------------- --------------------

Italian Wind Projects(1)............... 36 billion Italian Lira $17

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

(1) The Italian Wind Projects are a series of power projects that are in
operation or under development in Italy. A wholly-owned subsidiary of Edison
Mission Energy owns a 50% interest. Purchase payments will continue through
2002, depending on the number of projects that are ultimately developed.

FIRM COMMITMENTS TO CONTRIBUTE PROJECT EQUITY

PROJECTS LOCAL CURRENCY U.S. ($ IN MILLIONS)
- -------- ---------------------- --------------------

Italian Wind Projects(1)................ 6 billion Italian Lira $3

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

(1) The Italian Wind Projects are a series of power projects that are in
operation or under development in Italy. A wholly-owned subsidiary of Edison
Mission Energy owns a 50% interest. Equity will be contributed depending on
the number of projects that are ultimately developed.

Firm commitments to contribute project equity could be accelerated due to
certain events of default as defined in the non-recourse project financing
facilities. Management does not believe that these events of default will occur
to require acceleration of the firm commitments.

CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY

PROJECTS LOCAL CURRENCY U.S. ($ IN MILLIONS)
- -------- ----------------------- --------------------

Paiton(1).............................. -- $39
ISAB(2)................................ 90 billion Italian Lira 44

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

(1) Contingent obligations to contribute additional project equity will be based
on events principally related to insufficient cash flow to cover interest on
project debt and operating expenses, project cost overruns during plant
construction, specified partner obligations or events of default. Our
obligation to contribute contingent equity will not exceed $141 million, of
which $102 million has been contributed as of December 31, 2000. As of
March 16, 2001, $5 million of this amount remains to be funded.

For more information on the Paiton project, see "--Paiton" above.

(2) ISAB is a 512 MW integrated gasification combined cycle power plant near
Siracusa in Sicily, Italy. A wholly-owned subsidiary of Edison Mission
Energy owns a 49% interest. Commercial operations

64

commenced in April 2000. Contingent obligations to contribute additional
equity to the project relate specifically to an agreement to provide equity
assurances to the project's lenders depending on the outcome of the
contractor claim arbitration.

We are not aware of any other significant contingent obligations or
obligations to contribute project equity other than as noted above and equity
contributions to be made by us to meet capital calls by partnerships who own
qualifying facilities that have power purchase agreements with Southern
California Edison and Pacific Gas and Electric. See "--California Power Crisis"
for further discussion.

SUBSIDIARY INDEMNIFICATION AGREEMENTS

Some of our subsidiaries have entered into indemnification agreements, under
which the subsidiaries agreed to repay capacity payments to the projects' power
purchasers in the event the projects unilaterally terminate their performance or
reduce their electric power producing capability during the term of the power
contracts. Obligations under these indemnification agreements as of
December 31, 2000, if payment were required, would be $256 million. We have no
reason to believe that the projects will either terminate their performance or
reduce their electric power producing capability during the term of the power
contracts.

OTHER

In support of the businesses of our subsidiaries, we have made, from time to
time, guarantees, and have entered into indemnity agreements with respect to our
subsidiaries' obligations like those for debt service, fuel supply or the
delivery of power, and have entered into reimbursement agreements with respect
to letters of credit issued to third parties to support our subsidiaries'
obligations. We may incur additional guaranty, indemnification, and
reimbursement obligations, as well as obligations to make equity and other
contributions to projects in the future.

MARKET RISK EXPOSURES

Our primary market risk exposures arise from changes in interest rates,
changes in oil and gas prices and electricity pool pricing and fluctuations in
foreign currency exchange rates. We manage these risks in part by using
derivative financial instruments in accordance with established policies and
procedures.

INTEREST RATE RISK

Interest rate changes affect the cost of capital needed to finance the
construction and operation of our projects. We have mitigated the risk of
interest rate fluctuations by arranging for fixed rate financing or variable
rate financing with interest rate swaps or other hedging mechanisms for a number
of our project financings. Interest expense included $16.1 million,
$25.2 million and $22.8 million for the years 2000, 1999 and 1998, respectively,
as a result of interest rate hedging mechanisms. We have entered into several
interest rate swap agreements under which the maturity date of the swaps occurs
prior to the final maturity of the underlying debt. A 10% increase in market
interest rates at December 31, 2000 would result in a $17.2 million increase in
the fair value of our interest rate hedge agreements. A 10% decrease in market
interest rates at December 31, 2000 would result in a $17.1 million decline in
the fair value of our interest rate hedge agreements.

We had short-term obligations of $883.4 million consisting of commercial
paper and bank borrowings at December 31, 2000. The fair values of these
obligations approximated their carrying values at December 31, 2000, and would
not have been materially affected by changes in market interest rates. The fair
market value of long-term fixed interest rate obligations are subject to
interest rate risk. The fair market value of our total long-term obligations
(including current portion) was $6,999.8 million at December 31, 2000. A 10%
increase in market interest rates at December 31, 2000

65

would result in a decrease in the fair value of total long-term obligations by
approximately $96 million. A 10% decrease in market interest rates at
December 31, 2000 would result in an increase in the fair value of total
long-term obligations by approximately $104 million.

COMMODITY PRICE RISK

Electric power generated at our uncontracted plants is generally sold under
bilateral arrangements with utilities and power marketers under short-term
contracts with terms of two years or less, or, in the case of the Homer City
plant, to the PJM or the NYISO. We have developed risk management policies and
procedures which, among other things, address credit risk. When making sales
under negotiated bilateral contracts, it is our policy to deal with investment
grade counterparties or counterparties that provide equivalent credit support.
Exceptions to the policy are granted only after thorough review and scrutiny by
Edison Mission Energy's Risk Management Committee. Most entities that have
received exceptions are organized power pools and quasi-governmental agencies.
We hedge a portion of the electric output of our merchant plants, whose output
is not committed to be sold under long-term contracts, in order to lock in
desirable outcomes. When appropriate, we manage the spread between electric
prices and fuel prices, and use forward contracts, swaps, futures, or options
contracts to achieve those objectives.

Our electric revenues were increased by $47.5 million, $60.9 million and
$108.4 million in 2000, 1999 and 1998, respectively, as a result of electricity
rate swap agreements and other hedging mechanisms. A 10% increase in pool prices
would result in a $130.8 million decrease in the fair market value of
electricity rate swap agreements. A 10% decrease in pool prices would result in
a $130.5 million increase in the fair market value of electricity rate swap
agreements. An electricity rate swap agreement is an exchange of a fixed price
of electricity for a floating price. As a seller of power, we receive the fixed
price in exchange for a floating price, like the index price associated with
electricity pools. A 10% increase in electricity prices at December 31, 2000
would result in a $1.8 million decrease in the fair market value of forward
contracts entered into by the Loy Yang B plant. A 10% decrease in electricity
prices at December 31, 2000 would result in a $1.8 million increase in the fair
market value of forward contracts entered into by Loy Yang B plant.

A 10% increase in fuel oil, natural gas and electricity forward prices at
December 31, 2000 would result in a $15.7 million decrease in the fair market
value of energy contracts utilized by our domestic trading operations in energy
trading and price risk management activities. A 10% decrease in fuel oil,
natural gas and electricity forward prices at December 31, 2000 would result in
a $15.7 million increase in the fair market value of energy contracts utilized
by our domestic trading operations in energy trading and price risk management
activities.

AMERICAS

On September 1, 2000, we acquired the trading operations of Citizens Power
LLC. As a result of this acquisition, we have expanded our trading operations
beyond the traditional marketing of our electric power. Our energy trading and
price risk management activities give rise to market risk, which represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Market risks are actively monitored to ensure compliance
with the risk management policies of Edison Mission Energy. Policies are in
place which limit the amount of total net exposure we may enter into at any
point in time. Procedures exist which allow for monitoring of all commitments
and positions with daily reporting to senior management. We perform a "value at
risk" analysis in our daily business to measure, monitor and control our overall
market risk exposure. The use of value at risk allows management to aggregate
overall risk, compare risk on a consistent basis and identify the reasons for
the risk. Value at risk measures the worst expected loss over a given time
interval, under normal market conditions, at a given confidence level. Given the
inherent limitations of value at risk and relying on a single risk measurement
tool, we supplement this approach with industry "best

66

practice" techniques including the use of stress testing and worst-case scenario
analysis, as well as stop limits and counterparty credit exposure limits.

Electric power generated at the Homer City plant is sold under bilateral
arrangements with domestic utilities and power marketers under short-term
contracts with terms of two years or less, or to the PJM or the NYISO. These
pools have short-term markets, which establish an hourly clearing price. The
Homer City plant is situated in the PJM control area and is physically connected
to high-voltage transmission lines serving both the PJM and NYISO markets. The
Homer City plant can also transmit power to the midwestern United States.

Electric power generated at the Illinois Plants is sold under power purchase
agreements with Exelon Generation Company, in which Exelon Generation Company
purchases capacity and has the right to purchase energy generated by the
Illinois Plants. The agreements, which began on December 15, 1999 and have a
term of up to five years, provide for Exelon Generation Company to make capacity
payments for the plants under contract and energy payments for the electricity
produced by these plants and taken by Exelon Generation Company. The capacity
payments provide the Illinois Plants revenue for fixed charges, and the energy
payments compensate the Illinois Plants for variable costs of production. If
Exelon Generation Company does not fully dispatch the plants under contract, the
Illinois Plants may sell, subject to specified conditions, the excess energy at
market prices to neighboring utilities, municipalities, third party electric
retailers, large consumers and power marketers on a spot basis. A bilateral
trading infrastructure already exists with access to the Mid-America
Interconnected Network and the East Central Area Reliability Council.

UNITED KINGDOM

Our plants in the U.K. currently sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly clearing
price, also referred to as the pool price, for electrical energy. This system
has been in place since 1989 but is due to be replaced on March 27, 2001 with a
bilateral physical trading system referred to as the new electricity trading
arrangements.

The new electricity trading arrangements are the direct result of an
October 1997 request by the Minister for Science, Energy and Industry who asked
the U.K. Director General of Electricity Supply to review the operation of the
pool pricing system. In July 1998 the Director General proposed that the current
structure of contracts for differences and compulsory trading via the pool at
half-hourly clearing prices bid a day ahead be abolished. The U.K. Government
accepted the proposals in October 1998 subject to reservations. Following this,
further proposals were published by the Government and the Director General in
July and October 1999. The proposals include, among other things, the
establishment of a spot market or voluntary short-term power exchanges operating
from 24 to 3 1/2-hours before a trading period; a balancing mechanism to enable
the system operator to balance generation and demand and resolve any
transmission constraints; a mandatory settlement process for recovering
imbalances between contracted and metered volumes with strong incentives for
being in balance; and a Balancing and Settlement Code Panel to oversee
governance of the balancing mechanism. Contracting over time periods longer than
the day-ahead market are not directly affected by the proposals. Physical
bilateral contracts will replace the current contracts for differences, but will
function in a similar manner. However, it remains difficult to evaluate the
future impact of the proposals. A key feature of the new electricity trading
arrangements is to require firm physical delivery, which means that a generator
must deliver, and a consumer must take delivery, against their contracted
positions or face assessment of energy imbalance penalty charges by the system
operator. A consequence of this should be to increase greatly the motivation of
parties to contract in advance and develop forwards and futures markets of
greater liquidity than at present. Recent experience has been that the new
electricity trading arrangements have placed a significant downward pressure on
forward contract prices. Furthermore, another consequence may be that
counterparties may require additional credit support, including parent company
guarantees or letters of credit. Legislation in the form of the Utilities Act,
which was

67

approved July 28, 2000, allows for the implementation of new electricity trading
arrangements and the necessary amendments to generators' licenses. Various key
documents were designated by the Secretary of State and signed by participants
on August 14, 2000 (the Go-Active Date); however, due to difficulties
encountered during testing, implementation of the new electricity trading
arrangements has been delayed from November 21, 2000 until March 27, 2001.

The Utilities Act sets a principal objective for the Government and the
Director General to "protect the interests of consumers.... where appropriate by
promoting competition....". This represents a shift in emphasis toward the
consumer interest. But this is qualified by a recognition that license holders
should be able to finance their activities. The Act also contains new powers for
the Government to issue guidance to the Director General on social and
environmental matters, changes to the procedures for modifying licenses and a
new power for the Director General to impose financial penalties on companies
for breach of license conditions. We will be monitoring the operation of these
new provisions. See "--Financing Plans."

ASIA PACIFIC

AUSTRALIA. The Loy Yang B plant sells its electrical energy through a
centralized electricity pool, which provides for a system of generator bidding,
central dispatch and a settlements system based on a clearing market for each
half-hour of every day. The National Electricity Market Management Company,
operator and administrator of the pool, determines a system marginal price each
half-hour. To mitigate exposure to price volatility of the electricity traded
into the pool, the Loy Yang B plant has entered into a number of financial
hedges. From May 8, 1997 to December 31, 2000, approximately 53% to 64% of the
plant output sold was hedged under vesting contracts, with the remainder of the
plant capacity hedged under the State Hedge described below. Vesting contracts
were put into place by the State Government of Victoria, Australia, between each
generator and each distributor, prior to the privatization of electric power
distributors in order to provide more predictable pricing for those electricity
customers that were unable to choose their electricity retailer. Vesting
contracts set base strike prices at which the electricity will be traded. The
parties to the vesting contracts make payments, which are calculated based on
the difference between the price in the contract and the half-hourly pool
clearing price for the element of power under contract. Vesting contracts were
sold in various structures and accounted for as electricity rate swap
agreements. The State Hedge agreement with the State Electricity Commission of
Victoria is a long-term contractual arrangement based upon a fixed price
commencing May 8, 1997 and terminating October 31, 2016. The State Government of
Victoria, Australia guarantees the State Electricity Commission of Victoria's
obligations under the State Hedge. From January 2001 to July 2014, approximately
77% of the plant output sold is hedged under the State Hedge. From August 2014
to October 2016, approximately 56% of the plant output sold is hedged under the
State Hedge. Additionally, the Loy Yang B plant entered into a number of fixed
forward electricity contracts commencing January 1, 2001, which expire either on
January 1, 2002 or January 1, 2003, and which will further mitigate against the
price volatility of the electricity pool.

NEW ZEALAND. The New Zealand Government has been undergoing a steady process
of electric industry deregulation since 1987. Reform in the distribution and
retail supply sector began in 1992 with legislation that deregulated electricity
distribution and provided for competition in the retail electric supply
function. The New Zealand Energy Market, established in 1996, is a voluntary
competitive wholesale market which allows for the trading of physical
electricity on a half-hourly basis. The Electricity Industry Reform Act, which
was passed in July 1998, was designed to increase competition at the wholesale
generation level by splitting up Electricity Company of New Zealand Limited, the
large state-owned generator, into three separate generation companies. The
Electricity Industry Reform Act also prohibits the ownership of both generation
and distribution assets by the same entity.

The New Zealand Government commissioned an inquiry into the electricity
industry in February 2000. This Inquiry Board's report was presented to the
government in mid 2000. The main

68

focus of the report was on the monopoly segments of the industry, transmission
and distribution, with substantial limitations being recommended in the way in
which these segments price their services in order to limit their monopoly
power. Recommendations were also made with respect to the retail customer in
order to reduce barriers to customers switching. In addition, the Board made
recommendations in relation to the wholesale market's governance arrangements
with the purpose of streamlining them. The recommended changes are now being
progressively implemented.

FOREIGN EXCHANGE RATE RISK

Fluctuations in foreign currency exchange rates can affect, on a United
States dollar equivalent basis, the amount of our equity contributions to, and
distributions from, our international projects. As we continue to expand into
foreign markets, fluctuations in foreign currency exchange rates can be expected
to have a greater impact on our results of operations in the future. At times,
we have hedged a portion of our current exposure to fluctuations in foreign
exchange rates through financial derivatives, offsetting obligations denominated
in foreign currencies, and indexing underlying project agreements to United
States dollars or other indices reasonably expected to correlate with foreign
exchange movements. In addition, we have used statistical forecasting techniques
to help assess foreign exchange risk and the probabilities of various outcomes.
We cannot assure you, however, that fluctuations in exchange rates will be fully
offset by hedges or that currency movements and the relationship between certain
macro economic variables will behave in a manner that is consistent with
historical or forecasted relationships. Foreign exchange considerations for
three major international projects, other than Paiton which was discussed
earlier, are discussed below.

The First Hydro, Ferrybridge and Fiddler's Ferry plants in the U.K. and the
Loy Yang B plant in Australia have been financed in their local currency, pounds
sterling and Australian dollars, respectively, thus hedging the majority of
their acquisition costs against foreign exchange fluctuations. Furthermore, we
have evaluated the return on the remaining equity portion of these investments
with regard to the likelihood of various foreign exchange scenarios. These
analyses use market derived volatilities, statistical correlations between
specified variables, and long-term forecasts to predict ranges of expected
returns.

Foreign currencies in the U.K., Australia and New Zealand decreased in value
compared to the U.S. dollar by 7%, 15% and 15%, respectively (determined by the
change in the exchange rates from December 31, 1999 to December 31, 2000). The
decrease in value of these currencies was the primary reason for the foreign
currency translation loss of $157.3 million during 2000. A 10% increase or
decrease in the exchange rate at December 31, 2000 would result in foreign
currency translation gains or losses of $196.7 million.

In December 2000, we entered into foreign currency forward exchange
contracts in the ordinary course of business to protect ourselves from adverse
currency rate fluctuations on anticipated foreign currency commitments with
varying maturities ranging from January 2001 to July 2002. The periods of the
forward exchange contracts correspond to the periods of the hedged transactions.
At December 31, 2000, the outstanding notional amount of the contracts totaled
$91 million, consisting of contracts to exchange U.S. dollars to pound sterling.
A 10% fluctuation in exchange rates would change the fair value of the contracts
at December 31, 2000 by approximately $6 million.

We will continue to monitor our foreign exchange exposure and analyze the
effectiveness and efficiency of hedging strategies in the future.

OTHER

The electric power generated by some of our investments in domestic
operating projects, excluding the Homer City plant and the Illinois Plants, is
sold to electric utilities under long-term contracts, typically with terms of 15
to 30-years. We structure our long-term contracts so that fluctuations in fuel

69

costs will produce similar fluctuations in electric and/or steam revenues and
enter into long-term fuel supply and transportation agreements. The degree of
linkage between these revenues and expenses varies from project to project, but
generally permits the projects to operate profitably under a wide array of
potential price fluctuation scenarios.

ENVIRONMENTAL MATTERS AND REGULATIONS

We are subject to environmental regulation by federal, state and local
authorities in the United States and foreign regulatory authorities with
jurisdiction over projects located outside the United States. We believe that we
are in substantial compliance with environmental regulatory requirements and
that maintaining compliance with current requirements will not materially affect
our financial position or results of operation. However, possible future
developments, such as the promulgation of more stringent environmental laws and
regulations, and future proceedings which may be taken by environmental
authorities, could affect the costs and the manner in which we conduct our
business and could cause us to make substantial additional capital expenditures.
We cannot assure you that we would be able to recover these increased costs from
our customers or that our financial position and results of operations would not
be materially adversely affected.

Typically, environmental laws require a lengthy and complex process for
obtaining licenses, permits and approvals prior to construction and operation of
a project. Meeting all the necessary requirements can delay or sometimes prevent
the completion of a proposed project as well as require extensive modifications
to existing projects, which may involve significant capital expenditures.

We expect that compliance with the Clean Air Act and the regulations and
revised State Implementation Plans developed as a consequence of the Act will
result in increased capital expenditures and operating expenses. For example, we
expect to spend approximately $67 million in 2001 to install upgrades to the
environmental controls at the Homer City plant to control sulfur dioxide and
nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental
controls at the Illinois Plants to control nitrogen oxide emissions to result in
expenditures of approximately $61 million, $67 million, $130 million,
$123 million and $57 million for 2001, 2002, 2003, 2004 and 2005, respectively.
Provisions related to nonattainment, air toxins, permitting of new and existing
units, enforcement and acid rain may affect our domestic plants; however, final
details of all these programs have not been issued by the United States
Environmental Protection Agency and state agencies. In addition, at the
Ferrybridge and Fiddler's Ferry plants we anticipate environmental costs arising
from plant modification of approximately $52 million for the 2001-2005 period.

We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership
which owns and operates a liquified natural gas import terminal and cogeneration
project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection
Agency issued to EcoElectrica a notice of violation and a compliance order
alleging violations of the federal Clean Air Act primarily related to start-up
activities. Representatives of EcoElectrica have met with the Environmental
Protection Agency to discuss the notice of violations and compliance order. To
date, EcoElectrica has not been informed of the commencement of any formal
enforcement proceedings. It is premature to assess what, if any, action will be
taken by the Environmental Protection Agency.

On November 3, 1999, the United States Department of Justice filed suit
against a number of electric utilities for alleged violations of the Clean Air
Act's "new source review" requirements related to modifications of air emissions
sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In
addition, the United States Environmental Protection Agency has also issued
administrative notices of violation alleging similar violations at additional
power plants owned by some of the same utilities named as defendants in the
Department of Justice lawsuit, as well as other utilities, and also issued an
administrative order to the Tennessee Valley Authority for similar violations at
certain of its power plants. The Environmental Protection Agency has also issued
requests for information pursuant to the

70

Clean Air Act to numerous other electric utilities seeking to determine whether
these utilities also engaged in activities that may have been in violation of
the Clean Air Act's new source review requirements.

To date, one utility, the Tampa Electric Company, has reached a formal
agreement with the United States to resolve alleged new source review
violations. Two other utilities, the Virginia Electric & Power Company and
Cinergy Corp., have reached agreements in principle with the Environmental
Protection Agency. In each case, the settling party has agreed to incur over
$1 billion in expenditures over several years for the installation of additional
pollution control, the retirement or repowering of coal fired generating units,
supplemental environmental projects and civil penalties. These agreements
provide for a phased approach to achieving required emission reductions over the
next 10-15 years. The settling utilities have also agreed to pay civil penalties
ranging from $3.5 million to $8.5 million.

Prior to our purchase of the Homer City plant, the Environmental Protection
Agency requested information from the prior owners of the plant concerning
physical changes at the plant. Other than with respect to the Homer City plant,
no proceedings have been initiated or requests for information issued with
respect to any of our United States facilities. However, we have been in
informal voluntary discussions with the Environmental Protection Agency relating
to these facilities, which may result in the payment of civil fines. We cannot
assure you that we will reach a satisfactory agreement or that these facilities
will not be subject to proceedings in the future. Depending on the outcome of
the proceedings, we could be required to invest in additional pollution control
requirements, over and above the upgrades we are planning to install, and could
be subject to fines and penalties.

A new ambient air quality standard was adopted by the Environmental
Protection Agency in July 1997 to address emissions of fine particulate matter.
It is widely understood that attainment of the fine particulate matter standard
may require reductions in nitrogen oxides and sulfur dioxides, although under
the time schedule announced by the Environmental Protection Agency when the new
standard was adopted, non-attainment areas were not to have been designated
until 2002 and control measures to meet the standard were not to have been
identified until 2005. In May 1999, the United States Court of Appeals for the
District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act,
the section of the Clean Air Act requiring the promulgation of national ambient
air quality standards, as interpreted by the Environmental Protection Agency,
was an unconstitutional delegation of legislative power. The Court of Appeals
remanded both the fine particulate matter standard and the revised ozone
standard to allow the EPA to determine whether it could articulate a
constitutional application of Section 109(b)(1). On February 27, 2001, the
Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the
Circuit Court's judgment on this issue and remanded the case back to the Court
of Appeals to dispose of any other preserved challenges to the particulate
matter and ozone standards. Accordingly, as the final application of the revised
particulate matter ambient air quality standard is potentially subject to
further judicial proceedings, the impact of this standard on our facilities is
uncertain at this time.

On December 20, 2000, the Environmental Protection Agency issued a
regulatory finding that it is "necessary and appropriate" to regulate emissions
of mercury and other hazardous air pollutants from coal-fired power plants. The
agency has added coal-fired power plants to the list of source categories under
Section 112(c) of the Clean Air Act for which "maximum available control
technology" standards will be developed. Eventually, unless overturned or
reconsidered, the Environmental Protection Agency will issue technology-based
standards that will apply to every coal-fired unit owned by us or our affiliates
in the United States. This section of the Clean Air Act provides only for
technology-based standards, and does not permit market trading options. Until
the standards are actually promulgated, the potential cost of these control
technologies cannot be estimated, and we cannot evaluate the potential impact on
the operations of our facilities.

Since the adoption of the United Nations Framework on Climate Change in
1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton

71

Administration participated in the Kyoto, Japan negotiations, where the basis of
a Climate Change treaty was formulated. Under the treaty, known as the Kyoto
Protocol, the United States would be required, by 2008-2012, to reduce its
greenhouse gas emissions by 7% from 1990 levels. However, because of opposition
to the treaty in the United States Senate, the Kyoto Protocol has not been
submitted to the Senate for ratification. Although legislative developments at
the federal and state level related to controlling greenhouse gas emissions are
beginning, we are not aware of any state legislative developments in the states
in which we operate. If the United States ratifies the Kyoto Protocol or we
otherwise become subject to limitations on emissions of carbon dioxide from our
plants, these requirements could have a significant impact on our operations.

The Comprehensive Environmental Response, Compensation, and Liability Act,
which is also known as CERCLA, and similar state statutes, require the cleanup
of sites from which there has been a release or threatened release of hazardous
substances. We are unaware of any material liabilities under this act; however,
we can not assure you that we will not incur CERCLA liability or similar state
law liability in the future.

NEW ACCOUNTING STANDARDS

Effective January 1, 2001, Edison Mission Energy adopted Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities." The Statement establishes accounting and reporting
standards requiring that every derivative instrument be recorded in the balance
sheet as either an asset or liability measured at its fair value. The Statement
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. For derivatives that
qualify for hedge accounting, depending on the nature of the hedge, changes in
fair value are either offset by changes in the fair value of the hedged assets,
liabilities or firm commitments through earnings or recognized in other
comprehensive income until the hedged item is recognized in earnings. The
ineffective portion of a derivative's change in fair value is immediately
recognized in earnings.

Effective January 1, 2001, we will record all derivatives at fair value
unless the derivatives qualify for the normal sales and purchases exception. We
expect that the portion of our business activities related to physical sales and
purchases of power or fuel and those similar business activities of our
affiliates will qualify for this exception. We expect the majority of our risk
management activities will qualify for treatment under SFAS No. 133 as cash flow
hedges with appropriate adjustments made to other comprehensive income. In the
United Kingdom, we expect that the majority of our activities related to the
Fiddler's Ferry, Ferrybridge and First Hydro power plants will not qualify for
either the normal purchases and sales exception or as cash flow hedges.
Accordingly, we expect the majority of these contracts will be recorded at fair
value, with subsequent changes in fair value recorded through the income
statement.

As a result of the adoption of SFAS No. 133, we expect our quarterly
earnings will be more volatile than earnings reported under our prior accounting
policy. The cumulative effect on prior years' net income resulting from the
change in accounting for derivatives in accordance with SFAS No. 133 is expected
to be less than $10 million, net of tax.

RECENT DEVELOPMENTS

In February 2001, we completed the acquisition of a 50% interest in CBK
Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year
build-rehabilitate-transfer-and-operate agreement with National Power
Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project has
been completed with equity contributions of $117 million (our 50% share is
$58.5 million) required to be made upon completion of the rehabilitation and
expansion, currently scheduled for 2003, and debt financing has been arranged
for the remainder of the cost for this project.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A is filed with this report under Item 7.
"Management's Discussion and Analysis of Results of Operations and Financial
Condition."

72

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements:
Report of Independent Public Accountants................ 74
Consolidated Statements of Income for the years ended 75
December 31, 2000, 1999 and 1998.......................
Consolidated Balance Sheets at December 31, 2000 and 76-77
1999...................................................
Consolidated Statements of Shareholder's Equity for the 78
years ended December 31, 2000, 1999, and 1998..........
Consolidated Statements of Cash Flows for the years 79
ended December 31, 2000, 1999 and 1998.................
Notes to Consolidated Financial Statements.............. 80

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

None.

73

EDISON MISSION ENERGY AND SUBSIDIARIES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of Edison Mission Energy:

We have audited the accompanying consolidated balance sheets of Edison
Mission Energy (a California corporation) and subsidiaries as of December 31,
2000 and 1999, and the related consolidated statements of income, shareholder's
equity and cash flows for each of the three years in the period ended
December 31, 2000. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 Edison
Mission Energy and subsidiaries as of December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States.

Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index of
financial statements are presented for purposes of complying with the Securities
and Exchange Commission's rules and are not part of the basic financial
statements. These schedules have been subjected to the auditing procedures
applied in the audit of the basic financial statements and, in our opinion,
fairly state in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken as a whole.

Arthur Andersen LLP

Orange County, California
March 28, 2001

74

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
----------------------------------
2000 1999 1998
---------- ---------- --------

OPERATING REVENUES
Electric revenues........................................ $2,951,038 $1,360,039 $664,055
Equity in income from energy projects.................... 221,819 218,058 171,819
Equity in income from oil and gas investments............ 45,057 26,286 17,613
Net losses from energy trading and price risk
management............................................. (17,339) (6,413) --
Operation and maintenance services....................... 40,459 37,969 40,293
---------- ---------- --------
Total operating revenues............................. 3,241,034 1,635,939 893,780
---------- ---------- --------

OPERATING EXPENSES
Fuel..................................................... 1,081,817 449,137 176,954
Plant operations......................................... 813,198 291,463 127,711
Operation and maintenance services....................... 28,135 27,501 28,386
Depreciation and amortization............................ 382,130 190,219 87,339
Long-term incentive compensation......................... (55,952) 136,316 39,000
Administrative and general............................... 160,879 114,849 83,925
---------- ---------- --------
Total operating expenses............................. 2,410,207 1,209,485 543,315
---------- ---------- --------
Operating income......................................... 830,827 426,454 350,465
---------- ---------- --------

OTHER INCOME (EXPENSE)
Interest and other income................................ 44,987 45,153 47,016
Gain on sale of assets................................... 25,756 7,627 1,148
Interest expense......................................... (689,397) (353,154) (182,901)
Dividends on preferred securities........................ (32,075) (22,375) (13,149)
---------- ---------- --------
Total other income (expense)......................... (650,729) (322,749) (147,886)
---------- ---------- --------

Income before income taxes............................... 180,098 103,705 202,579
Provision (benefit) for income taxes..................... 72,536 (40,412) 70,445
---------- ---------- --------
INCOME BEFORE ACCOUNTING CHANGE............................ 107,562 144,117 132,134
---------- ---------- --------

Cumulative effect on prior years of change in accounting
for major maintenance costs, net of tax.................. 17,690 -- --
Cumulative effect on prior years of change in accounting
for start-up costs, net of tax........................... -- (13,840) --
---------- ---------- --------

NET INCOME................................................. $ 125,252 $ 130,277 $132,134
========== ========== ========

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

75

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS)

DECEMBER 31,
-------------------------
2000 1999
----------- -----------

ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 962,865 $ 398,695
Accounts receivable--trade, net of allowance of $1,126 in
2000 and 1999........................................... 506,936 254,538
Accounts receivable--affiliates........................... 156,862 9,597
Assets under energy trading and price risk management..... 251,524 --
Inventory................................................. 279,864 258,864
Prepaid expenses and other................................ 49,004 35,665
----------- -----------
Total current assets.................................... 2,207,055 957,359
----------- -----------
INVESTMENTS
Energy projects........................................... 2,044,043 1,891,703
Oil and gas............................................... 43,549 49,173
----------- -----------
Total investments....................................... 2,087,592 1,940,876
----------- -----------
PROPERTY, PLANT AND EQUIPMENT............................... 10,585,710 12,533,413
Less accumulated depreciation and amortization............ 721,586 411,079
----------- -----------
Net property, plant and equipment....................... 9,864,124 12,122,334
----------- -----------
OTHER ASSETS
Long-term receivables..................................... 267,599 7,767
Goodwill.................................................. 289,146 290,695
Deferred financing costs.................................. 113,652 133,948
Long-term assets under energy trading and price risk
management.............................................. 56,695 --
Restricted cash and other................................. 131,228 81,242
----------- -----------
Total other assets...................................... 858,320 513,652
----------- -----------
TOTAL ASSETS................................................ $15,017,091 $15,534,221
=========== ===========

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

76

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS)

DECEMBER 31,
-------------------------
2000 1999
----------- -----------

LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES
Accounts payable--affiliates.............................. $ 25,489 $ 7,772
Accounts payable and accrued liabilities.................. 736,213 328,057
Liabilities under energy trading and price risk
management.............................................. 281,657 --
Interest payable.......................................... 123,354 89,272
Short-term obligations.................................... 883,389 1,122,067
Current portion of long-term incentive compensation....... 93,000 --
Current maturities of long-term obligations............... 1,767,898 225,679
----------- -----------
Total current liabilities............................... 3,911,000 1,772,847
----------- -----------
LONG-TERM OBLIGATIONS NET OF CURRENT MATURITIES............. 5,334,789 7,439,308
----------- -----------
LONG-TERM DEFERRED LIABILITIES
Deferred taxes and tax credits............................ 1,611,485 1,520,490
Deferred revenue.......................................... 460,481 534,531
Long-term incentive compensation.......................... 51,766 253,513
Long-term liabilities under energy trading and price risk
management.............................................. 58,016 --
Other..................................................... 314,610 468,161
----------- -----------
Total long-term deferred liabilities.................... 2,496,358 2,776,695
----------- -----------
TOTAL LIABILITIES........................................... 11,742,147 11,988,850
----------- -----------
PREFERRED SECURITIES OF SUBSIDIARIES
Company-obligated mandatorily redeemable security of
partnership holding solely parent debentures............ 150,000 150,000
Subject to mandatory redemption........................... 176,760 208,840
Not subject to mandatory redemption....................... -- 118,054
----------- -----------
Total preferred securities of subsidiaries................ 326,760 476,894
----------- -----------
COMMITMENTS AND CONTINGENCIES
(Notes 7, 8, 13 and 14)

SHAREHOLDER'S EQUITY
Common stock, no par value; 10,000 shares authorized; 100
shares issued and outstanding........................... 64,130 64,130
Additional paid-in capital................................ 2,629,406 2,629,406
Retained earnings......................................... 401,396 364,434
Accumulated other comprehensive income (loss)............. (146,748) 10,507
----------- -----------
TOTAL SHAREHOLDER'S EQUITY.................................. 2,948,184 3,068,477
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY.................. $15,017,091 $15,534,221
=========== ===========

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

77

EDISON MISSION ENERGY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY

(IN THOUSANDS)

ACCUMULATED
ADDITIONAL OTHER
COMMON PAID-IN RETAINED COMPREHENSIVE COMPREHENSIVE SHAREHOLDER'S
STOCK CAPITAL EARNINGS INCOME INCOME EQUITY
-------- ---------- -------- ------------- ------------- -------------

BALANCE AT DECEMBER 31, 1997 $64,130 $ 629,406 $102,620 $ 30,446 $ 826,602
Comprehensive income...........
Net income................... 132,134 $ 132,134 132,134
Other comprehensive income...
Foreign currency
translation adjustment
net of income tax
provision of $52......... (767) (767) (767)
---------
Total Comprehensive income... 131,367
Stock option price appreciation
on options exercised......... (409) (409)
------- ---------- -------- --------- ----------

BALANCE AT DECEMBER 31, 1998 64,130 629,406 234,345 29,679 957,560
Comprehensive income...........
Net income................... 130,277 130,277 130,277
Other comprehensive income...
Foreign currency
translation adjustment
net of income tax benefit
of $1,678................ (19,172) (19,172) (19,172)
---------
Total comprehensive income... 111,105
Contributions................ 2,000,000 2,000,000
Stock option price
appreciation on options
exercised.................. (188) (188)
------- ---------- -------- --------- ----------

BALANCE AT DECEMBER 31, 1999 64,130 2,629,406 364,434 10,507 3,068,477
Comprehensive income...........
Net income................... 125,252 125,252 125,252
Other comprehensive income...
Foreign currency
translation adjustment
net of income tax benefit
of $3,934................ (157,255) (157,255) (157,255)
---------
Total comprehensive income..... $ (32,003)
=========
Cash dividends to parent....... (88,000) (88,000)
Stock option price appreciation
on options exercised......... (290) (290)
------- ---------- -------- --------- ----------

BALANCE AT DECEMBER 31, 2000 $64,130 $2,629,406 $401,396 $(146,748) $2,948,184
======= ========== ======== ========= ==========

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

78

EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
-----------------------------------
2000 1999 1998
---------- ---------- ---------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................ $ 125,252 $ 130,277 $ 132,134
Adjustments to reconcile net income to net cash provided
by operating activities
Equity in income from energy projects................... (221,819) (218,058) (171,819)
Equity in income from oil and gas investments........... (45,057) (26,286) (17,613)
Distributions from energy projects...................... 188,741 188,040 165,206
Dividends from oil and gas.............................. 37,480 23,423 19,812
Depreciation and amortization........................... 382,130 190,219 87,339
Amortization of discount on short-term obligations...... 66,376 15,649 --
Deferred taxes and tax credits.......................... 242,062 67,741 85,138
Gain on sale of assets.................................. (25,756) (7,627) (1,148)
Cumulative effect on prior years of change in
accounting, net of tax................................ (17,690) 13,840 --
Decrease (increase) in accounts receivable................ (340,707) (178,803) 6,800
Increase in inventory..................................... (1,195) (39,692) (473)
Decrease in assets under risk management.................. 27,688 -- --
Decrease (increase) in prepaid expenses and other......... 4,117 (11,563) (32,375)
Increase in interest payable.............................. 43,809 32,564 14,081
Increase (decrease) in accounts payable and accrued
liabilities............................................. 322,239 163,589 (8,648)
Increase in liabilities under risk management............. 8,926 -- --
Increase (decrease) in long-term incentive compensation... (108,747) 134,862 32,952
Other, net................................................ (22,641) (61,025) (44,798)
---------- ---------- ---------
Net cash provided by operating activities............... 665,208 417,150 266,588
---------- ---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowing on long-term obligations........................ 3,099,206 5,267,843 102,450
Payments on long-term obligations......................... (3,366,345) (255,718) (84,502)
Short-term financing, net................................. (303,257) 1,114,586 --
Issuance of preferred securities.......................... -- 326,168 --
Redemption of preferred securities........................ (124,650) -- --
Capital contributions from parent......................... -- 2,000,000 --
Cash dividends to parent.................................. (88,000) -- --
Financing costs........................................... -- (89,429) --
---------- ---------- ---------
Net cash provided by (used in) financing activities..... (783,046) 8,363,450 17,948
---------- ---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in and loans to energy projects............... (177,466) (97,570) (117,216)
Purchase of generating stations........................... (16,895) (7,958,474) --
Purchase of common stock of acquired companies............ (104,774) (653,499) (221,985)
Capital expenditures...................................... (352,330) (216,440) (73,393)
Proceeds from sale-leaseback transactions................. 1,667,000 -- --
Proceeds from loan repayments............................. 13,735 31,661 12,790
Proceeds from sale of assets.............................. 35,546 34,833 4,100
Increase in restricted cash............................... (60,048) (341) (12,507)
Investments in other assets............................... (262,662) 50,337 (18,973)
Other, net................................................ (23,989) (28,267) 18,941
---------- ---------- ---------
Net cash provided by (used in) investing activities..... 718,117 (8,837,760) (408,243)
---------- ---------- ---------
Effect of exchange rate changes on cash..................... (36,109) (3,323) (2,998)
---------- ---------- ---------
Net increase (decrease) in cash and cash equivalents........ 564,170 (60,483) (126,705)
Cash and cash equivalents at beginning of period............ 398,695 459,178 585,883
---------- ---------- ---------
Cash and cash equivalents at end of period.................. $ 962,865 $ 398,695 $ 459,178
========== ========== =========

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

79

EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN MILLIONS)

NOTE 1. GENERAL

ORGANIZATION

Edison Mission Energy is a wholly-owned subsidiary of The Mission Group, a
wholly-owned, non-utility subsidiary of Edison International, the parent holding
company of Southern California Edison Company. Through our subsidiaries, we are
engaged in the business of developing, acquiring, owning or leasing and
operating electric power generation facilities worldwide. We also conduct energy
trading and price risk management activities in power markets open to
competition.

CALIFORNIA POWER CRISIS

Edison International, our ultimate parent company, is a holding company.
Edison International is also the corporate parent of Southern California Edison
Company, an electric utility that buys and sells power in California. In the
past year, various market conditions and other factors have resulted in higher
wholesale power prices to California utilities. At the same time, two of the
three major utilities, Southern California Edison and Pacific Gas and Electric
Co., have operated under a retail rate freeze. As a result, there has been a
significant under recovery of costs by Southern California Edison and Pacific
Gas and Electric, and each of these companies has failed to make payments due to
power suppliers and others. Given these and other payment defaults, creditors of
Southern California Edison and Pacific Gas and Electric could file involuntary
bankruptcy petitions against these companies. Other results of the under
recoveries could include an end to the rate freeze and significant retail rate
increases. A number of federal and state, legislative and regulatory initiatives
addressing the issues of the California electric power industry have been
proposed, including wholesale rate caps, retail rate increases, acceleration of
power plant permitting and state entry into the power market. Many of these
activities are ongoing. These activities may result in a restructuring of the
California power market. At this time, these activities are in their preliminary
stages, and it is not possible to estimate their likely ultimate outcome For
more information on how the current California power crisis affects our
investments, see "--Note 13. Commitments and Contingencies--Other Commitments
and Contingencies--California Power Crisis."

Southern California Edison's current financial condition has had, and may
continue to have, an adverse impact on Edison International's credit quality
and, as previously reported by Edison International, has resulted in
cross-defaults under Edison International's credit facilities. Both Standard &
Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the
credit ratings of Edison International and Southern California Edison to
substantially below investment grade levels. The credit ratings remain under
review for potential downgrade by both Standard & Poor's and Moody's.

To isolate ourselves from the credit downgrades and potential bankruptcies
of Edison International and Southern California Edison, and to facilitate our
ability and the ability of our subsidiaries to maintain their respective
investment grade credit ratings, on January 17, 2001, we amended our articles of
incorporation and our bylaws to include so-called "ring-fencing" provisions.
These ring-fencing provisions are intended to preserve us as a stand-alone
investment grade rated entity despite the current credit difficulties of Edison
International and Southern California Edison. These provisions

80

require the unanimous approval of our board of directors, including at least one
independent director, before we can do any of the following:

- declare or pay dividends or distributions unless:

- we then have an investment grade credit rating and receive rating
agency confirmation that the dividend or distribution will not result
in a downgrade; or

- the dividends do not exceed $32.5 million in any fiscal quarter and we
meet an interest coverage ratio of not less than 2.2 to 1 for the
immediately preceding four fiscal quarters. We currently meet this
interest coverage ratio;

- institute or consent to bankruptcy, insolvency or similar proceedings or
actions; or

- consolidate or merge with any entity or transfer substantially all our
assets to any entity, except to an entity that is subject to similar
restrictions.

We cannot assure you that these measures will effectively isolate us from
the credit downgrades or the potential bankruptcies of Edison International and
Southern California Edison. In January 2001, Standard & Poor's and Moody's
lowered our credit ratings. Our senior unsecured credit ratings were downgraded
to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's.
Our credit ratings remain investment grade. Both Standard & Poor's and Moody's
have indicated that the credit ratings outlook for us is stable. A downgrade in
our credit ratings below investment grade could increase our cost of capital,
increase our credit support obligations, make efforts to raise capital more
difficult and could have an adverse impact on us and our subsidiaries.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

CONSOLIDATIONS

The consolidated financial statements include Edison Mission Energy and its
majority-owned subsidiaries, partnerships and a special purpose corporation. All
significant intercompany transactions have been eliminated. Certain prior year
reclassifications have been made to conform to the current year financial
statement presentation.

MANAGEMENT'S USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.

CASH EQUIVALENTS

Cash equivalents include time deposits and other investments totaling
$555.7 million at December 31, 2000, with maturities of three months or less.
All investments are classified as available-for-sale.

INVESTMENTS

Investments in energy projects and oil and gas investments with 50% or less
voting stock are accounted for by the equity method. The majority of energy
projects and all investments in oil and gas are accounted for under the equity
method at December 31, 2000 and 1999. The equity method of accounting is
generally used to account for the operating results of entities over which we
have a significant influence but in which we do not have a controlling interest.

81

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, including leasehold improvements and
construction in progress, are capitalized at cost and are principally comprised
of our majority-owned subsidiaries' plants and related facilities. Depreciation
and amortization are computed by using the straight-line method over the useful
life of the property, plant and equipment and over the lease term for leasehold
improvements.

As part of the acquisition of the Illinois Plants and the Homer City plant,
we acquired emission allowances under the Environmental Protection Agency's Acid
Rain Program. Although the emission allowances granted under this program are
freely transferable, we intend to use substantially all the emission allowances
in the normal course of our business to generate electricity. Accordingly, we
have classified emission allowances expected to be used by us to generate power
as part of property, plant and equipment. Acquired emission allowances will be
amortized over the estimated lives of the plants on a straight-line basis.

Useful lives for property, plant, and equipment are as follows:

Furniture and office equipment.............................. 3 - 20 years
Building, plant and equipment............................... 10 - 60 years
Emission allowances......................................... 20 - 40 years
Civil works................................................. 40 - 80 years
Capitalized leased equipment................................ 25 - 33 years
Leasehold improvements...................................... Life of lease

GOODWILL

Goodwill represents the cost incurred in excess of the fair value of net
assets acquired in a purchase transaction. The amounts are being amortized on a
straight-line basis over periods ranging from 20 to 40 years. Accumulated
amortization was $38.8 million and $33.2 million at December 31, 2000 and 1999,
respectively.

IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS

We periodically evaluate the potential impairment of our investments in
projects and other long-lived assets, including goodwill, based on a review of
estimated future cash flows expected to be generated. If the carrying amount of
the investment or asset exceeds the amount of the expected future cash flows,
undiscounted and without interest charges, then an impairment loss for our
investments in projects and other long-lived assets is recognized in accordance
with Accounting Principles Board Opinion No. 18 "The Equity Method of Accounting
for Investments in Common Stock" and Statement of Financial Accounting Standards
No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," respectively.

CAPITALIZED INTEREST

Interest incurred on funds borrowed by us to finance project construction is
capitalized. Capitalization of interest is discontinued when the projects are
completed and deemed operational. Such capitalized interest is included in
investment in energy projects and property, plant and equipment.

82

Capitalized interest is amortized over the depreciation period of the major
plant and facilities for the respective project.

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Interest incurred................................... $703.7 $380.6 $209.2
Interest capitalized................................ (14.3) (27.4) (26.3)
------ ------ ------
$689.4 $353.2 $182.9
====== ====== ======

INCOME TAXES

We are included in the consolidated federal income tax and combined state
franchise tax returns of Edison International. We calculate our income tax
provision on a separate company basis under a tax sharing arrangement with The
Mission Group, which in turn has an agreement with Edison International. Tax
benefits generated by us and used in the Edison International consolidated tax
return are recognized by us without regard to separate company limitations.

We account for income taxes using the asset-and-liability method, wherein
deferred tax assets and liabilities are recognized for future tax consequences
of temporary differences between the carrying amounts and the tax bases of
assets and liabilities using enacted rates. Investment and energy tax credits
are deferred and amortized over the term of the power purchase agreement of the
respective project. Income tax accounting policies are discussed further in
Note 10.

MAINTENANCE ACCRUALS

Certain of our plant facilities' major pieces of equipment require major
maintenance on a periodic basis. These costs are expensed as incurred. Through
December 31, 1999, we accrued for major maintenance costs incurred during the
period between turnarounds (referred to as "accrue in advance" accounting
method). The accounting policy has been widely used by independent power
producers as well as several other industries. In March 2000, the Securities and
Exchange Commission issued a letter to the Accounting Standards Executive
Committee, stating its position that the Securities and Exchange Commission
staff does not believe it is appropriate to use an "accrue in advance" method
for major maintenance costs. The Accounting Standards Executive Committee agreed
to add accounting for major maintenance costs as part of an existing project and
to issue authoritative guidance by August 2001. Due to the position taken by the
Securities and Exchange Commission staff, we voluntarily decided to change our
accounting policy to record major maintenance costs as an expense as incurred.
Such change in accounting policy is considered preferable based on the recent
guidance provided by the Securities and Exchange Commission. In accordance with
Accounting Principles Board Opinion No. 20, "Accounting Changes," we have
recorded $17.7 million, after tax, increase to net income, as a cumulative
change in the accounting for major maintenance costs during the quarter ended
March 31, 2000. Pro forma data have not been provided for prior periods, as the
impact would not be material.

PROJECT DEVELOPMENT COSTS

We capitalize only the direct costs incurred in developing new projects
subsequent to being awarded a bid. These costs consist of professional fees,
salaries, permits, and other directly related development costs incurred by us.
The capitalized costs are amortized over the life of operational projects or
charged to expense if management determines the costs to be unrecoverable.

83

DEFERRED FINANCING COSTS

Bank, legal and other direct costs incurred in connection with obtaining
financing are deferred and amortized as interest expense on a basis which
approximates the effective interest rate method over the term of the related
debt. Accumulated amortization of these costs amounted to $30.4 million in 2000
and $9.7 million in 1999.

REVENUE RECOGNITION

We record revenue and related costs as electricity is generated or services
are provided. For our long-term power contracts that provide for higher pricing
in the early years of the contract, revenue is recognized in accordance with
Emerging Issues Task Force Issued Number 91-6 "Revenue Recognition of Long-Term
Sales Contract," which results in a deferral and levelization of revenues being
recognized. Also included in deferred revenues is the deferred gain from the
termination of the Loy Yang B power sales agreement. Revenues are adjusted for
price differentials resulting from electricity rate swap agreements in the
United States, United Kingdom and Australia. These rate swap agreements are
discussed further in Note 7.

DERIVATIVE FINANCIAL INSTRUMENTS

We engage in price risk management activities for both trading and
non-trading purposes. Derivative financial instruments are mainly utilized by us
to manage exposure to fluctuations in interest rates, foreign exchange rates,
oil and gas prices and energy prices. Hedge accounting is utilized to account
for financial instruments entered into for non-trading purposes so long as there
is a high degree of correlation between price movements in the derivative and
the item designated as being hedged. For example, the differentials to be paid
or received related to interest rate agreements are recorded as adjustments to
interest expense. The differentials to be paid or received related to
electricity rate swap agreements are currently recorded as adjustments to
electric revenues or fuel expenses. An electricity rate swap agreement is an
exchange of a fixed price of electricity for a floating price. Under hedge
accounting, gains and losses on financial instruments used for hedging purposes
are recognized in the Consolidated Income Statement in the same manner as the
hedged item. If a derivative financial instrument contract is terminated because
it is probable that a transaction or forecasted transaction will not occur, any
gain or loss as of such date is immediately recognized. If a derivative
financial instrument contract is terminated for other economic reasons, any gain
or loss as of the termination date is deferred and recorded concurrently with
the related energy purchase or sale. Mark-to-market accounting would be used if
the hedge accounting criteria were not met.

Derivative financial instruments that are utilized for trading purposes are
accounted for using the fair value method under EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities." Under this
method, forwards, futures, options, swaps and other financial instruments with
third parties are reflected at market value and are included in the balance
sheet as assets or liabilities from energy trading activities. In the absence of
quoted value, financial instruments are valued at fair value, considering time
value, volatility of the underlying commodity, and other factors as determined
by Edison Mission Energy. Resulting gains and losses are recognized in net gains
(losses) from energy trading and price risk management in the accompanying
Consolidated Income Statements in the period of change. Assets from energy
trading and price risk management activities include the fair value of open
financial positions related to trading activities and the present value of net
amounts receivable from structured transactions. Liabilities from energy trading
and price risk management activities include the fair value of open financial
positions related to trading activities of open financial positions related to
trading activities and the present value of net amounts payable from structured
transactions.

84

TRANSLATION OF FOREIGN FINANCIAL STATEMENTS

Assets and liabilities of most foreign operations are translated at end of
period rates of exchange, and the income statements are translated at the
average rates of exchange for the year. Gains or losses from translation of
foreign currency financial statements are included in comprehensive income in
shareholder's equity. Gains or losses resulting from foreign currency
transactions are normally included in other income in the consolidated
statements of income. Foreign currency transaction gains/(losses) amounted to
$12.8 million, ($1.7) million and ($1.2) million for 2000, 1999 and 1998,
respectively.

STOCK-BASED COMPENSATION

We measure compensation expense relative to stock-based compensation by the
intrinsic-value method.

NEW ACCOUNTING STANDARD

Effective January 1, 2001, Edison Mission Energy adopted Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities." The Statement establishes accounting and reporting
standards requiring that every derivative instrument be recorded in the balance
sheet as either an asset or liability measured at its fair value. The Statement
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. For derivatives that
qualify for hedge accounting, depending on the nature of the hedge, changes in
fair value are either offset by changes in the fair value of the hedged assets,
liabilities or firm commitments through earnings or recognized in other
comprehensive income until the hedged item is recognized in earnings. The
ineffective portion of a derivative's change in fair value is immediately
recognized in earnings.

Effective January 1, 2001, we will record all derivatives at fair value
unless the derivatives qualify for the normal sales and purchases exception. We
expect that the portion of our business activities related to physical sales and
purchases of power or fuel and those similar business activities of our
affiliates will qualify for this exception. We expect the majority of our risk
management activities will qualify for treatment under SFAS No. 133 as cash flow
hedges with appropriate adjustments made to other comprehensive income. In the
United Kingdom, we expect that the majority of our activities related to the
Fiddler's Ferry, Ferrybridge and First Hydro power plants will not qualify for
either the normal purchases and sales exception or as cash flow hedges.
Accordingly, we expect the majority of these contracts will be recorded at fair
value, with subsequent changes in fair value recorded through the income
statement.

As a result of the adoption of SFAS No. 133, we expect our quarterly
earnings will be more volatile than earnings reported under our prior accounting
policy. The cumulative effect on prior years' net income resulting from the
change in accounting for derivatives in accordance with SFAS No. 133 is expected
to be less than $10 million, net of tax.

NOTE 3. INVENTORY

Inventory is stated at the lower of weighted average cost or market.
Inventory at December 31, 2000 and December 31, 1999 consisted of the following:

2000 1999
-------- --------

Coal and fuel oil........................................... $207.8 $190.1
Spare parts, materials and supplies......................... 72.1 68.8
------ ------
Total....................................................... $279.9 $258.9
====== ======

85

NOTE 4. ACQUISITIONS

ACQUISITION OF SUNRISE PROJECT

On November 17, 2000, we completed a transaction with Texaco Inc. to
purchase a proposed 560 MW gas fired combined cycle project to be located in
Kern County, California, referred to as the Sunrise Project. The acquisition
included all rights, title and interest held by Texaco in the Sunrise Project,
except that Texaco has an option to repurchase a 50% interest in the project
prior to its commercial operation. As part of this transaction, we also:
(i) acquired from Texaco an option to purchase two gas turbines which we plan to
utilize in the project, (ii) provided Texaco an option to purchase two of the
turbines available to us under the Edison Mission Energy Master Turbine Lease
and (iii) granted Texaco an option to acquire a 50% interest in 1000 MW of
future power plant projects we designate. For more information on the Edison
Mission Energy Master Turbine Lease, see "Note 14. Lease Commitments--Edison
Mission Energy Master Turbine Lease." The Sunrise Project consists of two phases
with Phase I, construction of a single-cycle gas fired facility (320 MW),
currently scheduled to be completed in August 2001, and Phase II, conversion to
a combined-cycle gas fired facility (560 MW), currently scheduled to be
completed in June 2003. In December 2000, we received the Energy Commission
Certification and a permit to construct the Sunrise Plant, which allowed us to
commence construction of Phase I. We are negotiating with the California
Department of Water Resources the detailed terms and conditions of a long-term
cost-based-type rate power purchase agreement. We cannot assure you that we will
be successful in reaching a final agreement.

The total purchase price of the Sunrise Project was $27 million. We funded
the purchase with cash. The total estimated construction cost of this project is
approximately $400 million. As of December 31, 2000, we had also spent
$17.8 million on construction costs for the Sunrise Project.

ACQUISITION OF TRADING OPERATIONS OF CITIZENS POWER LLC

On September 1, 2000, we completed a transaction with P&L Coal Holdings
Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading
operations of Citizens Power LLC and a minority interest in structured
transaction investments relating to long-term power purchase agreements. The
purchase price of $44.9 million was based on the sum of: (a) fair market value
of the trading portfolio and the structured transaction investments at the date
of the acquisition and (b) $25 million. The acquisition was funded with cash. As
a result of this acquisition, we have expanded our trading operations beyond the
traditional marketing of our electric power. By the end of the third quarter of
2000, the Citizens trading operations were merged into our own marketing
operations under Edison Mission Marketing & Trading, Inc.

ACQUISITION OF INTEREST IN ITALIAN WIND

On March 15, 2000, we completed a transaction with UPC International
Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly
known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50%
interest in a series of power projects that are in operation or under
development in Italy. All the projects use wind to generate electricity from
turbines which is sold under fixed-price, long-term tariffs. Assuming all
projects under development are completed, currently scheduled for 2002, the
total capacity of these projects will be 283 MW. The total purchase price is
90 billion Italian Lira (approximately $44 million at December 31, 2000), with
equity contribution obligations of up to 33 billion Italian Lira (approximately
$16 million at December 31, 2000), depending on the number of projects that are
ultimately developed. As of December 31, 2000, our payments in respect of these
projects included $27 million toward the purchase price and $13 million in
equity contributions.

86

ACQUISITION OF ILLINOIS PLANTS

On December 15, 1999, we completed a transaction with Commonwealth Edison, a
subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel
power generating plants located in Illinois, which are collectively referred to
as the Illinois Plants. These plants provide access to Mid-America
Interconnected Network and the East Central Area Reliability Council. In
connection with this transaction, we entered into power purchase agreements with
Commonwealth Edison with terms of up to five years, pursuant to which
Commonwealth Edison purchases capacity and has the right to purchase energy
generated by the plants. Subsequently, Commonwealth Edison assigned its rights
and obligations under these power purchase agreements to Exelon Generation
Company, LLC.

Concurrently with the acquisition of the Illinois Plants, we assigned our
right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating
station located in Illinois, to third party lessors. After this assignment, we
entered into leases of the Collins Station with terms of 33.75 years. The
aggregate megawatts either purchased or leased as a result of these transactions
with Commonwealth Edison Company and the third party lessors is 9,539 MW.

Consideration for the Illinois Plants, excluding $860 million paid by the
third party lessors to acquire the Collins Station, consisted of a cash payment
of approximately $4.1 billion. The acquisition was funded primarily with a
combination of approximately $1.6 billion of non-recourse debt secured by a
pledge of the stock of specified subsidiaries, $1.3 billion of Edison Mission
Energy's debt and $1.2 billion in equity contributions to us from Edison
International.

ACQUISITION OF FERRYBRIDGE AND FIDDLER'S FERRY PLANTS

On July 19, 1999, we completed a transaction with PowerGen UK plc to acquire
the Ferrybridge and Fiddler's Ferry coal fired electric generating plants
located in the U.K.. Ferrybridge, located in West Yorkshire, and Fiddler's
Ferry, located in Warrington, each has a generating capacity of approximately
2,000 MW.

Consideration for the purchase of the Ferrybridge and Fiddler's Ferry plants
by our indirect subsidiary, Edison First Power, consisted of an aggregate of
approximately $2.0 billion (L1.3 billion sterling at the time of the
acquisition) for the two plants. The acquisition was funded primarily with a
combination of net proceeds of L1.15 billion from the Edison First Power Limited
Guaranteed Secured Variable Rate Bonds due 2019, a $500 million equity
contribution to us from Edison International and cash. The Edison First Power
Bonds were issued to a special purpose entity formed by Merrill Lynch
International. Merrill Lynch International sold the variable rate coupons
portion of the bonds to a special purpose entity that borrowed $1.3 billion
(830 million pounds sterling at the time of the acquisition) under a term loan
facility due 2012 to finance the purchase.

ACQUISITION OF INTEREST IN CONTACT ENERGY

On May 14, 1999, we completed a transaction with the New Zealand government
to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in an overseas public offering resulting in
widespread ownership among the citizens of New Zealand and offshore investors.
These shares are publicly traded on stock exchanges in New Zealand and
Australia. During 2000, we increased our share of ownership in Contact Energy to
42%. Contact Energy owns and operates hydroelectric, geothermal and natural gas
fired power generating plants primarily in New Zealand with a total current
generating capacity of 2,449 MW.

Consideration for Contact Energy consisted of a cash payment of
approximately $635 million (1.2 billion New Zealand dollars at the time of the
acquisition), which was financed by $120 million of preferred securities, a
$214 million (400 million New Zealand dollars at the time of the acquisition)

87

credit facility, a $300 million equity contribution to us from Edison
International and cash. The credit facility was subsequently paid off with
proceeds from the issuance of additional preferred securities.

ACQUISITION OF HOMER CITY PLANT

On March 18, 1999, we completed a transaction with GPU, Inc., New York State
Electric & Gas Corporation and their respective affiliates to acquire the 1,884
MW Homer City Electric Generating Station. This facility is a coal fired plant
in the mid-Atlantic region of the United States and has direct, high voltage
interconnections to both the New York Independent System Operator, which
controls the transmission grid and energy and capacity markets for New York
State and is commonly known as the NYISO, and the Pennsylvania-New
Jersey-Maryland Power Pool, which is commonly known as the PJM.

Consideration for the Homer City plant consisted of a cash payment of
approximately $1.8 billion, which was partially financed by $1.5 billion of new
loans, combined with our revolver borrowings and cash.

ACQUISITION OF INTEREST IN ECOELECTRICA

In December 1998, we acquired 50% of the 540 MW EcoElectrica liquefied
natural gas combined-cycle cogeneration facility under construction in Penuelas,
Puerto Rico for approximately $243 million. The project also includes a
desalination plant and liquefied natural gas storage and vaporization
facilities. Commercial operation commenced March 2000.

ACCOUNTING TREATMENT OF ACQUISITIONS

Each of the acquisitions described above has been accounted for utilizing
the purchase method. The purchase price was allocated to the assets acquired and
liabilities assumed based on their respective fair market values. Amounts in
excess of the fair value of the net assets acquired have been assigned to
goodwill. Our consolidated statement of income reflects the operations of
Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000,
EcoElectrica beginning March 1, 2000, the Homer City plant beginning March 18,
1999, Contact Energy beginning May 1, 1999, the Ferrybridge and Fiddler's Ferry
plants beginning July 19, 1999, and the Illinois Plants beginning December 15,
1999.

PRO FORMA DATA

The following unaudited pro forma data summarizes the consolidated results
of operations for the periods indicated as if the acquisition of the Ferrybridge
and Fiddler's Ferry plants had occurred at the beginning of 1999 and 1998. The
pro forma data gives effect to certain adjustments including electric revenues,
fuel expense, plant operations, depreciation and amortization, interest expense
and related income tax adjustments. These results have been prepared for
comparative purposes only and do not purport to be indicative of what would have
occurred had the acquisitions been made at the beginning of 1999 and 1998 or of
the results which may occur in the future. Pro forma data has not been provided
for the acquisitions of the Homer City plant and the Illinois Plants because
these plants were previously operated as part of an integrated, regulated
utility whose primary business was the sale of power bundled with transmission,
distribution and customer support to retail customers. Accordingly, historical
financial results of these plants would not be meaningful and are not required
due to the acquisitions not being considered business combinations. Pro forma
financial information is not

88

presented for the acquisition of trading operations of Citizens Power LLC as the
effect of this acquisition was not material to our results of operations or
financial position.

(UNAUDITED)
YEARS ENDED
DECEMBER 31,
-------------------
1999 1998
-------- --------

Operating revenues....................................... $1,889.9 $1,447.9
Income before accounting change and extraordinary loss... 126.2 95.7
Net income............................................... 112.4 95.7

The table below summarizes additional acquisitions by Edison Mission Energy
or its wholly-owned subsidiaries from 1998 through 2000.

PERCENTAGE
DATE ACQUISITION ACQUIRED PURCHASE PRICE
- ---- ------------------------------ ---------- --------------

ENERGY PROJECTS
October 5, 1999....... Pride Hold Limited (Roosecote) 20.0% $16.0
July 10, 1998......... Tri Energy Company Limited 25.0% 1.5

OIL AND GAS
July 28, 2000......... Four Star Oil & Gas Company 1.7% 1.4
May 15, 2000.......... Four Star Oil & Gas Company 1.7% 1.8
December 17, 1999..... Four Star Oil & Gas Company 0.6% 2.3
January 1, 1998....... Four Star Oil & Gas Company 3.2% 4.1

NOTE 5. INVESTMENTS

INVESTMENTS IN ENERGY PROJECTS

Investments in energy projects, generally 50% or less owned partnerships and
corporations, are accounted for by the equity method. The difference between the
carrying value of energy project investments and the underlying equity in the
net assets amounted to $479 million at December 31, 2000. The differences are
being amortized over the life of the projects. The following table presents
summarized financial information of the investments in energy projects:

DECEMBER 31,
-------------------
2000 1999
-------- --------

DOMESTIC ENERGY PROJECTS
Equity investment...................................... $ 398.5 $ 424.7
Loans receivable....................................... 165.7 151.9
-------- --------
Subtotal............................................. 564.2 576.6
-------- --------
INTERNATIONAL ENERGY PROJECTS
Equity investment...................................... 1,479.8 1,315.1
-------- --------
Total................................................ $2,044.0 $1,891.7
======== ========

Our subsidiaries have provided loans or advances related to certain
projects. Domestic loans at December 31, 2000 consist of the following: a
$107.8 million, 10% interest loan, due on demand; a $26.3 million, 5% interest
promissory note, interest payable semiannually, due April 2008; and a
$31.6 million, 12% interest loan, due on demand.

The undistributed earnings of investments accounted for by the equity method
were $270.7 million in 2000 and $223.9 million in 1999.

89

The following table presents summarized financial information of the
investments in energy projects accounted for by the equity method:

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Revenues....................................... $2,470.9 $2,031.8 $1,585.7
Expenses....................................... 1,984.0 1,590.2 1,255.6
-------- -------- --------
Net income................................... $ 486.9 $ 441.6 $ 330.1
======== ======== ========

DECEMBER 31,
-------------------
2000 1999
-------- --------

Current assets........................................... $1,807.9 $ 722.3
Noncurrent assets........................................ 7,371.1 7,728.2
-------- --------
Total assets........................................... $9,179.0 $8,450.5
======== ========
Current liabilities...................................... $1,163.9 $1,584.8
Noncurrent liabilities................................... 5,829.2 4,769.7
Equity................................................... 2,185.9 2,096.0
-------- --------
Total liabilities and equity........................... $9,179.0 $8,450.5
======== ========

The majority of noncurrent liabilities are comprised of project financing
arrangements that are non-recourse to us.

The following table presents, as of December 31, 2000, the energy projects
accounted for by the equity method that represent at least five percent (5%) of
our income before tax or in which we have an investment balance greater than
$50 million.

OWNERSHIP
ENERGY PROJECT LOCATION INVESTMENT INTEREST OPERATING STATUS
- -------------- --------------------- ---------- --------- -----------------------------

Contact Energy........ New Zealand $508.1(1) 42% Operating hydro, natural gas
and geothermal facilities

Paiton................ East Java, Indonesia 489.9 40% Operating coal fired facility

EcoElectrica.......... Penuelas, Puerto Rico 298.4 50% Operating liquefied natural
gas facility

Watson................ Carson, CA 113.2 49% Operating cogeneration
facility

Brooklyn Navy Yard.... Brooklyn, NY 83.1 50% Operating cogeneration
facility

Sycamore.............. Bakersfield, CA 71.4 50% Operating cogeneration
facility

Midway-Sunset......... Fellows, CA 62.1 50% Operating cogeneration
facility

Kern River............ Bakersfield, CA 56.4 50% Operating cogeneration
facility

March Point........... Anacortes, WA 28.0 50% Operating cogeneration
facility

James River........... Hopewell, VA 24.0 50% Operating coal fired
cogeneration facility

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

(1) Investment is translated into U.S. dollars at the year-end exchange rate.

At December 31, 2000, the quoted market value of our investment in Contact
Energy was $288.2 million. The valuation represents a calculation based on the
closing stock price of Contact Energy on the New Zealand stock exchange and is
not necessarily indicative of the amount that could

90

be realized upon sale. We expect to recover our investment in Contact Energy
based on future cash flows forecasted to be generated from the project.

INVESTMENTS IN OIL AND GAS

At December 31, 2000, we had one 35.84%-owned (with 34.54% voting stock) and
one 50%-owned investment in oil and gas. These investments are accounted for
utilizing the equity method. The difference between the carrying value of one
oil and gas investment and the underlying equity in the net assets amounted to
$10.8 million at December 31, 2000. The difference is being amortized on a unit
of production basis over the life of the reserves. The following table presents
summarized financial information of the investments in oil and gas:

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Operating revenues.................................. $382.6 $224.3 $211.3
Operating expenses.................................. 187.0 144.5 164.1
------ ------ ------
Operating income.................................... 195.6 79.8 47.2
Provision (credit) for income taxes................. 63.6 16.9 (2.3)
------ ------ ------
Net income (before non-operating items)............. 132.0 62.9 49.5
Non-operating expense, net.......................... (9.8) (10.4) (13.5)
------ ------ ------
Net income........................................ $122.2 $ 52.5 $ 36.0
====== ====== ======

DECEMBER 31,
-------------------
2000 1999
-------- --------

Current assets.............................................. $ 98.8 $ 47.0
Noncurrent assets........................................... 350.9 377.2
------ ------
Total assets.............................................. $449.7 $424.2
====== ======
Current liabilities......................................... $ 36.5 $ 22.7
Noncurrent liabilities...................................... 238.6 238.6
Deferred income taxes and other liabilities................. 61.7 48.1
Equity...................................................... 112.9 114.8
------ ------
Total liabilities and equity.............................. $449.7 $424.2
====== ======

During the fourth quarter of 1999, we completed the sale of 31.5% of our
50.1% interest in Four Star Oil & Gas for $34.2 million in cash and 50% interest
in the acquirer, Four Star Holdings. Four Star Holdings financed the purchase of
the interest in Four Star Oil & Gas from $27.5 million in loans from affiliates,
including $13.7 million from us, and $13.7 million from cash on hand. Upon
completion of the sale, we continue to own an 18.6% direct interest in Four Star
Oil & Gas and an indirect interest of 15.75% which is held through Four Star
Holdings. As a result of this transaction, our total interest in Four Star
Oil & Gas has decreased from 50.1% to 34.35%. Cash proceeds from the sale were
$34.2 million ($20.5 million net of the loan to Four Star Holdings). The gain on
the sale of the 31.5% interest in Four Star Oil & Gas was $11.5 million of which
we deferred 50%, or $5.6 million, due to our equity interest in Four Star
Holdings. The after-tax gain on the sale was approximately $30 million.

91

NOTE 6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following:

DECEMBER 31,
--------------------
2000 1999
-------- ---------

Buildings, plant and equipment.......................... $7,842.6 $ 9,957.1
Emission allowances..................................... 1,285.3 1,310.9
Civil works............................................. 929.2 956.5
Construction in progress................................ 335.8 108.8
Capitalized leased equipment............................ 192.8 200.1
-------- ---------
10,585.7 12,533.4
Less accumulated depreciation and amortization.......... 721.6 411.1
-------- ---------
Net property, plant and equipment..................... $9,864.1 $12,122.3
======== =========

In connection with the Homer City, Loy Yang B, First Hydro, Doga and Iberian
Hy-Power plant financings, lenders have taken a security interest in the
respective plant assets.

NOTE 7. FINANCIAL INSTRUMENTS

SHORT-TERM OBLIGATIONS

DECEMBER 31,
----------------------
2000 1999
-------- --------

Commercial Paper......................................... $444.2 $1,130.0
Other short-term obligations............................. 440.7 --
Unamortized discount..................................... (1.5) (7.9)
------ --------
Total.................................................. $883.4 $1,122.1
====== ========
Weighted-average interest rate........................... 7.4% 6.9%

Commercial paper consists of a $700 million senior credit facility due
May 2001 of which $444.2 million was outstanding at December 31, 2000. The
commercial paper facility represents recourse debt and is indexed to LIBOR.
Other short-term obligations consist of a borrowing under the $700 million
senior credit facility and the $300 million senior credit facility due May 2001
and a 20 million pounds sterling (approximately $30 million at December 31,
2000) bank borrowing of which $283.5 million and $28.7 million were outstanding,
respectively, at December 31, 2000. At December 31, 1999, commercial paper
consisted of a $700 million facility due March 2000 and a $500 million facility
due November 2000, of which $630 million and $500 million was outstanding,
respectively.

LONG-TERM OBLIGATIONS

Long-term obligations include both corporate debt and non-recourse project
debt, whereby lenders rely on specific project assets to repay such obligations.
At December 31, 2000, recourse debt totaled

92

$1.2 billion and non-recourse project debt totaled $5.9 billion. Long-term
obligations consist of the following:

DECEMBER 31,
--------------------
2000 1999
--------- --------

RECOURSE
Edison Mission Energy (parent only)
Senior Notes, net
due 2002 (8.125%)....................................... $ 99.7 $ 99.6
due 2009 (7.73%)........................................ 596.4 596.1

Floating Rate Notes, net due 2001
(LIBOR+0.67%) (6.79% at 12/31/99)......................... -- 499.5

Bank of America NT&SA Credit Agreement due 2001
(LIBOR+0.175%) (6.849% at 12/31/00)....................... 349.0 215.0

Long-Term Obligations--Affiliate............................ 78.0 78.0

NON-RECOURSE (UNLESS OTHERWISE NOTED)
Edison Mission Energy Funding Corp.
Series A Notes, net due 1997-2003 (6.77%)................. 130.6 168.1
Series B Bonds, net due 2004-2008 (7.33%)................. 189.1 189.0

Edison Mission Holdings Co.
Senior Secured Bonds--$300 MM due 2019 (8.137%)........... 300.0 300.0
Senior Secured Bonds--$530 MM due 2026 (8.734%)........... 530.0 530.0
Construction Loan due 2004 (LIBOR+1.0%) (7.701% at
12/31/00)............................................... 182.0 77.0

Edison Mission Midwest Holdings Co.
Tranche A due 2002 (LIBOR+1.0%) (7.469% at 12/31/99)...... -- 840.0
Tranche B due 2004 (LIBOR+0.95%) (9.247% at 12/31/00)..... 626.0 839.0
Tranche C--$150 MM due 2004 (LIBOR+0.95%) (9.5% at
12/31/00)............................................... 143.4 --
Commercial Paper due 2002 (6.601%)........................ 803.9 --

Doga project
Finance Agreement between Doga and OPIC due 2010
(U.S. Treasury Note+3.75%) (11.2% at 12/31/00).......... 86.6 90.9
NCM Credit Agreement due 2010
(U.S. LIBOR+1.25%) (8.24% at 12/31/00).................. 31.9 33.5

Ferrybridge and Fiddler's Ferry plants
L830 MM Term Loan Facility due 2012
(Sterling LIBOR+1.5%) (7.786% at 12/31/00).............. 1,106.7 1,312.0
Pounds Sterling Coal and Capex Facility due 2003--recourse
(Sterling LIBOR+0.875%+0.15%) (7.29% at 12/31/00)....... 86.7 22.6
L150 MM Long-term Obligation--Affiliate................... 224.3 --

First Hydro plants
First Hydro Finance plc L400 MM Guaranteed Secured Bonds
due 2021 (9%)........................................... 598.2 645.2
L18 MM Credit Agreement due 2004
(Sterling LIBOR+0.55%+0.0145%) (6.904% at 12/31/00)..... 26.9 29.0

Iberian Hy-Power plants
Spanish peseta Project Finance Credit Facility due 2012
(MIBOR+0.75%) (5.69% at 12/31/00)....................... 56.2 53.9
Spanish peseta Subordinated Loan due 2003 (9.408%)........ 10.7 15.3
Spanish peseta Compagnie Generale Des Eaux due 2003
(non-interest bearing).................................. 22.5 31.9

Kwinana plant
Australian dollar Syndicated Project Facility Agreement
due 2012 (BBR+1.2%) (7.52% at 12/31/00)................. 49.8 62.4

93

DECEMBER 31,
--------------------
2000 1999
--------- --------

Loy Yang B plant
Australian dollar Amortizing Term Facility due 2017
(BBR+0.5% to 1.1%) (7.037% at 12/31/00)................. 392.9 321.2
Australian dollar Interest Only Term Facility due 2012
(BBR+0.5% to 0.85%) (7.037% at 12/31/00)................ 272.5 484.6
Australian dollar Working Capital Facility due 2017
(BBR+0.5% to 1.1%) (7.037% at 12/31/00)................. 5.6 6.6

Roosecote plant
Pounds sterling Term Loan and Guarantee Facility due 2005
(Sterling LIBOR+0.6%) (6.77% at 12/31/00)............... 98.8 97.8
Capital lease obligation (see Note 14).................... 0.9 22.8
Other long-term obligations--recourse....................... 3.4 4.0
--------- --------
Subtotal.................................................... $ 7,102.7 $7,665.0
Current maturities of long-term obligations................. (1,767.9) (225.7)
--------- --------
Total....................................................... $ 5,334.8 $7,439.3
========= ========

At December 31, 2000, we had available $24.5 million of borrowing capacity
and approximately $126.5 million in letters of credit issued under a
$500 million revolving credit facility that expires in October 2001.

LONG-TERM OBLIGATIONS--AFFILIATES

During 1997, we declared a dividend of $78 million to The Mission Group
which was recorded as a note payable due in June 2007 with interest at
LIBOR + 0.275% (6.96% at December 31, 2000). The note was subsequently exchanged
for two notes with the same terms and conditions and assigned to other
subsidiaries of Edison International.

In January 2000, Edison Capital, a wholly-owned subsidiary of Edison
International, provided 150 million pounds sterling of subordinated financing to
Edison First Power Holdings I, an indirect, wholly-owned affiliate of Edison
Mission Energy. The coupon bearing interest sums are due January 2024 at a
coupon rate of 11.79%. On January 17, 2001, the subordinated financing was
repaid with interest and, therefore, the obligation is included in current
maturities of long-term obligations.

FINANCING OF THE HOMER CITY PLANT

In March 1999, Edison Mission Holdings Co., an indirect, wholly-owned
affiliate of Edison Mission Energy, closed a $1.1 billion financing in
connection with the acquisition of the Homer City plant. The financing consisted
of (1) an $800 million, 364-day term loan facility, (2) a $250 million,
five-year term loan facility and (3) a $50 million, five-year revolving credit
facility. The $800 million credit facility has since been repaid as described
below. These loans are structured on a limited-recourse basis in which the
lenders look primarily to the cash generated by the Homer City plant to repay
the debt and have taken a security interest in the Homer City plant assets. We
expect to use amounts available under the $250 million five-year term loan
facility to fund environmental capital improvements at the Homer City plant and
use amounts available under the $50 million five-year revolving credit facility
for general working capital purposes. As of December 31, 2000 and 1999, there
were no amounts outstanding under the $50 million five-year revolving credit
facility.

In May 1999, Edison Mission Holdings Co. completed an $830 million bond
financing. The financing consists of (1) $300 million, 8.137% Senior Secured
Bonds due 2019 and (2) $530 million, 8.734% Senior Secured Bonds due 2026. These
bonds are non-recourse to us apart from the Credit Support Guarantee and Debt
Service Reserve Guarantee entered into by us. The Credit Support

94

Guarantee requires us to guarantee the payment and performance of the
obligations of Edison Mission Holdings to the bond holders, banks and other
secured parties which financed the acquisition of the Homer City plant in an
aggregate amount not to exceed approximately $42 million. This guarantee is to
remain in place until December 31, 2001.

To satisfy the requirements under the Edison Mission Holdings Co. bond
financing to have a debt service reserve account balance in an amount equal to
six months' debt service projected to be due following the payment of a
distribution, Edison Mission Energy agreed to guarantee the payment and
performance of the obligations of Edison Mission Holdings, in the amount of
approximately $35 million, pursuant to a debt service reserve guarantee. In
addition, Edison Mission Energy provides a guarantee of Edison Mission Holdings'
obligations in the amount of $3 million to the lenders involved in the bank
financing. As a result of Edison Mission Energy's downgrade in January 2001,
Edison Mission Holdings is in the process of finalizing the arrangement of a
letter of credit of approximately $35 million to replace the bond debt service
reserve guarantee.

FINANCING OF THE FERRYBRIDGE AND FIDDLER'S FERRY PLANTS

In July 1999, Edison First Power Limited, an indirect, wholly-owned
affiliate of Edison Mission Energy, issued Edison First Power Bonds due 2019.
The bonds are guaranteed by us. The Edison First Power Bonds were issued to a
special purpose entity formed by Merrill Lynch International, which sold the
variable rate coupons portion of the bonds to another special purpose entity
that borrowed 830 million pounds sterling (approximately $1.2 billion as of
December 31, 2000) under a Term Loan Facility to finance the purchase. The Term
Loan Facility accrues interest at sterling LIBOR plus 1.50% to 1.90% and is
repaid in semi-annual installments over a 12-year period beginning
December 1999. As part of the financing of the Ferrybridge and Fiddler's Ferry
plants, we also entered into a 359 million pounds sterling (approximately
$537 million as of December 31, 2000) Coal and Capex Facility due January 2004
and July 2004, respectively, and a 20 million pounds sterling (approximately
$30 million as of December 31, 2000) working capital facility available through
September 2019. As of December 31, 2000, $28.7 million was outstanding under the
working capital facility.

Edison First Power has defaulted on its financing documents related to the
acquisition of the Fiddler's Ferry and Ferrybridge power plants. The financial
performance of these plants has not matched our expectations, largely due to
lower energy power prices resulting primarily from increased competition,
warmer-than-average weather and uncertainty surrounding the new electricity
trading arrangements. See "Management's Discussion and Analysis of Results of
Operations and Financial Condition--Market Risk Exposures--United Kingdom." As a
result, Edison First Power has decided to defer some environmental capital
expenditures originally planned to increase plant utilization and therefore is
currently in breach of milestone requirements for the implementation of the
capital expenditures program set forth in the financing documents relating to
the acquisition of these plants. In addition, due to this reduced financial
performance, Edison First Power's debt service coverage ratio during 2000
declined below the threshold set forth in the financing documents.

Edison First Power is currently in discussions with the relevant financing
parties to revise the required capital expenditure program, to waive (i) the
breach of the financial ratio covenant for 2000, (ii) a technical breach of
requirements for the provision of information that was delayed due to
uncertainty regarding capital expenditures, and (iii) other related technical
defaults. Edison First Power is in the process of requesting the necessary
waivers and consents to amendments from the financing parties. We cannot assure
you that these waivers and consents to amendments will be forthcoming. The
financing documents stipulate that a breach of the financial ratio covenant
constitutes an immediate event of default and, if the event of default is not
waived, the financing parties are entitled to enforce their security over Edison
First Power's assets, including the Fiddler's Ferry and Ferrybridge plants.
Despite the breaches under the financing documents, Edison First Power's debt
service coverage ratio

95

for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service
payments, Edison First Power utilized L37 million from its debt service reserve
to meet its debt service requirements in 2000.

In accordance with SFAS No. 121, "ACCOUNTING FOR THE IMPAIRMENT OF
LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED", we have evaluated
impairment of the Ferrybridge and Fiddler's Ferry power plants. The undiscounted
projected cash flow from these power plants exceeds the net book value at
December 31, 2000, and, accordingly, no impairment of these power plants is
permitted under SFAS No. 121. As a result of the change in the prices of power
in the U.K., we are considering the sale of Ferrybridge and Fiddler's Ferry
power plants. Management has not made a decision whether or not the sale of
these power plants will ultimately occur and, accordingly, these assets are not
classified as held for sale. However, if a decision to sell the Ferrybridge and
Fiddler's Ferry power plants were made, it is likely that the fair value of the
assets would be substantially below their book value at December 31, 2000. Our
net investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry
power plants and related debt was $918 million at December 31, 2000.

FINANCING OF THE ILLINOIS PLANTS

In December 1999, Edison Mission Midwest Holdings Co., an indirect,
wholly-owned affiliate of Edison Mission Energy, closed a $1.7 billion financing
in connection with the acquisition of the Illinois Plants. The financing
consisted of (1) an $840 million revolving credit facility due 2002, referred to
as Tranche A, (2) an $839 million revolving credit facility due 2004, referred
to as Tranche B, and (3) a $150 million of borrowing capacity available under a
working capital revolving facility, referred to as Tranche C, at LIBOR + 0.95%
due 2004. These credit facilities are structured on a non-recourse basis, in
which the debt is secured by a pledge of stock of specified subsidiaries. On
December 13, 2000, the commitment amount under Tranche A was increased from
$840 million to $911 million, and the commitment amount under Tranche B was
decreased from $839 million to $816 million. As of December 31, 2000, the
amounts borrowed in 1999 under Tranche A were paid. Under the working capital
revolving facility, Tranche C, $6.6 million of borrowing capacity was available
at December 31, 2000.

In February 2000, Edison Mission Midwest Holdings Co. issued $1.7 billion of
commercial paper under a commercial paper program and repaid a similar amount of
outstanding bank borrowings. At December 31, 2000, $803.9 million of commercial
paper was outstanding.

In December 1999, as part of the financing of the Illinois Plants, we also
issued $500 million floating rate notes due 2001 and borrowed $215 million under
our $500 million revolving credit facility that expires in 2001. During the
third quarter of 2000, the $500 million floating rate notes and the amount
borrowed under the revolving credit facility were repaid.

ANNUAL MATURITIES ON LONG-TERM DEBT

Annual maturities on long-term debt at December 31, 2000, for the next five
years, excluding capital leases (see Note 14) are summarized as follows:
2001--$1,767.6 million; 2002--$192.6 million; 2003--$326.5 million;
2004--$1,426.4 million; and 2005--$115 million. The current portion of Roosecote
debt is included in long-term debt, as proceeds from future borrowings will
exceed the current portion under the terms of the Term Loan and Guarantee
Facility at Roosecote.

RESTRICTED CASH

Several cash balances are restricted primarily to pay amounts required for
debt payments and letter of credit expenses. The total restricted cash in
Restricted cash and other assets was $121.0 million at December 31, 2000 and
$69.9 million at December 31, 1999. Debt service reserves classified in
Restricted cash and other assets (including reserves for interest on annual
lease payments) were $75.1 million at December 31, 2000 and $69.7 million at
December 31, 1999.

96

Collateral reserves classified in Restricted cash and other assets were
$37.2 million at December 31, 2000 as required by the Edison Mission Energy
Turbine Trust agreement entered into on December 4, 2000. This agreement is
discussed further in Note 14.

Each of our direct or indirect subsidiaries is organized as a legal entity
separate and apart from Edison Mission Energy and its other subsidiaries. Any
asset of any of those subsidiaries may not be available to satisfy our
obligations or any obligations of our other subsidiaries. However, unrestricted
cash or other assets which are available for distribution may, subject to
applicable law and the terms of financing arrangements of these parties, be
advanced, loaned, paid as dividends or otherwise distributed or contributed to
us or our affiliates.

FAIR VALUES OF FINANCIAL INSTRUMENTS

The following table summarizes the fair values for outstanding financial
instruments used for purposes other than trading by risk category and instrument
type:

DECEMBER 31,
---------------------------------------------
2000 1999
--------------------- ---------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- -------- ----------

INSTRUMENTS
Non-derivatives:
Long-term receivables................................ $ 267.6 $ 267.6 $ 7.8 $ 6.6
Long-term obligations................................ 5,334.8 5,231.9 7,439.3 7,430.4
Preferred securities subject to mandatory
redemption......................................... 326.8 326.8 358.8 359.8
Derivatives:
Interest rate swap/cap agreements.................... -- (40.8) -- (7.2)
Commodity price:
Forwards........................................... -- (107.5) -- --
Futures............................................ (2.9) (11.1) -- --
Options............................................ 0.6 1.8 3.5 3.5
Swaps.............................................. (46.6) 508.0 -- 70.8
Foreign currency forward exchange agreements......... -- (2.1) -- --

In assessing the fair value of our financial instruments, both derivative
and non-derivative, we use a variety of methods and assumptions that are based
on market conditions and risk existing at each balance sheet date. Quoted market
prices for the same or similar instruments are used for long-term receivables,
interest rate swap/cap agreements, long-term obligations and preferred
securities. Foreign currency forward exchange agreements are estimated by
obtaining quotes from the bank. The carrying amounts reported for cash
equivalents, commercial paper facilities and other short-term debt approximate
fair value due to their short maturities.

The fair value of the electricity rate swaps agreements (included under
commodity price-swaps) entered into by Ferrybridge and Fiddler's Ferry, First
Hydro and the Loy Yang B plants has been estimated by discounting the future
cash flows on the difference between the average aggregate contract price per MW
and a forecasted market price per MW, multiplied by the amount of MW sales
remaining under contract.

The fair value of the commodity price contracts considers quoted marked
prices, time value, volatility of the underlying commodities and other factors.

97

NOTE 8. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS

Our risk management policy allows for the use of derivative financial
instruments to limit financial exposure on its investments and to manage
exposure to fluctuations in interest rates, foreign exchange rates, oil and gas
prices and energy prices for both trading and non-trading purposes.

COMMODITY PRICE RISK MANAGEMENT

Energy trading and price risk management activities give rise to commodity
price risk, which represents the potential loss that can be caused by a change
in the market value of a particular commodity. Commodity price risks are
actively monitored to ensure compliance with the risk management policies of
Edison Mission Energy. Policies are in place which limit the amount of total net
exposure we may enter into at any point in time. Procedures exist which allow
for monitoring of all commitments and positions with daily reporting to senior
management. Edison Mission Energy performs a "value at risk" analysis in our
daily business to measure, monitor and control our overall market risk exposure.
The use of value at risk allows management to aggregate overall risk, compare
risk on a consistent basis and identify the drivers of the risk. Value at risk
measures the worst expected loss over a given time interval, under normal market
conditions, at a given confidence level. Given the inherent limitations of value
at risk and relying on a single risk measurement tool, we supplement this
approach with industry "best practice" techniques including the use of stress
testing and worst-case scenario analysis, as well as stop limits and
counterparty credit exposure limits.

INTEREST RATE RISK MANAGEMENT

Interest rate changes affect the cost of capital needed to finance the
construction and operation of our projects. We have mitigated the risk of
interest rate fluctuations by arranging for fixed rate financing or variable
rate financing with interest rate swaps or other hedging mechanisms for a number
of our project financings. We have entered into several interest rate swap
agreements under which the maturity date of the swaps occurs prior to the final
maturity of the underlying debt.

Under the fixed to variable swap agreements, the fixed interest rate
payments are at a weighted average rate of 5.65% at December 31, 2000 and 1999.
Variable rate payments are based on six month LIBOR capped at 9%. The weighted
average LIBOR rate applicable to these agreements was 5.605% and 6.22% at
December 31, 2000 and 1999, respectively. Under the variable to fixed swap
agreements, we will pay counterparties interest at a weighted average fixed rate
of 7.59% and 7.6% at December 31, 2000 and 1999, respectively. Counterparties
will pay us interest at a weighted average variable rate of 6.43% and 5.03% at
December 31, 2000 and 1999, respectively. The weighted average variable interest
rates are based on LIBOR or equivalent interest rate benchmarks for foreign
denominated interest rate swap agreements.

CREDIT RISK

Our financial instruments and power sales contracts involve elements of
credit risk. Credit risk relates to the risk of loss that we would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The counterparties to financial instruments and
contracts consist of a number of major financial institutions and domestic and
foreign utilities. Our attempts to mitigate this risk by entering into contracts
with counterparties that have a strong capacity to meet their contractual
obligations and by monitoring the credit quality of these financial institutions
and utilities. One of our customers, Exelon Generation Company, accounted for
33% of our revenues during 2000. Any failure by Exelon Generation Company to
make payments under the power purchase agreements could adversely affect our
results of operations. The currency crisis in Indonesia has raised concerns over
the ability of the state owned utility to meet its obligations under the current
power sales contract with our Paiton project as discussed further in Note 13. In
addition, we enter into contracts

98

whereby the structure of the contracts minimizes our credit exposure.
Accordingly, we, with the exception of our contract with Exelon Generation
Company and the power sale contract with our Paiton project, do not anticipate
any material impact to our financial position or results of operations as a
result of counterparty nonperformance.

The electric power generated by some of our investments in domestic
operating projects, excluding the Homer City plant and the Illinois Plants, is
sold to electric utilities under long-term, typically with terms of 15 to
30-years, power purchase agreements and is expected to result in consistent cash
flow under a wide range of economic and operating circumstances. To accomplish
this, we structure our long-term contracts so that fluctuations in fuel costs
will produce similar fluctuations in electric and/or steam revenues and enter
into long-term fuel supply and transportation agreements. In addition, we have
plants located in different geographic areas in order to mitigate the effects of
regional markets, economic downturns or unusual weather conditions.

FOREIGN EXCHANGE RATE RISK

Fluctuations in foreign currency exchange rates can affect, on a United
States dollar equivalent basis, the amount of our equity contributions to, and
distributions from, our international projects. As we continue to expand into
foreign markets, fluctuations in foreign currency exchange rates can be expected
to have a greater impact on our results of operations in the future. At times,
we have hedged a portion of our current exposure to fluctuations in foreign
exchange rates through financial derivatives, offsetting obligations denominated
in foreign currencies, and indexing underlying project agreements to United
States dollars or other indices reasonably expected to correlate with foreign
exchange movements. In addition, we have used statistical forecasting techniques
to help assess foreign exchange risk and the probabilities of various outcomes.
We cannot assure you, however, that fluctuations in exchange rates will be fully
offset by hedges or that currency movements and the relationship between certain
macro economic variables will behave in a manner that is consistent with
historical or forecasted relationships.

At December 31, 2000, we had outstanding foreign currency forward exchange
contracts entered into in the ordinary course of business to protect ourselves
from adverse currency rate fluctuations on anticipated foreign currency
commitments with varying maturities ranging from January 2001 to July 2002. The
periods of the forward exchange contracts correspond to the periods of the
hedged transactions.

Edison Mission Energy has the following commodity, interest rate and foreign
currency hedges:

DECEMBER 31,
-----------------------------------------------
2000 1999
---------------------- ----------------------
NOTIONAL CONTRACT NOTIONAL CONTRACT
AMOUNT EXPIRES AMOUNT EXPIRES
-------- ----------- -------- -----------

Derivative commodity contracts:
Forwards........................................ $ 488.6 2001 - 2003 $ -- --
Futures......................................... (69.8) 2001 -- --
Options......................................... 3.5 2001 47.3 2001
Swaps........................................... 1,747.8 2001 - 2016 1,802.7 2000 - 2016

Interest rate swaps:
Fixed to variable............................... 100.0 2002 100.0 2002
Variable to fixed............................... 906.1 2001 - 2009 1,066.3 2001 - 2009
Interest rate caps................................ 583.7 2005 - 2010 626.4 2005

Foreign Currency Forward Contracts................ 90.7 2001 - 2002 -- --

99

ENERGY TRADING

On September 1, 2000, we acquired the trading operations of Citizens Power
LLC. As a result of this acquisition, we have expanded our trading operations
beyond the traditional marketing of our electric power. Our energy trading and
price risk management activities give rise to market risk, which represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Market risks are actively monitored to ensure compliance
with the risk management policies of Edison Mission Energy. Policies are in
place which limit the amount of total net exposure we may enter into at any
point in time. Procedures exist which allow for monitoring of all commitments
and positions with daily reporting to senior management. We perform a "value at
risk" analysis in our daily business to measure, monitor and control our overall
market risk exposure. The use of value at risk allows management to aggregate
overall risk, compare risk on a consistent basis and identify the reasons for
the risk. Value at risk measures the worst expected loss over a given time
interval, under normal market conditions, at a given confidence level. Given the
inherent limitations of value at risk and relying on a single risk measurement
tool, we supplement this approach with industry "best practice" techniques
including the use of stress testing and worst-case scenario analysis, as well as
stop limits and counterparty credit exposure limits.

The fair value of the financial instruments, including forwards, futures,
options and swaps, related to trading activities as of December 31, 2000, which
include energy commodities, and the average fair value of those instruments held
during the period from inception (September 1, 2000) to December 31, 2000 are
set forth below:

AVERAGE FAIR VALUE
FAIR VALUE AS OF FOR THE PERIOD ENDED
DECEMBER 31, 2000 DECEMBER 31, 2000
---------------------- -----------------------
ASSETS LIABILITIES ASSETS LIABILITIES
-------- ----------- --------- -----------

Forward contracts........................ $302.0 $282.1 $154.0 $147.2
Futures contracts........................ 0.1 0.1 0.1 0.1
Option contracts......................... 1.4 3.6 3.2 1.7
Swap agreements.......................... 2.9 4.3 1.8 2.3
------ ------ ------ ------
Total.................................... $306.4 $290.1 $159.1 $151.3
====== ====== ====== ======

The approximate gross contract or notional amounts of financial instruments
as of December 31, 2000 are as follows:

DECEMBER 31, 2000
----------------------
ASSETS LIABILITIES
-------- -----------

Forward contracts......................................... $433.4 $420.1
Futures contracts......................................... 0.4 0.1
Option contracts.......................................... 1.6 (0.1)
Swap agreements........................................... 39.6 64.0

100

The net realized and change in unrealized gains or losses arising from
trading activities for the period from inception (September 1, 2000) to
December 31, 2000 are as follows:

PERIOD ENDED
DECEMBER 31, 2000
------------------

Forward contracts........................................... $68.4
Futures contracts........................................... 0.4
Option contracts............................................ (1.4)
Swap agreements............................................. (5.2)
-----
Total....................................................... $62.2
=====

The change in unrealized gain from trading and price risk management
activities included in the above amounts was $11.7 million for the period ended
December 31, 2000.

NOTE 9. PREFERRED SECURITIES

COMPANY-OBLIGATED MANDATORILY REDEEMABLE SECURITY OF PARTNERSHIP HOLDING
SOLELY PARENT DEBENTURES. In November 1994, Mission Capital, L.P., a limited
partnership of which Edison Mission Energy is the sole general partner, issued
3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a
price of $25 per security. These securities are redeemable at the option of
Mission Capital, in whole or in part, beginning November 1999, with mandatory
redemption in 2024 at a redemption price of $25 per security, plus accrued and
unpaid distributions. No securities have been redeemed as of December 31, 2000.
During August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly
Income Preferred Securities, Series B at a price of $25 per security. These
securities are redeemable at the option of Mission Capital, in whole or in part,
beginning August 2000, with mandatory redemption in 2025 at a redemption price
of $25 per security, plus accrued and unpaid distributions. No securities were
redeemed in 2000. We issued a guarantee in favor of the holders of the preferred
securities, which guarantees the payments of distributions declared on the
preferred securities, payments upon a liquidation of Mission Capital and
payments on redemption with respect to any preferred securities called for
redemption by Mission Capital. So long as any preferred securities remain
outstanding, we will not be able to declare or pay, directly or indirectly, any
dividend on, or purchase, acquire or make a distribution or liquidation payment
with respect to, any of its common stock if at such time (i) we shall be in
default with respect to its payment obligations under the guarantee, (ii) there
shall have occurred any event of default under the subordinated indenture, or
(iii) we shall have given notice of its selection of an extended interest
payment period as provided in the indenture and such period, or any extension
thereof, shall be continuing.

NOT SUBJECT TO MANDATORY REDEMPTION. In connection with the 40% acquisition
of Contact Energy in May 1999, Edison Mission Energy Global Management, Inc., an
indirect wholly-owned affiliate of Edison Mission Energy, issued $120 million of
Flexible Money Market Cumulative Preferred Stock. The stock issuance consisted
of (1) 600 Series A shares and (2) 600 Series B shares, both with liquidation
preference of $100,000 per share and a dividend rate of 5.74% until May 2004.

On December 20, 2000, Edison Mission Energy Global Management, Inc. was
dissolved and its $120 million of Flexible Money Market Cumulative Preferred
Stock was redeemed. The 600 Series A and 600 Series B shares were redeemed at
their liquidation preference of $100,000 per share, along with an additional
liquidation premium of $3,785 per share, and all unpaid dividends. The
redemption of Edison Mission Energy Global Management's preferred shares was
funded by return of capital from Edison Mission Energy Taupo Limited. Edison
Mission Energy Taupo Limited sold its entire interest in Contact Energy Limited
to EME Pacific Holdings, an indirect, wholly-owned subsidiary of Edison Mission
Energy, to permit Edison Mission Energy Taupo to make the necessary distribution
to Edison Mission Energy Global Management. In connection with the transfer of
ownership of Contact, Edison

101

Mission Energy entered into a further Deed of Covenant in favor of the
institutional subscriber of 160 million New Zealand dollars of the preferred
stock issued by Edison Mission Energy Taupo in June 1999, discussed below. This
further Deed of Covenant required Edison Mission Energy to compensate the
institutional preferred stock subscriber in the event that a private binding
ruling issued to it by the New Zealand Inland Revenue Department ceases to apply
as a direct result of the transfer. The amount of any compensation that may
become payable by Edison Mission Energy under the further Deed of Covenant is
limited to that necessary to keep the preferred stock subscriber in the same
position that it would have been had the private binding ruling continued to
apply.

The support agreement between Edison Mission Energy and Edison Mission
Energy Global Management, which required Edison Mission Energy to make certain
capital contributions to Edison Mission Energy Global Management, was terminated
immediately following the dissolution of Edison Mission Energy Global Management
and the redemption of the preferred shares as described above.

SUBJECT TO MANDATORY REDEMPTION. During June 1999, Edison Mission Energy
Taupo Limited, a New Zealand corporation, an indirect, wholly-owned affiliate of
Edison Mission Energy, issued $84 million of Class A Redeemable Preferred Shares
(16,000 shares at a price of 10,000 New Zealand dollars per share). The dividend
rate ranges from 6.19% to 6.86%. The shares are redeemable in June 2003 at
10,000 New Zealand dollars per share. If an event of default occurs at any time
without prejudice to any other remedies which the redeemable preferred share
subscriber may have, the redeemable preferred share subscriber may, by notice to
the issuer, require redemption of, and the issuer must redeem, the redeemable
preferred shares on the date specified in that notice. Each dividend will rank
for payment in priority to the rights in respect of dividends and the rights, if
any, in respect of interest on arrears thereof of all holders of other classes
of shares of ours other than redeemable preferred shares issued by us. Edison
Mission Energy Taupo shall not pay or make, or allow to be paid or made, any
distribution, other than dividends or the redemption amount or similar amounts
payable in respect of the retail shares, if an event of default or potential
event of default has occurred, which remains unremedied, unless the redeemable
preferred share subscriber has given its prior written consent which may be
given on such conditions as the redeemable preferred share subscriber deems
reasonable.

From July through November 1999, Edison Mission Energy Taupo issued
$125 million of retail redeemable preferred shares (240 million shares at a
price of one New Zealand dollar per share). The dividend rate ranges from 5.00%
to 6.37%. The shares are redeemable at one New Zealand dollar per share in
June 2001 (64 million), June 2002 (43 million), and June 2003 (133 million).
Edison Contact Finance is a special purpose company established to raise funds
by the issuance of retail redeemable preferred shares to assist Edison Mission
Energy Taupo to refinance in part the funding used by it for its acquisition of
40% of the ordinary shares in Contact Energy. Edison Contact Finance and Edison
Mission Energy Taupo are parties to a subscription and indemnity agreement,
which contains the terms of subscription by Edison Contact Finance for Edison
Mission Energy Taupo retail shares. Edison Contact Finance will subscribe for
Edison Mission Energy Taupo retail shares as and when Edison Contact Finance
issues retail shares. The principal terms of issuance of Edison Mission Energy
Taupo retail shares are set out in the Subscription Agreement and are
substantially the same as the terms of issue of the Class A Redeemable Preferred
shares. On an event of default under the terms of issue of the retail shares,
early redemption of the shares may be required by the holders of the shares by
special resolution, by 15% of the holders of shares, in instances of
non-payment, by written notice to Edison Contact Finance, or Edison Contact
Finance by written notice to the holders of shares. If only part of the retail
shares are redeemed earlier than their scheduled redemption date, in some cases,
a minimum number of retail shares must be redeemed, and unless the redemption
occurs on a dividend payment date, Edison Mission Energy Taupo must redeem all
Edison Mission Energy Taupo shares in any class, with the same scheduled
redemption date and fixed dividend rate. Edison Contact Finance will redeem the
same shares of a class corresponding to the redeemed Edison Mission Energy Taupo
shares. Not all

102

classes of shares need be affected by a partial redemption of Edison Mission
Energy Taupo retail shares. Redemption of retail shares can be accelerated if
Edison Mission Energy Taupo exercises its option under the terms of the
subscription and indemnity agreement to redeem any of the Edison Mission Energy
Taupo retail shares at its discretion. Edison Contact Finance will pay fully
imputed dividends, in arrears, to the holder of each retail share on the record
date. Edison Contact Finance may change the annual dividend rates, which will
attach to the shares at any time before acceptance by Edison Contact Finance of
an application for those shares.

In connection with the preferred shares issued by Edison Mission Energy
Taupo Limited to partially finance the acquisition of the 40% interest in
Contact Energy, Edison Mission Energy provided a guaranty of Edison Mission
Energy Taupo Limited's obligation to pay a minimum level of non-cumulative
dividends on the preferred shares through June 30, 2002, including
NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending
June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts
required to ensure that Edison Misison Energy Taupo Limited will satisfy two
financial ratio covenants on specified dates. The first financial ratio, called
a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is
based on historical and projected dividends received from Contact Energy and the
dividends payable to preferred shareholders. The second financial ratio, called
a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based
on the fair value of our Contact Energy shares and the outstanding preferred
shares. If, however, Edison Mission Energy's senior unsecured credit rating by
Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be
called to perform on its guaranty of Edison Mission Energy Taupo Limited's
financial covenants before the specified calculation dates. Based on the fair
value of our ownership in Contact Energy at March 20, 2001, had Edison Mission
Energy been required to perform on its guarantee of the debt to valuation ratio
as of that date, Edison Mission Energy's obligation would have been
approximately $19 million.

NOTE 10. INCOME TAXES

CURRENT AND DEFERRED TAXES

Income tax expense includes the current tax liability from operations and
the change in deferred income taxes during the year. The components of the net
accumulated deferred income tax liability were:

DECEMBER 31,
-------------------
2000 1999
-------- --------

DEFERRED TAX ASSETS
Items deductible for book not currently deductible for
tax.................................................. $ 132.4 $ 178.9
Loss carryforwards..................................... 97.0 68.5
Deferred income........................................ 182.5 185.3
Dividends in excess of equity earnings................. 4.9 6.3
Price risk management.................................. 38.5 --
-------- --------
Total................................................ $ 455.3 $ 439.0
-------- --------
DEFERRED TAX LIABILITIES
Basis differences...................................... $2,047.7 $1,939.1
Tax credits, net....................................... 19.1 19.5
Other.................................................. -- 0.9
-------- --------
Total................................................ 2,066.8 1,959.5
-------- --------
Deferred taxes and tax credits, net...................... $1,611.5 $1,520.5
======== ========

103

Loss carryforwards, primarily Australian, total $281 million and
$232 million at December 31, 2000 and 1999, respectively, with $11 million
expiring in 2005. Federal capital loss carryforwards total $25 million expiring
in 2005. State capital loss carryforwards total $309 million and $107 million at
December 31, 2000 and 1999, respectively, with no expiration date. Loss
carryforwards total approximately $20 million for Pennsylvania and $63 million
for Illinois at December 31, 2000 with various expiration dates.

The components of income (loss) before income taxes are as follows:

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

U.S................................................. $ 2.1 $(74.7) $ 32.8
Foreign............................................. 178.0 178.4 169.8
------ ------ ------
Total............................................. $180.1 $103.7 $202.6
====== ====== ======

United States income taxes have not been provided on unrepatriated foreign
earnings in the amounts of $487 million and $372 million at December 31, 2000
and 1999, respectively. In addition, foreign income taxes have not been provided
on unrepatriated foreign earnings from a different foreign jurisdiction in the
amount of $151 million and $136 million at December 31, 2000 and 1999,
respectively.

The provision (benefit) for income taxes is comprised of the following:

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

CURRENT
Federal.......................................... $(206.5) $ (75.0) $(10.5)
State............................................ (19.8) (0.5) (19.0)
Foreign.......................................... 58.8 (34.0) 14.8
------- ------- ------
Total current.................................. $(167.5) $(109.5) $(14.7)
======= ======= ======
DEFERRED
Federal.......................................... $ 213.5 $ 37.4 $ 28.1
State............................................ 37.9 10.1 25.3
Foreign.......................................... (11.4) 21.6 31.7
------- ------- ------
Total deferred................................. 240.0 69.1 85.1
------- ------- ------
Provision (benefit) for income taxes............... $ 72.5 $ (40.4) $ 70.4
======= ======= ======

104

The components of the deferred tax provision, which arise from tax credits
and timing differences between financial and tax reporting, are presented below:

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Basis differences and tax credit amortization............... $266.3 $157.4 $116.5
Loss carryforwards.......................................... (28.5) (25.5) (32.6)
Deferred income............................................. 2.8 2.6 3.7
State tax deduction......................................... (5.4) (6.0) 4.3
Items deductible for book and tax in different accounting
periods................................................... 45.4 (52.9) (17.4)
Elimination of book income.................................. -- -- 6.9
Price risk management....................................... (38.5) -- --
Other....................................................... (2.1) (6.5) 3.7
------ ------ ------
Total deferred provision.................................. $240.0 $ 69.1 $ 85.1
====== ====== ======

Variations from the 35% federal statutory rate are as follows:

YEARS ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
-------- -------- --------

Expected provision for federal income taxes................. $ 63.0 $ 36.3 $ 70.9
Increase (decrease) in the provision for taxes resulting
from:
State tax--net of federal deduction....................... 11.7 3.6 4.1
Dividends received deduction.............................. (11.0) (2.2) (4.0)
Amortization of tax credits............................... (0.4) (1.1) (6.5)
Benefit due to foreign tax rate reduction................. -- (5.9) (11.0)
Taxes payable under anti-deferral regimes................. 6.0 7.0 6.7
Taxes on foreign operations at different rates............ 7.6 5.9 8.4
Book and tax basis differences............................ (8.2) (7.8) 2.3
Capital loss not previously recognized.................... -- (29.0) --
Non-utilization of foreign losses......................... 16.0 6.9 --
Permanent reinvestment of earnings of foreign affiliates
located in different foreign tax jurisdiction........... (12.2) (40.3) --
Refund of Advance Corporation Tax......................... -- (15.2) --
Other..................................................... -- 1.4 (0.5)
------ ------ ------
Total provision (benefit) for income taxes................ $ 72.5 $(40.4) $ 70.4
====== ====== ======
Effective tax rate........................................ 40.3% (39.0)% 34.8%
====== ====== ======

We are, and may in the future be, under examination by tax authorities in
varying tax jurisdictions with respect to positions we take in connection with
the filing of our tax returns. Matters raised upon audit may involve substantial
amounts, which, if resolved unfavorably, an event not currently anticipated,
could possibly be material. However, in our opinion, it is unlikely that the
resolution of any such matters will have a material adverse effect upon our
financial condition or results of operations.

NOTE 11. EMPLOYEE BENEFIT PLANS

United States employees of Edison Mission Energy are eligible for various
benefit plans of Edison International. Several of our Australian, United Kingdom
and Spanish subsidiaries also participate in their own respective defined
benefit pension plans.

105

PENSION PLANS

Noncontributory, defined benefit pension plans cover employees who fulfill
minimum service requirements. In April 1999, Edison International adopted a cash
balance feature for its pension plan.

In 1999, we acquired the Homer City plant and the Illinois Plants. The
acquisitions are discussed further in Note 4. The obligations and expenses for
employees at these plants are included below.

In 1999, Ferrybridge and Fiddler's Ferry employees were included as part of
the PowerGen UK Group defined benefit pension plan, Electricity Supply Pension
Scheme, administered by a trustee, which provides pension and other related
benefits. Contributions to the plan are based on a percentage of compensation
for the covered employees and are assessed by a qualified actuary. As a result
of Ferrybridge and Fiddler's Ferry not having a plan separate from the PowerGen
UK Group, amounts were not readily available to provide the information included
in the tables below for 1999. Pension expense recorded by Ferrybridge and
Fiddler's Ferry totaled $1.0 million for the period from July 1999 through
December 31, 1999. During the first quarter of 2000, Ferrybridge and Fiddler's
Ferry employees joined a separate defined benefit pension plan utilized by First
Hydro employees. All amounts for the year 2000 are included in the table below.

Information on plan assets and benefit obligations is shown below:

YEARS ENDED DECEMBER 31,
------------------------------------------------------
2000 1999 2000 1999
-------- -------- ---------- ----------
U.S. PLANS NON U.S. PLANS

Change in Benefit Obligation
Benefit obligation at beginning of year.......... $ 37.5 $ 26.1 $ 119.2 $ 36.7
Service cost..................................... 10.2 2.3 3.5 2.0
Interest cost.................................... 2.7 2.1 6.6 1.9
Plan amendment................................... -- (3.8) -- --
Acquisition...................................... -- 10.6 -- --
Actuarial loss (gain)............................ 0.4 0.4 (4.7) 5.8
Plan participants' contribution.................. -- -- 2.6 0.8
Benefits paid.................................... (1.3) (0.2) (1.0) (0.6)
------ ------ ---------- ----------
Benefit obligation at end of year.............. $ 49.5 $ 37.5 $ 126.2 $ 46.6
====== ====== ========== ==========

Change in Plan Assets
Fair value of plan assets at beginning of year... $ 28.6 $ 20.9 $ 118.0 $ 34.8
Actual return on plan assets..................... (0.3) 5.8 (2.7) 8.3
Employer contributions........................... 9.4 2.1 7.6 2.5
Plan participants' contribution.................. -- -- 0.9 0.2
Benefits paid.................................... (1.3) (0.2) (0.8) (0.4)
------ ------ ---------- ----------
Fair value of plan assets at end of year....... $ 36.4 $ 28.6 $ 123.0 $ 45.4
====== ====== ========== ==========

Funded Status...................................... $(13.1) $ (8.9) $ (3.2) $ (1.2)
Unrecognized net loss (gain)....................... 0.2 (3.4) 5.9 0.7
Unrecognized net obligation........................ 0.9 1.1 (0.1) --
Unrecognized prior service cost.................... (2.8) (3.1) 0.5 0.4
------ ------ ---------- ----------
Pension asset (liability).......................... $(14.8) $(14.3) $ 3.1 $ (0.1)
====== ====== ========== ==========

Discount rate...................................... 7.25% 7.75% 4.0 - 6.0% 4.5 - 6.0%
Rate of compensation increase...................... 5.00% 5.00% 3.75 - 4.5% 3.75 - 4.5%
Expected return on plan assets..................... 8.50% 7.50% 5.75 - 9.0% 6.5 - 9.0%

106

Components of pension expense were:

YEARS ENDED DECEMBER 31,
---------------------------------------------------------------
2000 1999 1998 2000 1999 1998
-------- -------- -------- -------- -------- --------
U.S. PLANS NON U.S. PLANS

Service cost........................... $10.2 $2.3 $2.4 $3.4 $1.5 $1.8
Interest cost.......................... 2.7 2.1 1.4 6.7 1.9 1.9
Expected return on plan assets......... (2.7) (1.7) (1.3) (7.2) (2.1) (3.4)
Net amortization and deferral.......... (0.4) -- 0.2 -- 0.1 1.3
----- ---- ---- ---- ---- ----
Total pension expense.................. $ 9.8 $2.7 $2.7 $2.9 $1.4 $1.6
===== ==== ==== ==== ==== ====

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

Most United States employees retiring at or after age 55 with at least
10 years of service are eligible for postretirement health and dental care, life
insurance and other benefits.

In 1999, we acquired the Homer City plant and the Illinois Plants. The
acquisitions are discussed further in Note 4. The obligations and expenses for
employees at these plants are included below.

Information on plan assets and benefit obligations is shown below:

YEARS ENDED
DECEMBER 31,
-------------------
2000 1999
-------- --------

Change in Benefit Obligation
Benefit obligation at beginning of year.................. $ 77.3 $ 14.9
Service cost............................................. 5.4 1.6
Interest cost............................................ 7.6 1.3
Plan amendment........................................... -- (4.1)
Acquisition.............................................. -- 80.7
Actuarial loss (gain).................................... 30.0 (17.0)
Benefits paid............................................ (0.2) (0.1)
------- ------
Benefit obligation at end of year........................ $ 120.1 $ 77.3
======= ======

Change in Plan Assets
Fair value of plant assets at beginning of year.......... $ -- $ --
Employer contributions................................... 0.2 0.1
Benefits paid............................................ (0.2) (0.1)
------- ------
Fair value of plan assets at end of year............... $ -- $ --
======= ======

Funded Status.............................................. $(120.1) $(77.3)
Unrecognized net loss (gain)............................... 14.5 (15.5)
Unrecognized transition obligation......................... -- --
Unrecognized prior service cost............................ (1.9) (2.1)
------- ------
Recorded liability......................................... $(107.5) $(94.9)
======= ======
Discount rate.............................................. 7.50% 8.0%
Expected return on plan assets............................. 8.20% 7.5%

107

The components of postretirement benefits other than pensions expense were:

YEARS ENDED
DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Service cost............................................. $ 5.4 $1.6 $1.4
Interest cost............................................ 7.6 1.3 0.7
Net amortization......................................... (0.2) 0.1 0.2
----- ---- ----
Net expense.............................................. $12.8 $3.0 $2.3
===== ==== ====

The assumed rate of future increases in the per-capita cost of health care
benefits is 11% for 2001, gradually decreasing to 5% for 2008 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 2000, by $31.4 million
and annual aggregate service and interest costs by $3.5 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of December 31, 2000, by $23.7 million and annual
aggregate service and interest costs by $2.6 million.

EMPLOYEE STOCK PLANS

A 401(k) plan is maintained to supplement eligible United States employees'
retirement income. The plan received contributions from us of $5.3 million in
2000, $2.9 million in 1999 and $0.8 million in 1998.

Doga employees are included in a separate government scheme, Pension Plan of
Social Security Institution. The plan is administered by the officers of the
Turkish Government. Contributions to the plan are based on a percentage of
compensation for the covered employees and are assessed by the Ministry of Labor
and Social Security. The plan is substantially funded at the end of each month.
Pension expense recorded by Doga was $114 thousand in 2000 and $12 thousand in
1999.

We also sponsor a defined contribution plan for specified United Kingdom
subsidiaries. Annual contributions are based on ten percent of covered
employees' salaries. Contribution expense for the subsidiaries totaled
approximately $0.5 million, $0.4 million and $0.5 million in 2000, 1999 and
1998, respectively.

NOTE 12. STOCK COMPENSATION PLANS

Under the Edison International Equity Compensation Plan, shares of Edison
International common stock were reserved for potential issuance to key Edison
Mission Energy employees in various forms, including the exercise of stock
options. In May 2000, Edison International adopted an additional plan, the 2000
Equity Plan. Under these programs, there are currently outstanding to officers
of Edison Mission Energy, options on 3,353,371 shares of Edison International
Common Stock of which 2,550,660, 154,695 and 83,000 were granted in 2000, 1999
and 1998, respectively.

Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. Edison International stock options
include a dividend equivalent feature. Generally, for options issued before
1994, amounts equal to dividends accrue on the options at the same time and at
the same rate as would be payable on the number of shares of Edison
International common stock covered by the options. The amounts accumulate
without interest. For Edison International stock options issued after 1993,
dividend equivalents are subject to reduction unless certain shareholder return
performance criteria are met. Beginning with the 1999 Edison International stock
option awards, only some stock options include a dividend equivalent feature.
The liability and associated expense is accrued each quarter for the dividend
equivalents for each option year. At the end of the performance measurement
period, the expense and related liability is adjusted accordingly. Upon
exercise, the dividends are paid out and the associated liability is reduced on
Edison Mission Energy Consolidated Balance Sheet. The 2000 stock option awards
did not include dividend equivalents. Future stock option awards are not
expected to include dividend equivalents.

108

A portion of the executive long-term incentives for 2000 was awarded in the
form of performance shares. The performance shares were restructured as
retention incentives in December 2000, which will pay as a combination of Edison
International common stock and cash if the executive remains employed at the end
of the performance period. No special stock options may be exercised before five
years have passed unless the stock price appreciates to $25 (based on the
average of 20 consecutive trading day closing prices). Performance shares may
still be awarded in 2001 and 2002.

All stock options have a 10-year term. Options issued after 1997 generally
vest in 25 percent annual installments over a four-year period, although the
vesting period for the May 2000 grants does not begin until May 2001. Stock
options issued prior to 1998 had a three-year vesting period with one-third of
the total award vesting after each of the first three years of the award term.
If an option holder retires, dies or is permanently and totally disabled
(qualifying event) during the vesting period, the unvested options will vest on
a pro rata basis. The performance shares values are accrued ratably over a
three-year performance period.

We measure compensation expense related to stock-based compensation by the
intrinsic value method. Compensation expense recorded under the stock
compensation program was $0.7 million for 2000, $0.4 million for 1999 and
$0.5 million for 1998.

The weighted-average fair value of options granted during 2000, 1999 and
1998 was $5.63 per share option, $6.45 per share option and $6.33 per share
option, respectively. The weighted-average remaining life of options outstanding
was 8 years as of December 31, 2000, and 7 years as of December 31, 1999 and
1998.

The fair value for each option granted during 2000, 1999 and 1998,
reflecting the basis for the pro forma disclosures, was determined on the date
of grant using the Black-Scholes option-pricing model.

The following assumptions were used in determining fair value through the
model:

2000 1999 1998
------------ -------- --------

Expected life............................. 8 years 7 years 7 years
Risk-free interest rate................... 4.7% to 6.0% 5.5% 5.6%
Expected volatility....................... 17% to 46% 18% 17%

The recognition of dividend equivalents results in no dividends assumed for
purposes of fair-value determination. Stock-based compensation expense under the
"fair-value" method of accounting prescribed by SFAS No. 123 "Stock-Based
Compensation" would have resulted in pro forma net income of $123.8 million,
$131.4 million and $132.3 million in 2000, 1999 and 1998, respectively.

109

A summary of the status of Edison International's stock options granted to
Edison Mission Energy employees is as follows:

SHARE WEIGHTED
OPTIONS EXERCISE PRICE EXERCISE PRICE
--------- --------------- --------------

Outstanding, December 31, 1997....... 320,590 $14.56 - $24.44 $19.49
Granted.............................. 83,000 $27.25 - $29.34 $27.31
Forfeited............................ (1,200) $17.63 - $19.75 $19.04
Exercised............................ (50,018) $14.56 - $23.28 $18.44
---------
Outstanding, December 31, 1998....... 352,372 $14.56 - $24.44 $21.51
Granted.............................. 154,695 $25.31 - $28.13 $27.84
Forfeited............................ (1,229) $19.75 - $27.25 $25.65
Exercised............................ (26,767) $14.56 - $19.85 $18.81
---------
Outstanding, December 31, 1999....... 479,071 $14.56 - $29.34 $23.84
Granted.............................. 2,550,660 $20.06 - $28.13 $21.84
Transferred to Edison Mission Energy
from Edison International.......... 514,750 $14.56 - $28.13 $23.68
Forfeited............................ (147,518) $18.75 - $28.13 $24.58
Exercised............................ (43,592) $14.56 - $28.13 $19.01
---------
Outstanding, December 31, 2000....... 3,353,371 $14.56 - $29.34 $22.31
=========

PHANTOM STOCK OPTIONS

Edison Mission Energy, as a part of the Edison International long-term
incentive compensation program, issued phantom stock option performance awards
to key employees commencing in 1994. Each phantom stock option could be
exercised to realize any appreciation in the value of one hypothetical share of
Edison Mission Energy stock over its exercise price. Compensation expense was
recognized during the period that the employee had the right to receive this
appreciation. Exercise prices for our phantom stock were escalated on an
annually compounded basis over the grant price by 9%. The value of the phantom
stock was recalculated annually as determined by a formula linked to the value
of its portfolio of investments less general and administrative costs. The
options had a 10-year term with one-third of the total award vesting in each of
the first three years of the award term, for all awards prior to 1998. For
options awarded in 1998 and 1999, one-fourth of the total award vested in each
of the first four years of the award term.

Compensation expense recorded with respect to phantom stock options was
$4.1 million (before the $60 million adjustment referred to below),
$136.3 million and $39 million in 2000, 1999 and 1998, respectively.

In June 2000, the board of directors of Edison International approved an
exchange offer to the holders of outstanding phantom options which was
subsequently accepted by all holders of these options. The exchange offer was
principally for cash, with a portion exchanged for stock equivalent units
relating to Edison International common stock. The number of stock equivalent
units was determined on the basis of $20.50 per share, and the stock equivalent
units accrue and will receive dividend equivalents. Participants were required
to elect to cash their vested stock equivalent units on either the first or
third anniversary of the exchange offer date (August 2000) for an amount equal
to the daily average of Edison International common stock (for 20 trading days
preceding the elected payment date). Some participants have elected to defer
payment of their cash and stock equivalent units. Since all the outstanding
phantom options have been terminated, there will be no future exercises of the
phantom options.

110

Due to the lower valuation of the exchange offer, compared to the values
previously accrued, the liability for accrued incentive compensation was reduced
by approximately $60 million in the third quarter of 2000.

NOTE 13. COMMITMENTS AND CONTINGENCIES

FIRM COMMITMENT FOR ASSET PURCHASE

PROJECTS LOCAL CURRENCY U.S. ($ IN MILLIONS)
- -------- ----------------------- --------------------

Italian Wind Projects(i)............... 36 billion Italian Lira $17

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

(i) The Italian Wind Projects are a series of power projects that are in
operation or under development in Italy. A wholly-owned subsidiary of
Edison Mission Energy owns a 50% interest. Purchase payments will continue
through 2002, depending on the number of projects that are ultimately
developed.

FIRM COMMITMENTS TO CONTRIBUTE PROJECT EQUITY

PROJECTS LOCAL CURRENCY U.S. ($ IN MILLIONS)
- -------- ---------------------- --------------------

Italian Wind Projects(i)................ 6 billion Italian Lira $3

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

(i) The Italian Wind Projects are a series of power projects that are in
operation or under development in Italy. A wholly-owned subsidiary of
Edison Mission Energy owns a 50% interest. Equity will be contributed
depending on the number of projects that are ultimately developed.

Firm commitments to contribute project equity could be accelerated due to
certain events of default as defined in the non-recourse project financing
facilities. Management does not believe that these events of default will
occur to require acceleration of the firm commitments.

CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY

PROJECTS LOCAL CURRENCY U.S. ($ IN MILLIONS)
- -------- ----------------------- --------------------

Paiton(i).............................. -- $39
ISAB(ii)............................... 90 billion Italian Lira 44

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

(i) Contingent obligations to contribute additional project equity will be
based on events principally related to insufficient cash flow to cover
interest on project debt and operating expenses, project cost overruns
during the plant construction, specified partner obligations or events of
default. Our obligation to contribute contingent equity will not exceed
$141 million, of which $102 million has been contributed as of
December 31, 2000. As of March 16, 2001, $5 million of this amount remains
to be funded.

For more information on the Paiton project, see "--Other Commitments and
Contingencies--Paiton."

(ii) ISAB is a 512 MW integrated gasification combined cycle power plant near
Siracusa in Sicily, Italy. A wholly-owned subsidiary of Edison Mission
Energy owns a 49% interest. Commercial operations commenced in
April 2000. Contingent obligations to contribute additional equity to the
project relate specifically to an agreement to provide equity assurances
to the project's lenders depending on the outcome of the contractor claim
arbitration.

We are not aware of any other significant contingent obligations or
obligations to contribute project equity other than as noted above and equity
contributions made by us to meet capital calls by

111

partnerships who own qualifying facilities that have power purchase agreements
with Southern California Edison and Pacific Gas and Electric. See "--California
Power Crisis" for further discussion.

OTHER COMMITMENTS AND CONTINGENCIES

SUBSIDIARY INDEMNIFICATION AGREEMENTS

Some of our subsidiaries have entered into indemnification agreements, under
which the subsidiaries agreed to repay capacity payments to the projects' power
purchasers in the event the projects unilaterally terminate their performance or
reduce their electric power producing capability during the term of the power
contracts. Obligations under these indemnification agreements as of
December 31, 2000, if payment were required, would be $256 million. We have no
reason to believe that the projects will either terminate their performance or
reduce their electric power producing capability during the term of the power
contracts.

CALIFORNIA POWER CRISIS

We have partnership interests in eight partnerships which own power plants
in California which have power purchase contracts with Pacific Gas and Electric
and/or Southern California Edison. Three of these partnerships have a contract
with Southern California Edison, four of them have a contract with Pacific Gas
and Electric, and one of them has contracts with both. In 2000, our share of
earnings before taxes from these partnerships was $168 million, which
represented 20% of our operating income. Our investment in these partnerships at
December 31, 2000 was $345 million.

As a result of Southern California Edison's and Pacific Gas and Electric's
current liquidity crisis, each of these utilities has failed to make payments to
qualifying facilities supplying them power. These qualifying facilities include
the eight power plants which are owned by partnerships in which we have a
partnership interest. Southern California Edison did not pay any of the amounts
due to the partnerships in January, February and March of 2001 and may continue
to miss future payments. Pacific Gas and Electric made its January payment in
full but thus far has paid only a small portion of the amounts due to the
partnerships in February and March and may not pay all or a portion of its
future payments.

The California utilities' failure to pay has adversely affected the
operations of our eight California qualifying facilities. Continuing failures to
pay similarly could have an adverse impact on the operations of our California
qualifying facilities. Provisions in the partnership agreements stipulate that
partnership actions concerning contracts with affiliates are to be taken through
the non-affiliated partner in the partnership. Therefore, partnership actions
concerning the enforcement of rights under each qualifying facility's power
purchase agreement with Southern California Edison in response to Southern
California Edison's suspension of payments under that power purchase agreement
are to be taken through the non-Edison Mission Energy affiliated partner in the
partnership. Some of the partnerships have sought to minimize their exposure to
Southern California Edison by reducing deliveries under their power purchase
agreements. It is unclear at this time what additional actions, if any, the
partnerships will take in regard to the utilities' suspension of payments due to
the qualifying facilities. As a result of the utilities' failure to make
payments due under these power purchase agreements, the partnerships have called
on the partners to provide additional capital to fund operating costs of the
power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours
have made equity contributions totaling approximately $103 million to meet
capital calls by the partnerships. Our subsidiaries and the other partners may
be required to make additional capital contributions to the partnerships.

Southern California Edison has stated that it is attempting to avoid
bankruptcy and, subject to the outcome of regulatory and legal proceedings and
negotiations regarding purchased power costs, it intends to pay all its
obligations once a permanent solution to the current energy and liquidity crisis
has been reached. Pacific Gas and Electric has taken a different approach and is
seeking to invoke force

112

majeure provisions under its power purchase agreements to excuse its failure to
pay. In either case, it is possible that the utilities will not pay all their
obligations in full. In addition, it is possible that Southern California Edison
and/or Pacific Gas and Electric could be forced into bankruptcy proceedings. If
this were to occur, payments to the qualifying facilities, including those owned
by partnerships in which we have a partnership interest, could be subject to
significant delays associated with the lengthy bankruptcy court process and may
not be paid in full. At February 28, 2001, accounts receivable due to these
partnerships from Southern California Edison and Pacific Gas & Electric were
$437 million; our share of these receivables was $217 million. Furthermore,
Southern California Edison's and Pacific Gas and Electric's power purchase
agreements with the qualifying facilities could be subject to review by a
bankruptcy court. While we believe that the generation of electricity by the
qualifying facilities, including those owned by partnerships in which we have a
partnership interest, is needed to meet California's power needs, we cannot
assure you either that these partnerships will continue to generate electricity
without payment by the purchasing utility, or that the power purchase agreements
will not be adversely affected by a bankruptcy or contract renegotiation as a
result of the current power crisis.

CREDIT SUPPORT FOR TRADING AND PRICE RISK MANAGEMENT ACTIVITIES

Our trading and price risk management activities are conducted through our
subsidiary, Edison Mission Marketing & Trading, Inc., which is currently rated
investment grade ("BBB-" by Standard and Poor's). As part of obtaining an
investment grade rating for this subsidiary, we have entered into a support
agreement, which commits us to contribute up to $300 million in equity to Edison
Mission Marketing & Trading, if needed to meet cash requirements. An investment
grade rating is an important benchmark used by third parties when deciding
whether or not to enter into master contracts and trades with us. The majority
of Edison Mission Marketing & Trading's contracts have various standards of
creditworthiness, including the maintenance of specified credit ratings. If
Edison Mission Marketing & Trading does not maintain its investment grade rating
or if other events adversely affect its financial position, a third party could
request Edison Mission Marketing & Trading to provide adequate assurance.
Adequate assurance could take the form of supplying additional financial
information, additional guarantees, collateral, letters of credit or cash.
Failure to provide adequate assurance could result in a counterparty liquidating
an open position and filing a claim against Edison Mission Marketing & Trading
for any losses.

The California power crisis has adversely affected the liquidity of West
Coast trading markets, and to a lesser extent, other regions in the United
States. Our trading and price risk management activity has been reduced as a
result of these market conditions and uncertainty regarding the effect of the
power crisis on our affiliate, Southern California Edison. It is not certain
that resolution of the California power crisis will occur in 2001 or that, if
resolved, we will be able to conduct trading and price risk management
activities in a manner that will be favorable to us.

PAITON

The Paiton project is a 1,230 MW coal fired power plant in operation in East
Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a
$490 million investment in the Paiton project at December 31, 2000. The
project's tariff under the power purchase agreement with PT PLN is higher in the
early years and steps down over time. The tariff for the Paiton project includes
costs relating to infrastructure to be used in common by other units at the
Paiton complex. The plant's output is fully contracted with the state-owned
electric company, PT PLN. Payments are in Indonesian Rupiah, with the portion of
the payments intended to cover non-Rupiah project costs, including returns to
investors, adjusted to account for exchange rate fluctuations between the
Indonesian Rupiah and the U.S. dollar. The project received substantial finance
and insurance support from the Export-Import Bank of the United States, the
Japan Bank for International Cooperation, the U.S. Overseas Private Investment

113

Corporation and the Ministry of Economy, Trade and Industry of Japan. PT PLN's
payment obligations are supported by the Government of Indonesia.

The projected rate of growth of the Indonesian economy and the exchange rate
of Indonesian Rupiah into U.S. dollars have deteriorated significantly since the
Paiton project was contracted, approved and financed. The Paiton project's
senior debt ratings have been reduced from investment grade to speculative grade
based on the rating agencies' determination that there is increased risk that PT
PLN might not be able to honor the power purchase agreement with P.T. Paiton
Energy, the project company. The Government of Indonesia has arranged to
reschedule sovereign debt owed to foreign governments and has entered into
discussions about rescheduling sovereign debt owed to private lenders.

In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the
Paiton project had achieved commercial operation under the terms of the power
purchase agreement and, in July 1999, that the second 615 MW unit of the plant
had similarly achieved commercial operation. Because of the economic downturn,
PT PLN was then experiencing low electricity demand and PT PLN, through
February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a
lawsuit contesting the validity of its agreement to purchase electricity from
the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in
connection with this withdrawal, the parties entered into an interim agreement
for the period through December 31, 2000, under which dispatch levels and fixed
and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made
all fixed payments due under the interim agreement totaling $115 million and all
payments due for energy delivered by the plant to PT PLN. As part of the
continuing negotiations on a long-term restructuring of the tariff, Paiton
Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period
from January 1, 2001 through June 30, 2001. This agreement provides for fixed
monthly payments aggregating $108 million over its six month duration and for
the payment for energy delivered to PT PLN from the plant during this period.
Paiton Energy and PT PLN intend to complete the negotiations of the further
phases of a new long-term tariff during the six month duration of the Phase I
Agreement. To date, PT PLN has made all fixed and energy payments due under the
Phase I Agreement.

Events, including those discussed above, have occurred which may mature into
defaults of the project's debt agreements following the passage of time, notice
or lapse of waivers granted by the project's lenders. On October 15, 1999, the
project entered into an interim agreement with its lenders pursuant to which the
lenders waived defaults during the term of the agreement and effectively agreed
to defer payments of principal until July 31, 2000. In July, the lenders agreed
to extend the term of the lender interim agreement through December 31, 2000. In
December 2000, the lenders agreed to an additional extension of the lender
interim agreement through December 31, 2001. Paiton Energy has received lender
approval of the Phase I Agreement.

Under the terms of the power purchase agreement, PT PLN has been required to
pay for capacity and fixed operating costs once each unit and the plant achieved
commercial operation. As of December 31, 2000, PT PLN had not paid invoices
amounting to $814 million for capacity charges and fixed operating costs under
the power purchase agreement. All arrears under the power purchase agreement
continue to accrue, minus the fixed monthly payments actually made under the
year 2000 interim agreement and under the recently agreed Phase I Agreement,
with the payment of these arrears to be dealt with in connection with the
overall long-term restructuring of the tariff. In this regard, under the Phase I
Agreement, Paiton Energy has agreed that, so long as the Phase I Agreement is
complied with, it will seek to recoup no more than $590 million of the above
arrears, the payment of which is to be dealt with in connection with the overall
tariff restructuring.

Any material modifications of the power purchase agreement resulting from
the continuing negotiation of a new long-term tariff could require a
renegotiation of the Paiton project's debt

114

agreements. The impact of any such renegotiations with PT PLN, the Government of
Indonesia or the project's creditors on our expected return on our investment in
Paiton Energy is uncertain at this time; however, we believe that we will
ultimately recover our investment in the project.

BROOKLYN NAVY YARD

Brooklyn Navy Yard is a 286 MW gas fired cogeneration power plant in
Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In
February 1997, the construction contractor asserted general monetary claims
under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners,
L.P. for damages in the amount of $136.8 million. Brooklyn Navy Yard
Cogeneration Partners has asserted general monetary claims against the
contractor. In connection with a $407 million non-recourse project refinancing
in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its
partner from all claims and costs arising from or in connection with the
contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard
Cogeneration Partners' lenders. At this time, we cannot reasonably estimate the
amount that would be due, if any, related to this litigation. Additional
amounts, if any, which would be due to the contractor with respect to completion
of construction of the power plant would be accounted for as an additional part
of its power plant investment. Furthermore, our partner has executed a
reimbursement agreement with us that provides recovery of up to $10 million over
an initial amount, including legal fees, payable from its management and royalty
fees. At December 31, 2000, no accrual has been recorded in connection with this
litigation. We believe that the outcome of this litigation will not have a
material adverse effect on our consolidated financial position or results of
operations.

ILLINOIS PLANTS--POWER PURCHASE AGREEMENTS

During 2000, 33% of our electric revenues were derived under power purchase
agreements with Exelon Generation Company, a subsidiary of Exelon Corporation,
entered into in connection with our December 1999 acquisition of the Illinois
Plants. Exelon Corporation is the holding company of Commonwealth Edison and
PECO Energy Company, major utilities located in Illinois and Pennsylvania.
Electric revenues attributable to sales to Exelon Generating Company are earned
from capacity and energy provided by the Illinois Plants under three five-year
power purchase agreements. If Exelon Generation were to fail to or became unable
to fulfill its obligations under these power purchase agreements, we may not be
able to find another customer on similar terms for the output of our power
generating assets. Any material failure by Exelon Generation to make payments
under these power purchase agreements could adversely affect our results of
operations and liquidity.

Pursuant to the acquisition documents for the purchase of generating assets
from Commonwealth Edison, our subsidiary committed to install one or more
gas-fired power plants having an additional gross dependable capacity of 500 MWs
at existing or adjacent power plant site in Chicago. The acquisition documents
require that commercial operations of this project be completed by December 15,
2003. The estimated cost to complete the construction of this 500 MW gas-fired
power plant is approximately $250 million.

FUEL SUPPLY CONTRACTS

At December 31, 2000, we had contractual commitments to purchase and/or
transport coal and fuel oil. Based on the contract provisions which consist of
fixed prices, subject to adjustment clauses in some cases, these minimum
commitments are currently estimated to aggregate $2.4 billion in the next five
years summarized as follows: 2001--$838 million; 2002--$653 million;
2003--$386 million; 2004--$308 million; 2005--$241 million.

115

LITIGATION

We are routinely involved in litigation arising in the normal course of
business. While the results of such litigation cannot be predicted with
certainty, we, based on advice of counsel, do not believe that the final outcome
of any pending litigation will have a material adverse effect on our financial
position or results of operations.

ENVIRONMENTAL MATTERS OR REGULATIONS

We are subject to environmental regulation by federal, state and local
authorities in the United States and foreign regulatory authorities with
jurisdiction over projects located outside the United States. We believe that we
are in substantial compliance with environmental regulatory requirements and
that maintaining compliance with current requirements will not materially affect
our financial position or results of operation. However, possible future
developments, such as the promulgation of more stringent environmental laws and
regulations, and future proceedings which may be taken by environmental
authorities, could affect the costs and the manner in which we conduct our
business and could cause us to make substantial additional capital expenditures.
We cannot assure you that we would be able to recover these increased costs from
our customers or that our financial position and results of operations would not
be materially adversely affected.

Typically, environmental laws require a lengthy and complex process for
obtaining licenses, permits and approvals prior to construction and operation of
a project. Meeting all the necessary requirements can delay or sometimes prevent
the completion of a proposed project as well as require extensive modifications
to existing projects, which may involve significant capital expenditures.

We expect that compliance with the Clean Air Act and the regulations and
revised State Implementation Plans developed as a consequence of the Act will
result in increased capital expenditures and operating expenses. For example, we
expect to spend approximately $67 million in 2001 to install upgrades to the
environmental controls at the Homer City plant to control sulfur dioxide and
nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental
controls at the Illinois Plants to control nitrogen oxide emissions to result in
expenditures of approximately $61 million, $67 million, $130 million,
$123 million and $57 million for 2001, 2002, 2003, 2004 and 2005, respectively.
Provisions related to nonattainment, air toxins, permitting of new and existing
units, enforcement and acid rain may affect our domestic plants; however, final
details of all these programs have not been issued by the United States
Environmental Protection Agency and state agencies. In addition, at the
Ferrybridge and Fiddler's Ferry plants we anticipate environmental costs arising
from plant modification of approximately $52 million for the 2001-2005 period.

We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership
which owns and operates a liquified natural gas import terminal and cogeneration
project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection
Agency issued to EcoElectrica a notice of violation and a compliance order
alleging violations of the federal Clean Air Act primarily related to start-up
activities. Representatives of EcoElectrica have met with the Environmental
Protection Agency to discuss the notice of violations and compliance order. To
date, EcoElectrica has not been informed of the commencement of any formal
enforcement proceedings. It is premature to assess what, if any, action will be
taken by the Environmental Protection Agency.

Prior to our purchase of the Homer City plant, the Environmental Protection
Agency requested information from the prior owners of the plant concerning
physical changes at the plant. Other than with respect to the Homer City plant,
no proceedings have been initiated or requests for information issued with
respect to any of our United States facilities. However, we have been in
informal voluntary discussions with the Environmental Protection Agency relating
to these facilities, which may result in the payment of civil fines. We cannot
assure you that we will reach a satisfactory agreement or that these facilities
will not be subject to proceedings in the future. Depending on the outcome of
the

116

proceedings, we could be required to invest in additional pollution control
requirements, over and above the upgrades we are planning to install, and could
be subject to fines and penalties.

NOTE 14. LEASE COMMITMENTS

We lease office space, property and equipment under noncancelable lease
agreements that expire in various years through 2063. The primary capital lease
obligation is for a plant located in the United Kingdom denominated in pounds
sterling. A group of banks provides a guarantee on the performance of the
capital lease obligation under a term loan and guarantee facility agreement. The
facility agreement provides for an aggregate of $171.6 million in a guarantee to
the lessor and in loans to the project. As of December 31, 2000, the loan
obligation stands at $98.8 million, which is secured by the plant assets of
$14.6 million owned by the project and a debt service reserve of $3.0 million.

Future minimum payments for operating and capital leases at December 31,
2000, are:

OPERATING CAPITAL
YEARS ENDING DECEMBER 31, LEASES LEASES
- ------------------------- --------- --------

2001....................................................... $ 174.8 $0.3
2002....................................................... 193.9 0.2
2003....................................................... 195.5 0.2
2004....................................................... 219.5 0.1
2005....................................................... 260.2 0.2
Thereafter................................................. 3,821.4 --
-------- ----
Total future commitments................................... $4,865.3 1.0
========
Amount representing interest (8.86%)....................... 0.2
----
Net Commitments............................................ $0.8
====

Operating lease expense amounted to $122.0 million, $10.4 million and
$6.9 million in 2000, 1999 and 1998, respectively.

SALE-LEASEBACK TRANSACTIONS

In connection with the acquisition of the Illinois Plants, we assigned the
right to purchase the Collins gas and oil-fired power plant to third party
lessors. The third party lessors purchased the Collins Station for $860 million
and entered into leases of the plant with us. The leases, which are being
accounted for as operating leases, have an initial term of 33.75 years with
payments due on a quarterly basis. The base lease rent includes both a fixed and
variable component; the variable component of which is impacted by movements in
defined short-term interest rate indexes. Under the terms of the leases, we may
request a lessor, at its option, to refinance the lessor's debt, which if
completed would impact the base lease rent. If a lessor intends to sell its
interest in the Collins Station, we have a first right of refusal to acquire the
facility at fair market value. Minimum lease payments (included in the table
above) are $42.3 million in 2001, $50.3 million in 2002, $50.3 million in 2003,
$50.4 million in 2004, and $50.3 million in 2005. At December 31, 2000, the
total remaining minimum lease payments were $1.5 billion.

On July 10, 2000, one of our subsidiaries entered into a sale-leaseback of
equipment, primarily Illinois peaker power units, to a third party lessor for
$300 million. Under the terms of the 5-year lease, we have a fixed price
purchase option at the end of the lease term of $300 million. We guarantee the
monthly payments under the lease. Minimum lease payments (included in the table
above) are $21.1 million in 2001, $21.0 million in 2002, $21.0 million in 2003,
and $21.0 million in 2004. In connection with the sale-leaseback, a subsidiary
of ours purchased $255 million of notes issued by the lessor which accrue
interest at LIBOR plus 0.65% to 0.95%, depending on our credit rating. The notes

117

are due and payable in five years. The gain recognized on the sale of equipment
has been deferred and is being amortized over the term of the lease.

On August 24, 2000, we entered into a sale-leaseback transaction for the
Powerton and Joliet power facilities located in Illinois to third party lessors
for an aggregate purchase price of $1.367 billion. Under the terms of the leases
(33.75 years for Powerton and 30 years for Joliet), our subsidiary makes
semi-annual lease payments on each January 2 and July 2, beginning January 2,
2001. Edison Mission Energy guarantees the subsidiary's payments under the
leases. If a lessor intends to sell its interest in the Powerton or Joliet power
facility, we have a right of first refusal to acquire the interest at fair
market value. Minimum lease payments (including in the table above) are
$83.3 million for 2001, $97.3 million for 2002, $97.3 million for 2003,
$97.3 million for 2004 and $141.1 million for 2005. At December 31, 2000, the
total remaining minimum lease payments are $2.4 billion. Lease costs of these
power facilities will be levelized over the terms of the respective leases. The
gain recognized on the sale of the power facilities has been deferred and is
being amortized over the term of the lease.

EDISON MISSION ENERGY MASTER TURBINE LEASE

In December 2000, we entered into a master lease and other agreements for
the construction of new projects using nine turbines that are being procured
from Siemens Westinghouse. The aggregate total construction cost of these
projects is estimated to be approximately $986 million. Under the terms of the
master lease, the lessor, as owner of the projects, is responsible for the
development and construction costs of the new projects using these turbines. We
have agreed to supervise the development and construction of the projects as the
agent of the lessor. Upon completion of construction of each project, we have
agreed to lease the projects from the lessor. In connection with the lease, we
have provided a residual value guarantee to the lessor at the end of the lease
term. We are required to deposit treasury notes equal to 103% of the
construction costs as collateral for the lessor which can only be used under
circumstances involving our default of our obligations we have agreed to perform
during the construction of each project. Lease payments are scheduled to begin
in November 2003. Minimum lease payments (included in the table above) are
$3.1 million in 2003, $27.7 million in 2004, and $50.2 million in 2005. The term
of the master lease ends in 2010. The master lease grants us, as lessee, a
purchase option based on the lease balance which can be exercised at any time
during the term.

NOTE 15. RELATED PARTY TRANSACTIONS

Specified administrative services such as payroll and employee benefit
programs, all performed by Edison International or Southern California Edison
Company employees, are shared among all affiliates of Edison International, and
the costs of these corporate support services are allocated to all affiliates,
including us. Costs are allocated based on one of the following formulas:
percentage of time worked, equity in investment and advances, number of
employees, or multi-factor (operating revenues, operating expenses, total assets
and number of employees). In addition, services of Edison International or
Southern California Edison employees are sometimes directly requested by us and
these services are performed for our benefit. Labor and expenses of these
directly requested services are specifically identified and billed at cost. We
believe the allocation methodologies utilized are reasonable. We made
reimbursements for the cost of these programs and other services, which amounted
to $65.3 million, $34.6 million and $29.7 million in 2000, 1999 and 1998,
respectively. Accounts payable--affiliates associated with these administrative
services totaled $25.5 million and $7.8 million at December 31, 2000 and 1999,
respectively.

We record accruals for tax liabilities and/or tax benefits which are settled
quarterly according to a series of tax sharing agreements as described in
Note 2. Under these agreements, we recognized tax benefits of $226.3 million,
$75.5 million and $29.5 million for 2000, 1999 and 1998, respectively. See

118

Note 10. Amounts included in Accounts receivable--affiliates associated with
these tax benefits totaled $149.9 million and $1.9 million at December 31, 2000
and 1999, respectively.

Edison Mission Operation & Maintenance, Inc., an indirect, wholly-owned
affiliate of Edison Mission Energy, has entered into operation and maintenance
agreements with partnerships in which Edison Mission Energy has a 50% or less
ownership interest. Pursuant to the negotiated agreements, Edison Mission
Operation & Maintenance shall perform all operation and maintenance activities
necessary for the production of power by these partnerships' facilities. The
agreements will continue until terminated by either party. Edison Mission
Operation & Maintenance paid for all costs incurred with operating and
maintaining the facility and may also earn an incentive compensation as set
forth in the agreements. We recorded revenues under the operation and
maintenance agreements of $27.9 million, $28.9 million and $29.8 million in
2000, 1999 and 1998, respectively. Accounts receivable--affiliates for Edison
Mission Operation & Maintenance totaled $4.9 million and $5.1 million at
December 31, 2000 and 1999, respectively.

Specified Edison Mission Energy subsidiaries have ownership in partnerships
that sell electricity generated by their project facilities to Southern
California Edison Company and others under the terms of long-term power purchase
agreements. Sales by these partnerships to Southern California Edison Company
under these agreements amounted to $715.9 million, $512.6 million and
$534.8 million in 2000, 1999 and 1998, respectively.

NOTE 16. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Cash paid
Interest (net of amount capitalized)............ $619.5 $ 327.6 $171.5
Income taxes (receipts)......................... $(38.2) $ (41.5) $ 8.8
Details of assets acquired
Fair value of assets acquired................... $518.5 $9,151.1 $248.4
Liabilities assumed............................. 396.8 539.1 --
------ -------- ------
Net cash paid for acquisitions.................... $121.7 $8,612.0 $248.4
====== ======== ======

NOTE 17. BUSINESS SEGMENTS

We operate predominantly in one line of business, electric power generation,
with reportable segments organized by geographic region: Americas, Asia Pacific
and Europe, Central Asia, Middle East and Africa. Our plants are located in
different geographic areas, which mitigate the effects of regional markets,
economic downturns or unusual weather conditions.

Electric power and steam generated in the United States is sold primarily
under (1) long-term contracts, with terms of 15 to 30-years, to domestic
electric utilities and industrial steam users, (2) through a centralized power
pool, or (3) under power purchase agreements with Commonwealth Edison, which
assigned its rights and obligations under these power purchase agreements to
Exelon Generation Company, which began December 15, 1999 and have a term of up
to five years. We currently derive a significant source of our revenues from the
sale of energy and capacity to Exelon Generation Company under the power
purchase agreements terminating in December 2004. Our revenues from Commonwealth
Edison were $1.1 billion for the year ended December 31, 2000. This represents
33% of our consolidated revenues in 2000. Our share of equity in earnings from
partnerships that have long-term power purchase agreements with Southern
California Edison were $153.0 million, $132.4 million and $112.7 million for the
years ended December 31, 2000, 1999 and

119

1998, respectively. This represents 5% in 2000, 8% in 1999 and 13% in 1998 of
our consolidated revenues. Both companies' revenues are included in the Americas
region shown below.

Plants located in the United Kingdom and a plant in Australia sell their
energy and capacity production through a centralized power pool. The plants that
sell through a centralized power pool enter into short and/or long-term
contracts to hedge against the volatility of price fluctuations in the pool.
Other electric power generated overseas is sold under long-term contracts to
electric utilities located in the country where the power is generated.
Intercompany transactions have been eliminated in the following segment
information.

EUROPE,
CENTRAL ASIA,
ASIA MIDDLE EAST CORPORATE/
AMERICAS PACIFIC AND AFRICA OTHER TOTAL
-------- -------- ------------- ---------- ---------

2000
Electric & operating revenues............ $1,571.0 $ 184.2 $1,236.3 $ -- $ 2,991.5
Net losses from energy trading and price
risk management........................ (17.3) -- -- -- (17.3)
Equity in income from investments........ 257.2 14.6 (5.0) -- 266.8
-------- -------- -------- ------- ---------
Total operating revenues............... 1,810.9 198.8 1,231.3 -- 3,241.0

Fuel and plant operations................ 1,131.6 61.5 730.1 -- 1,923.2
Depreciation and amortization............ 191.2 35.0 144.8 11.1 382.1
Long-term incentive compensation......... -- -- -- (56.0) (56.0)
Administrative and general............... 21.1 -- -- 139.8 160.9
-------- -------- -------- ------- ---------
Income (loss) from operations............ $ 467.0 $ 102.3 $ 356.4 $ (94.9) $ 830.8
======== ======== ======== ======= =========
Identifiable assets...................... $5,606.6 $1,408.9 $5,346.8 $ 567.2 $12,929.5
Equity investments and advances.......... 952.3 1,048.9 86.4 -- 2,087.6
-------- -------- -------- ------- ---------
Total assets........................... $6,558.9 $2,457.8 $5,433.2 $ 567.2 $15,017.1
======== ======== ======== ======= =========
Additions to property and plant.......... $ 294.1 $ 4.0 $ 38.9 $ 15.3 $ 352.3

1999
Electric & operating revenues............ $ 378.6 $ 213.6 $ 805.8 $ -- $ 1,398.0
Net losses from energy trading and price
risk management........................ (6.4) -- -- -- (6.4)
Equity in income from investments........ 224.8 18.1 1.4 -- 244.3
-------- -------- -------- ------- ---------
Total operating revenues............... 597.0 231.7 807.2 -- 1,635.9

Fuel and plant operations................ 237.7 73.8 456.6 -- 768.1
Depreciation and amortization............ 52.5 40.5 88.3 8.9 190.2
Long-term incentive compensation......... -- -- -- 136.3 136.3
Administrative and general............... -- -- -- 114.9 114.9
-------- -------- -------- ------- ---------
Income (loss) from operations............ $ 306.8 $ 117.4 $ 262.3 $(260.1) $ 426.4
======== ======== ======== ======= =========
Identifiable assets...................... $6,708.4 $1,421.1 $5,382.8 $ 81.0 $13,593.3
Equity investments and advances.......... 862.2 1,063.1 15.6 -- 1,940.9
-------- -------- -------- ------- ---------
Total assets........................... $7,570.6 $2,484.2 $5,398.4 $ 81.0 $15,534.2
======== ======== ======== ======= =========
Additions to property and plant.......... $6,127.0 $ 6.1 $2,124.3 $ 52.7 $ 8,310.1

120

EUROPE,
CENTRAL ASIA,
ASIA MIDDLE EAST CORPORATE/
AMERICAS PACIFIC AND AFRICA OTHER TOTAL
-------- -------- ------------- ---------- ---------

1998
Electric & operating revenues............ $ 29.9 $ 205.1 $ 469.4 $ -- $ 704.4
Equity in income from investments........ 184.6 1.3 3.5 -- 189.4
-------- -------- -------- ------- ---------
Total operating revenues............... 214.5 206.4 472.9 -- 893.8

Fuel and plant operations................ 22.2 69.6 241.3 -- 333.1
Depreciation and amortization............ 9.8 31.6 40.3 5.6 87.3
Long-term incentive compensation......... -- -- -- 39.0 39.0
Administrative and general............... -- -- -- 83.9 83.9
-------- -------- -------- ------- ---------
Income (loss) from operations............ $ 182.5 $ 105.2 $ 191.3 $(128.5) $ 350.5
======== ======== ======== ======= =========
Identifiable assets...................... $ 173.6 $1,334.3 $2,239.6 $ 184.1 $ 3,931.6
Equity investments and advances.......... 841.2 361.2 23.8 0.3 1,226.5
-------- -------- -------- ------- ---------
Total assets........................... $1,014.8 $1,695.5 $2,263.4 $ 184.4 $ 5,158.1
======== ======== ======== ======= =========
Additions to property and plant.......... $ 1.1 $ 2.2 $ 66.1 $ 4.0 $ 73.4

During 2000, Edison Mission Energy changed its presentation of segment
performance by presenting the measure of profit or loss for each reportable
segment as income (loss) from operation compared to net income (loss) as
reported in 1999 and 1998.

GEOGRAPHIC INFORMATION

Foreign operating revenues and assets by country included in the table above
are shown below.

YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Operating revenues
Australia....................................... $ 178.1 $208.5 $199.3
Other Asia Pacific.............................. 20.7 23.2 7.1
-------- ------ ------
Total Asia Pacific................................ $ 198.8 $231.7 $206.4
======== ====== ======
United Kingdom.................................. $1,114.6 $746.8 $448.8
Turkey.......................................... 98.9 38.0 --
Spain........................................... 17.8 22.4 24.1
-------- ------ ------
Total Europe, Central Asia, Middle East and
Africa.......................................... $1,231.3 $807.2 $472.9
======== ====== ======

121

DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------

Assets
Australia.................................... $1,216.5 $1,397.5 $1,326.2
New Zealand.................................. 685.7 616.8 --
Indonesia.................................... 531.3 442.5 358.2
Other Asia Pacific........................... 24.3 27.4 11.1
-------- -------- --------
Total Asia Pacific............................. $2,457.8 $2,484.2 $1,695.5
======== ======== ========
United Kingdom............................... $4,933.1 $5,032.3 $1,787.1
Turkey....................................... 231.0 191.2 161.8
Spain........................................ 143.9 167.2 195.7
Other Europe, Central Asia, Middle East and
Africa..................................... 125.2 7.7 118.8
-------- -------- --------
Total Europe, Central Asia, Middle East and
Africa....................................... $5,433.2 $5,398.4 $2,263.4
======== ======== ========

NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)

2000 FIRST(I) SECOND THIRD(I) FOURTH(I) TOTAL
- ---- -------- -------- -------- --------- --------

Operating revenues......................... $736.9 $723.2 $1,050.3 $730.6 $3,241.0
Operating income........................... 127.6 125.4 489.5 88.3 830.8
Income (loss) before accounting change..... (30.2)(ii) (18.5)(ii) 191.3 (35.0) 107.6
Net income (loss).......................... (12.5)(ii) (18.5)(ii) 191.3 (35.0) 125.3

1999 FIRST(I) SECOND THIRD(I) FOURTH(I) TOTAL
- ---- -------- -------- -------- --------- --------

Operating revenues........................... $269.6 $271.3(iii) $532.4(iv) $562.6 (v) $1,635.9
Operating income............................. 114.1 74.9(iii) 218.0(iv) 19.4 (v) 426.4
Income (loss) before accounting change....... 57.9 5.5(iii) 86.6(iv) (5.9)(v) 144.1
Net income (loss)............................ 44.1 5.5(iii) 86.6(iv) (5.9)(v) 130.3

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

(i) Reflects our seasonal pattern, in which the majority of earnings from
domestic projects are recorded in the third quarter of each year and higher
electric revenues from specified international projects are recorded during
the winter months of each year.

(ii) Reflects an increase in interest expense as the result of additional debt
financings due to the acquisitions throughout 1999.

(iii) Reflects the operations of the Homer City plant acquired in March 1999.

(iv) Reflects the operations of the Homer City plant, the Doga project, which
commenced commercial operations in May 1999, and the Ferrybridge and
Fiddler's Ferry plants acquired in July 1999.

(v) Reflects the operations of the Homer City plant, the Doga project, the
Ferrybridge and Fiddler's Ferry plants and the Illinois Plants acquired in
December 1999.

122

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

POSITIONS WITH EDISON MISSION ENERGY

Listed below are our current directors and executive officers and their ages
and positions as of March 20, 2001.

DIRECTOR POSITION HELD
CONTINUOUSLY TERM CONTINUOUSLY TERM
NAME, POSITION AND AGE SINCE EXPIRES SINCE EXPIRES
- ---------------------- ------------ -------- ------------- --------

John E. Bryson, 57 .................................. 2000 2001 -- --
Director, Chairman of the Board

Dean A. Christiansen, 41 ............................ 2001 2001 -- --
Director

Theodore F. Craver, Jr., 49 ......................... 2001 2001 -- --
Director

Bryant C. Danner, 63 ................................ 1993 2001 -- --
Director

Alan J. Fohrer, 50 .................................. 1992 2001 2000 2001
Director, President and Chief Executive Officer

Robert M. Edgell, 54 ................................ -- -- 1988 2001
Executive Vice President and Division President of
Edison Mission Energy, Asia Pacific

William J. Heller, 44 ............................... -- -- 2000 2001
Senior Vice President and Division President of
Edison Mission Energy, Europe, Central Asia, Middle
East and Africa

Ronald L. Litzinger, 41 ............................. -- -- 1999 2001
Senior Vice President, WorldwideOperations

Georgia R. Nelson, 51 ............................... -- -- 1999 2001
Senior Vice President and President of Midwest
Generation EME, LLC

Kevin M. Smith, 43 .................................. -- -- 1999 2001
Senior Vice President and Chief Financial Officer

Raymond W. Vickers, 58 .............................. -- -- 1999 2001
Senior Vice President and General Counsel

BUSINESS EXPERIENCE

Below is a description of the principal business experience during the past
five years of each of the individuals named above and the name of each public
company in which any director named above is a director.

MR. BRYSON has been director and chairman of the board of Edison Mission
Energy since January 2000. Mr. Bryson was director of Edison Mission Energy from
January 1986 to January 1998. Mr. Bryson has been president of Edison
International since January 2000 and chairman of the board and chief executive
officer of Edison International since 1990. Mr. Bryson served as chairman of the
board, chief executive officer and a director of Southern California Edison from
1990 to January 2000. Mr. Bryson is a director of The Walt Disney Company, The
Boeing Company, and Pacific American Income Shares, Inc. and LM Institutional
Fund Advisors I, Inc.

123

MR. CHRISTIANSEN has been director of Edison Mission Energy since
January 2001 and serves as Edison Mission Energy's independent director.
Mr. Christiansen has been president of Lord Securities since October 2000 and
has been president of Acacia Capital since May 1990. Mr. Christiansen has been a
director of Capital Markets Engineering & Trading, New York since August 1999
and has been director of Structural Concepts Corporation of Muskegon, Michigan
since May 1995.

MR. CRAVER has been director of Edison Mission Energy since January 2001.
Mr. Craver has been senior vice president, chief financial officer, and
treasurer of Edison International since January 2000. Mr. Craver has been
chairman of the board and chief executive officer of Edison Enterprise since
September 1999. Mr. Craver served as senior vice president and treasurer of
Edison International from February 1998 to January 2000. Mr. Craver served as
senior vice president and treasurer of Southern California Edison from
February 1998 to September 1999. Mr. Craver served as vice president and
treasurer of Edison International and Southern California Edison from
September 1996 to February 1998. Mr. Craver was executive vice president and
corporate treasurer of First Interstate Bancorp from September 1990 to
April 1996.

MR. DANNER has been director of Edison Mission Energy since May 1993.
Mr. Danner has been executive vice president and general counsel of Edison
International since June 1995. Mr. Danner was executive vice president and
general counsel of Southern California Edison from June 1995 until
January 2000. Mr. Danner was senior vice president and general counsel of Edison
International and Southern California Edison from July 1992 until May 1995.

MR. EDGELL has been executive vice president of Edison Mission Energy since
April 1988. Mr. Edgell served as director of Edison Mission Energy from
May 1993 to January 2001. Mr. Edgell was named division president of Edison
Mission Energy's Asia Pacific region in January 1995.

MR. FOHRER has been director, president and chief executive officer of
Edison Mission Energy since January 2000. From 1998 to 2000, Mr. Fohrer served
as chairman of the board. From 1993 to 1998, Mr. Fohrer served as vice chairman
of the board. Mr. Fohrer was executive vice president and chief financial
officer of Edison International and was executive vice president and chief
financial officer of Southern California Edison from June 1995 until
January 2000. Effective February 1996 and June 1995, Mr. Fohrer also served as
treasurer of Southern California Edison and Edison International, respectively,
until August 1996. Mr. Fohrer was senior vice president, treasurer and chief
financial officer of Edison International, and senior vice president and chief
financial officer of Southern California Edison from January 1993 until
May 1995. Mr. Fohrer was Edison Mission Energy's interim chief executive officer
between May 1993 and August 1993. From 1991 until 1993, Mr. Fohrer was vice
president, treasurer and chief financial officer of Edison International and
Southern California Edison.

MR. HELLER has been senior vice president and division president of Edison
Mission Energy, Europe, Central Asia, Middle East and Africa since
February 2000. Mr. Heller was elected director of Edison Mission Energy's board,
effective December 9, 1999, and subsequently resigned effective February 7,
2000. Mr. Heller was senior vice president of Strategic Planning and New
Business Development for Edison International from January 1996 until
February 2000. Prior to joining Edison International, Mr. Heller was with
McKinsey and Company, Inc. from 1982 to 1995, serving as principal and head of
McKinsey's Los Angeles Energy Practice from 1991 to 1995.

MR. LITZINGER has been senior vice president of Edison Mission Energy's
Worldwide Operations since June 1999. Mr. Litzinger served as vice president of
O&M Business Development from December 1998 to May 1999. Mr. Litzinger has been
with Edison Mission Energy since November 1995 serving as both regional vice
president of O&M Business Development and manager of O&M Business Development
until December 1998. Prior to joining Edison Mission Energy, Mr. Litzinger was a
reliability supervisor with Texaco Refining and Marketing, Inc. from March 1995
to October 1995 and prior to that held numerous management positions with
Southern California Edison since June 1986.

124

MS. NELSON has been senior vice president of Edison Mission Energy since
January 1996 and has been president of Midwest Generation EME, LLC since
May 1999. From January 1996 until June 1999, Ms. Nelson was senior vice
president of Worldwide Operations. Ms. Nelson was division president of Edison
Mission Energy's Americas region from January 1996 to January 1998. Prior to
joining Edison Mission Energy, Ms. Nelson served as senior vice president of
Southern California Edison from June 1995 until December 1995 and vice president
of Southern California Edison from June 1993 until May 1995.

MR. SMITH has been senior vice president and chief financial officer of
Edison Mission Energy since May 1999. Mr. Smith served as treasurer of Edison
Mission Energy from 1992 to 2000 and was elected a vice president in 1994.
During March 1998 until September 1999, Mr. Smith also held the position of
regional vice president of the Americas region.

MR. VICKERS has been senior vice president and general counsel of Edison
Mission Energy since March 1999. Prior to joining Edison Mission Energy,
Mr. Vickers was a partner with the law firm of Skadden, Arps, Slate, Meagher &
Flom LLP concentrating on international business transactions, particularly
cross-border capital markets and investment transactions, project implementation
and finance.

SECTION 16 (a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Pursuant to Item 405 of Regulation S-K, Edison Mission Energy is required to
disclose the following recently elected officers who each had one delinquent
Form 3 "Initial Statement of Beneficial Ownership of Securities" filing which is
required to be filed within 10 days of being elected for fiscal year 2000:

NAME DATE ELECTED
- ---- ------------------

Dennis Winkleman, Vice President........................ February 7, 2000
Thomas McDaniel, Director............................... February 9, 2000
Gary Garcia, Treasurer.................................. February 10, 2000
Sam Henry, Vice President............................... August 1, 2000
Fred McCluskey, Vice President.......................... August 1, 2000
Guy Gorney, Vice President.............................. August 1, 2000
John Mathis, Vice President............................. August 30, 2000
David Goss, Vice President.............................. September 1, 2000
Paul Jacob, Vice President.............................. September 1, 2000
Mark Maisto, Vice President............................. September 1, 2000
Mark Williams, Vice President........................... September 1, 2000
Larry Silverstein, Vice President....................... September 1, 2000
John Mallory, Vice President............................ September 1, 2000
Lewis Hashimoto, Vice President......................... November 6, 2000

125

ITEM 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table provides information concerning compensation paid by
Edison Mission Energy to each of the named executive officers during the years
2000, 1999 and 1998 for services rendered by such persons in all capacities to
Edison Mission Energy and its subsidiaries.

SUMMARY COMPENSATION TABLE

LONG-TERM
COMPENSATION
AWARDS
ANNUAL COMPENSATION ------------
--------------------------------------------------- SECURITIES
OTHER ANNUAL UNDERLYING ALL OTHER
SALARY BONUS COMPENSATION(3) OPTIONS(4) COMPENSATION(5)
NAME AND PRINCIPAL POSITION YEAR ($) ($) ($) (#) ($)
- --------------------------- -------- -------- -------- --------------- ------------ ---------------

Alan J. Fohrer(1) ........ 2000 458,654 --(8) 49,176 497,800 55,604
President and Chief
Executive Officer

Edward R. Muller(1) ...... 2000 22,431 --(8) 91 98,000 508,001(7)
President and Chief 1999 463,000 347,250 2,147 33,780 35,797
Executive Officer 1998 432,000 390,000 2,624 21,160 40,172

Robert M. Edgell ......... 2000 417,000 --(8) -- 183,600 100,041(6)
Executive Vice President 1999 387,000 276,500 -- 23,580 93,224(6)
and Division President of 1998 362,000 265,000 -- 14,760 56,474(6)
Edison Mission Energy,
Asia Pacific

Raymond W. Vickers ....... 2000 359,000 --(8) 4,648 161,200 16,170
Senior Vice President and 1999 287,692 158,700 2,688 22,690 231
General Counsel

Georgia R. Nelson ........ 2000 349,000 --(8) 4,228 150,900 31,460
Senior Vice President and 1999 330,000 178,200 3,532 13,610 28,478
President of Midwest 1998 310,000 170,000 3,125 8,580 29,233
Generation EME, LLC

Mark Maisto(2) ........... 2000 99,231 850,000(8) -- 30,000 1,846
President of Edison
Mission Marketing &
Trading, Inc.

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

(1) On January 17, 2000, Mr. Muller resigned as president and chief executive
officer of Edison Mission Energy and Mr. Fohrer was elected president and
chief executive officer of Edison Mission Energy.

(2) On February 23, 2001, Mr. Maisto resigned as president of Edison Mission
Marketing & Trading, Inc.

(3) Includes perquisites if in total they exceed the lesser of $50,000 or 10% of
annual salary and bonus, plus reimbursed taxes.

(4) No Stock Appreciation Rights have been awarded. Amounts shown are comprised
of Edison International nonqualified stock options and Edison Mission Energy
phantom stock options for

126

1999 and 1998. As discussed in footnote (3) in the table below entitled
"Aggregated Option Exercises in 2000 and Year-End Option Values," all
phantom stock options have been canceled pursuant to an exchange offer. The
terms and conditions for the 2000 Option Awards are described in footnotes
to the table below entitled "Option Grants in 2000." For 2000, Mr. Fohrer,
Mr. Muller, Mr. Edgell, Mr. Vickers, Ms. Nelson and Mr. Maisto received
496,672; 98,000; 61,200; 51,200; 50,300 and 0 Edison International stock
options pursuant to the Edison International Equity Compensation Plan,
respectively, and 1,128; 0; 122,400; 110,000; 100,600 and 30,000 Edison
International stock options pursuant to the Edison International 2000 Equity
Plan, respectively. For 1999, Mr. Muller, Mr. Edgell, Mr. Vickers and
Ms. Nelson received 23,100; 16,100; 15,500 and 9,300 Edison International
stock options, respectively, and 10,680; 7,480; 7,190 and 4,310 Edison
Mission Energy phantom stock options, respectively. For 1998, Mr. Muller,
Mr. Edgell and Ms. Nelson received 13,300; 8,700 and 5,400 Edison
International stock options, respectively; and 7,860; 6,060 and 3,180 Edison
Mission Energy phantom stock options, respectively.

(5) Includes the following company contributions to a defined contribution plan,
Stock Savings Plus Plan and a supplemental plan for eligible participants
who are affected by Stock Savings Plus Plan participation limits imposed on
higher-paid individuals by federal tax law: For 2000, Mr. Fohrer, $31,801;
Mr. Muller, $2,984; Mr. Edgell, $25,870; Mr. Vickers, $14,961; Ms. Nelson,
$20,984 and Mr. Maisto, $1,846. For 1999, Mr. Muller, $30,374; Mr. Edgell,
$16,384; Mr. Vickers, $0 and Ms. Nelson, $19,779. For 1998, Mr. Muller,
$26,373; Mr. Edgell, $14,550 and Ms. Nelson, $15,461.

Also includes the following amounts of interest accrued on deferred
compensation of the named individuals, which is considered under the rules
of the Securities and Exchange Commission to be at an above-market rate: For
2000, Mr. Fohrer, $23,743; Mr. Muller, $4,769; Mr. Edgell, $840;
Mr. Vickers, $1,110; Ms. Nelson, $3,856 and Mr. Maisto, $0. For 1999,
Mr. Muller, $5,272; Mr. Edgell, $338; Mr. Vickers, $231 and Ms. Nelson,
$2,353; For 1998, Mr. Muller, $13,520; Mr. Edgell, $1,116 and Ms. Nelson,
$7,812.

(6) Includes an overseas service allowance of $65,311, $68,644 and $33,693 in
2000, 1999 and 1998, respectively.

(7) In January 2000, Edison Mission Energy entered into a separate agreement
with Mr. Muller in connection with the end of his employment that is
discussed below in the section entitled "Employment Contract and Termination
of Employment Arrangements."

(8) No bonuses were paid under the Executive Incentive Compensation Plan to
executive officers for 2000 performance. Mr. Maisto received an award for
year 2000 performance pursuant to agreements entered into in connection with
the acquisition of Citizens Power LLC by Edison Mission Energy.

127

EXECUTIVE STOCK OPTIONS

The following table presents information regarding Edison International
stock options granted during 2000 pursuant to the Edison International Equity
Compensation Plan and/or the Edison International 2000 Equity Plan adopted by
the Edison International Board on May 18, 2000 to the executive officers named
in the Summary Compensation Table above.

OPTION GRANTS IN 2000(1)

INDIVIDUAL GRANTS
---------------------------------------------------------
PERCENT OF
TOTAL OPTIONS GRANT DATE
OPTIONS GRANTED TO EXERCISE OR PRESENT
GRANTED EMPLOYEES BASE PRICE EXPIRATION VALUE
NAME (#)(2)(3)(4) IN 2000 ($/SH) DATE(5) ($)(6)
- ---- ------------ --------------- ----------- ---------- ----------

Alan J. Fohrer(7)
Equity Compensation Plan............ 83,100 2% 25.1875 01/04/2010 438,768
Equity Compensation Plan............ 14,700 LESS THAN 1% 27.1250 01/04/2010 84,231
Equity Compensation Plan............ 398,872 10% 20.0625 05/18/2010 2,321,435
2000 Equity Plan.................... 1,128 LESS THAN 1% 20.0625 05/18/2010 6,565
Edward R. Muller
Equity Compensation Plan............ 98,000 2% 25.1875 cancelled 517,440
Robert M. Edgell
Equity Compensation Plan............ 61,200 2% 25.1875 01/04/2010 323,136
2000 Equity Plan.................... 122,400 3% 20.0625 05/18/2010 712,368
Raymond W. Vickers
Equity Compensation Plan............ 51,200 1% 25.1875 01/04/2010 270,336
2000 Equity Plan.................... 110,000 3% 20.0625 05/18/2010 640,200
Georgia R. Nelson
Equity Compensation Plan............ 50,300 1% 25.1875 01/04/2010 265,584
2000 Equity Plan.................... 100,600 2% 20.0625 05/18/2010 585,492
Mark Maisto
2000 Equity Plan.................... 15,000 LESS THAN 1% 20.5000 03/25/2002 89,850
2000 Equity Plan.................... 15,000 LESS THAN 1% 20.5000 cancelled 89,850

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

(1) No Stock Appreciation Rights were granted under the Equity Compensation Plan
to any participant during 2000. Stock Appreciation Rights cannot be granted
under the 2000 Equity Plan. This table reflects all awards made under the
Edison International Equity Compensation Plan and/or the 2000 Equity Plan
during 2000.

(2) Edison International nonqualified stock options granted in 2000 may be
exercised when vested to purchase one share of Edison International common
stock. Two Option Award grants were made during 2000 to the executive
officers named in the table above. On January 3, 2000, the annual Option
Award was made, and on May 18, 2000, a special Option Award was made in lieu
of the 2001 and 2002 annual Option Awards. No dividend equivalents were
included with either of these option grants.

The Edison International Compensation and Executive Personnel Committee
administers the Equity Compensation Plan and the 2000 Equity Plan and has
sole discretion to determine all terms and conditions of any grant, subject
to plan limits. It may substitute cash that is equivalent in value to the
Option Awards and, with the consent of the executive, may amend the terms of
any award, including the post-termination term, and the vesting schedule.

(3) The January 3, 2000, Option Awards are subject to a four-year vesting period
with one-fourth of the total award vesting and becoming exercisable annually
beginning on January 2, 2001. If an executive retires, dies, or terminates
employment following a permanent and total disability during the four-year
vesting period, the unvested Option Awards will vest and be exercisable to
the extent of 1/48 of the grant for each full month of service during the
vesting period. Upon retirement, death or permanent and total disability,
the vested Option Awards may continue to be exercised within their original
term by the recipient or beneficiary. If an executive

128

is terminated other than by retirement, death or permanent and total
disability, Option Awards that were vested as of the prior anniversary date
of the grant are forfeited unless exercised within 180 days of the date of
termination. All unvested Option Awards are forfeited on the date of
termination. The Option Awards of Mr. Fohrer are transferable to a spouse,
child or grandchild.

Appropriate and proportionate adjustments may be made by the Edison
International Compensation and Executive Personnel Committee to the Option
Awards to reflect any impact resulting from various corporate events such as
reorganizations, stock splits and so forth. If Edison International is not
the surviving corporation in such a reorganization, all Option Awards then
outstanding will become vested and be exercisable unless provisions are made
as part of the transaction to substitute options of the successor
corporation with appropriate adjustments as to the number and price of the
options. Notwithstanding the foregoing, the January 3, 2000 Option Awards
provide that upon a change of control of Edison International after the
occurrence of a Distribution Date under the Rights Agreement approved by the
Edison International Board of Directors on November 21, 1996, and amended on
September 16, 1999, the options will vest and will remain exercisable for at
least two years following the Distribution Date. A Distribution Date is
generally the date a person acquires 20% or more of the Common Stock of
Edison International, or a date specified by the Edison International Board
of Directors after commencement of a tender offer for 20% or more of such
stock. In no event, however, may an Option Award be exercised beyond its
original term.

(4) The May 18, 2000, Option Awards are subject to a five-year vesting period
with one-fourth of the total award vesting annually beginning on May 18,
2002. The Option Awards may not be exercised prior to May 18, 2005, unless
the closing price of Edison International Common Stock has averaged at least
$25 per share over 20 consecutive trading days. If an executive retires,
dies, or terminates employment following a permanent and total disability (a
"Separation Event") during the five-year vesting period, the unvested Option
Awards will vest and be exercisable (subject to the stock price appreciation
requirement) to the extent of 1/60 of the grant for each full month of
service during the vesting period, taking into consideration prior vesting
and exercises (the "regular vesting rule"). Unvested Option Awards of
Mr. Fohrer will vest and be exercisable upon a Separation Event in two equal
blocks, the 2001 block and the 2002 block. Both blocks will vest and be
exercisable to the extent provided under the regular vesting rule if the
Separation Event occurs prior to January 1, 2001. If the Separation Event
occurs during 2001, the 2001 block will be fully vested and exercisable
(subject to the stock price appreciation requirement), and the 2002 block
will vest and be exercisable to the extent determined under the regular
vesting rule. If the Separation Event occurs after 2002, both blocks will be
fully vested and exercisable (subject to the stock price appreciation
requirement). Following a Separation Event, the vested Option Awards may be
exercised within their original term by the recipient or beneficiary. If an
executive terminates employment other than by a Separation Event, Option
Awards that were vested as of the prior anniversary date of the grant are
forfeited unless exercised within 180 days of the date employment is
terminated. All unvested Option Awards are forfeited on the date employment
is terminated. The Option Awards of Mr. Fohrer are transferable to a spouse,
child or grandchild.

Appropriate and proportionate adjustments may be made by the Edison
International Compensation and Executive Personnel Committee to the Option
Award to reflect any impact resulting from various corporate events such as
reorganizations, stock splits and so forth. In the event of a change in
control of Edison International, the May 18, 2000, Option Awards then
outstanding will vest and be exercisable unless provisions are made as part
of the transaction for the assumption or substitution of the Option Awards
with options of the successor corporation with appropriate adjustments as to
the number and price of the options. If an involuntary severance occurs
during a protected period, but prior to a change in control, unvested Option
Awards and vested Option Awards reaching the end of their 180-day exercise
period will be suspended and unexercisable. If a change in control occurs
within 24 months after the involuntary severance, the Option Awards will
vest and be exercisable for 60 days after the change in control, or until
the end of the 180-day period following employment termination, whichever
date is later. In no event, however, may an Option Award be exercised beyond
its original term.

(5) The Option Awards are subject to earlier expiration upon termination of
employment as described in footnotes (3) and (4) above.

(6) The grant date value of each Edison International stock option for the
January 3, 2000, Option Award was calculated to be $5.28 per option share
using the Black-Scholes stock option pricing model. For purposes of

129

this calculation, it was assumed that the average exercise period was ten
years, the volatility rate was 23.48%, the risk-free rate of return was
5.58%, the dividend yield was 4.02% and the stock price and exercise price
were $25.1875.

The grant date value of each Edison International stock option for the
January 18, 2000, Option Award was calculated to be $5.73 per option share
using the Black-Scholes stock option pricing model. For purposes of this
calculation, it was assumed that the average exercise period was ten years,
the volatility rate was 23.48%, the risk-free rate of return was 5.65%, the
dividend yield was 4.02% and the stock price and exercise price were
$27.125.

The grant date value of each Edison International stock option for the
May 18, 2000, Option Award was calculated to be $5.82 per option share using
the Black-Scholes stock option pricing model. For purposes of this
calculation, it was assumed that the average exercise period was ten years,
the volatility rate was 36.67%, the risk-free rate of return was 6.01%, the
dividend yield was 4.21% and the stock price and exercise price were
$20.0625.

The grant date value of each Edison International stock option for the
September 1, 2000, Option Award was calculated to be $5.99 per option share
using the Black-Scholes stock option pricing model. For purposes of this
calculation, it was assumed that the average exercise period was ten years,
the volatility rate was 38.12%, the risk-free rate of return was 6.06%, the
dividend yield was 4.35% and the stock price and exercise price were
$20.500.

(7) Mr. Fohrer was granted an additional increment of Edison International stock
options on January 18, 2000, upon his election as president and chief
executive officer of Edison Mission Energy.

130

The following table presents information regarding the exercise of Edison
International stock options and Edison Mission Energy phantom stock options
during 2000 by the executive officers named in the Summary Compensation Table
above and unexercised options held as of December 31, 2000 by any of the named
officers. No Stock Appreciation Rights were exercised during 2000 or held at
year-end 2000 by any of the named officers.

AGGREGATED OPTION EXERCISES IN 2000
AND YEAR-END OPTION VALUES

(A) (B) (C) (D) (E)
NUMBER OF
UNEXERCISED OPTIONS VALUE OF UNEXERCISED IN-
AT FISCAL YEAR- THE-MONEY OPTIONS AT
END(1) FISCAL YEAR-END(1)(2)
------------------- ------------------------
SHARES ACQUIRED EXERCISABLE/ EXERCISABLE/
ON EXERCISE VALUE REALIZED UNEXERCISABLE UNEXERCISABLE
NAME (#) ($) (#) ($)
- ---- --------------- -------------- ------------------- ------------------------

Alan J. Fohrer
Edison International ..... -- -- 211,026 / 582,474 37,912 / 0
Edward R. Muller
Edison International ..... -- -- 88,666 / 12,534 8,425 / 0
Edison Mission Energy .... -- --(4) 0 / 0 0 / 0
Robert M. Edgell
Edison International ..... -- -- 47,576 / 200,024 2,190 / 0
Edison Mission Energy .... -- --(5) 0 / 0 17,435,794 / 755,348
Raymond W. Vickers
Edison International ..... -- -- 3,876 / 172,824 0 / 0
Edison Mission Energy .... -- --(5) 0 / 0 140,611 / 431,150
Georgia R. Nelson
Edison International ..... -- -- 11,692 / 160,574 0 / 0
Edison Mission Energy .... -- --(5) 0 / 0 4,640,176 / 419,411
Mark Maisto
Edison International ..... -- -- 0 / 30,000 0 / 0

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

(1) Each Edison International stock option may be exercised for one share of
Edison International Common Stock at an exercise price equal to the fair
market value of the underlying Common Stock on the date the option was
granted. Dividend equivalents that may accrue on some of the Edison
International stock options accumulate without interest and are paid in
cash. The option terms for current year awards are discussed in footnotes
(3) and (4) in the table above entitled "Option Grants in 2000." Each Edison
Mission Energy phantom stock option represents a right to exercise an option
to realize any appreciation in the deemed value of one hypothetical share of
Edison Mission Energy phantom stock. Outstanding Edison Mission Energy
phantom stock options were canceled pursuant to an exchange offer that is
discussed in footnote (3) below.

(2) Edison International stock options have been treated as in-the-money if the
fair market value of the underlying stock at December 31, 2000 exceeded the
exercise price of the options. The dollar amounts shown for Edison
International stock options are the differences between (i) the fair market
value of the Edison International Common Stock underlying all unexercised
in-the-money options at year-end 2000 and (ii) the exercise prices of those
options. The aggregate value at

131

year-end 2000 of all accrued dividend equivalents, exercisable and
unexercisable, for the named officers was:

$ / $
-------------

Alan J. Fohrer.............................................. 1,051,040 / 0
Edward R. Muller............................................ 419,569 / 0
Robert M. Edgell............................................ 307,255 / 0
Raymond W. Vickers.......................................... 0 / 0
Georgia R. Nelson........................................... 31,064 / 0
Mark Maisto................................................. 0 / 0

Edison Mission Energy phantom stock options were canceled during 2000
pursuant to the terms of an exchange offer described below in footnote (3).
The amounts shown in Column (e) reflect the value of the exchange offer on
December 31, 2000.

(3) In July 2000, an exchange offer was made for all outstanding Edison Mission
Energy phantom stock options. Holders of 100 percent of the outstanding
options accepted the exchange offer, and all conditions for completion of
the exchange offer were satisfied on August 8, 2000. Because all of the
phantom stock options have been terminated, no future phantom stock option
exercises will occur. The exchange offer was principally for cash with a
portion to be exchanged for stock equivalent units related to Edison
International Common Stock. The number of stock units was determined on a
basis of $20.50 per share. Each stock unit represents the value of one share
of Edison International Common Stock. The stock equivalent units accrue
dividend equivalents that are converted to additional stock equivalent
units. The vested cash, plus accrued interest from August 8, 2000, was paid
on March 13, 2001. Amounts attributable to unvested phantom stock options
will vest according to the original schedule and will be paid with interest
at that time. Participants may elect to receive payment for their stock
equivalent units on either the first- or third-year anniversary of the
August 8, 2000 exchange date. The stock equivalent units will be converted
to cash in an amount equal to the number of stock equivalent units
multiplied by the sum of the daily average of the high and low trading
prices of Edison International Common Stock on the New York Stock Exchange
for the 20 trading days preceding the elected payment date divided by 20.
Some phantom stock option holders elected to defer payments of the cash
and/or stock equivalent units, and the payment schedules for them will
differ from that described above.

(4) Edison Mission Energy made payments in settlement of the phantom stock
options held by Mr. Muller who resigned by mutual agreement in
January 2000. See the section entitled "Employment Contract and Termination
of Employment Arrangements" below for further information regarding the
terms of this agreement.

(5) Messrs. Edgell and Vickers, and Ms. Nelson accepted the exchange offer
described above in footnote (3), and their Edison Mission Energy phantom
stock options have therefore been canceled.

132

The following table presents information regarding Edison International
performance shares granted in part under the Edison International Equity
Compensation Plan during 2000 to the executive officers named in the Summary
Compensation Table above.

LONG-TERM INCENTIVE PLAN
AWARDS IN LAST FISCAL YEAR(1)

ESTIMATED FUTURE PAYOUTS UNDER
NON-STOCK PRICE-BASED PLANS
-------------------------------
(A) (B) (C) (D) (E) (F)
NUMBER OF
SHARES, UNITS PERFORMANCE OR
OR OTHER OTHER PERIOD
RIGHTS UNTIL MATURATION THRESHOLD TARGET MAXIMUM
NAME(2) (#) OR PAYOUT ($) ($) ($)
- ------- ------------- ---------------- --------- -------- --------

Alan J. Fohrer......................... 3,328 Units 2 years N/A N/A N/A
3,328 Units 3 years

Edward R. Muller....................... 3,372 Units cancelled N/A N/A N/A
3,371 Units cancelled

Robert M. Edgell....................... 2,108 Units 2 years N/A N/A N/A
2,107 Units 3 years

Raymond W. Vickers..................... 1,752 Units 2 years N/A N/A N/A
1,752 Units 3 years

Georgia R. Nelson...................... 1,726 Units 2 years N/A N/A N/A
1,726 Units 3 years

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

(1) Twenty-five percent of each Executive Officer's long-term incentive
compensation for 2000 was awarded in the form of Edison International
performance shares, with the balance being granted in the form of Edison
International Stock Options. The stock options are discussed in the
footnotes to the table above entitled "Option Grants in 2000." Performance
shares are stock-based units with each unit worth one share of Edison
International Common Stock. No dividend equivalents were included with these
grants. Two payment dates were established for this initial grant of
performance shares, each covering one-half of the performance shares
awarded. The first payment date is December 31, 2001; the second payment
date is December 31, 2002. One-half of the performance shares will be paid
in Edison International Common Stock under the Equity Compensation Plan, and
one-half will be paid in cash equal to the value of such stock outside of
the plan.

The initial grant and payment of performance shares was conditioned on
certain performance targets being met including total shareholder return.
However, effective January 2, 2001, the Edison International Compensation
and Executive Personnel Committee restructured the performance shares into
retention incentives as an inducement to Executive Officers to continue
working through resolution of the California power crisis. The downside and
upside potential was eliminated, and the performance shares will pay at
target levels on the first and second payment dates if the executive officer
remains employed by Edison Mission Energy on those dates. Pro rata payments
will be made in the event of death, disability, or involuntary severance
without cause, but no payment will be made in the event of a voluntary
separation or a separation for cause.

(2) Mr. Maisto was not awarded any Edison International performance shares in
2000.

133

RETIREMENT BENEFITS

The following table sets forth estimated gross annual benefits payable upon
retirement at age 65 to the executive officers named in the Summary Compensation
Table above in the remuneration and years of service classifications indicated.

PENSION PLAN TABLE(1)

YEARS OF SERVICE
--------------------------------------------------------------------------
REMUNERATION 10 15 20 25 30 35 40
- ------------ -------- -------- -------- -------- -------- -------- --------

$100,000 $ 25,000 $ 33,750 $ 42,500 $ 51,250 $ 60,000 $ 65,000 $ 70,000
150,000 37,500 50,625 63,750 76,875 90,000 97,500 105,000
200,000 50,000 67,500 85,000 102,500 120,000 130,000 140,000
250,000 62,500 84,375 106,250 128,125 150,000 162,500 175,000
300,000 75,000 101,250 127,500 153,750 180,000 195,000 210,000
350,000 87,500 118,125 148,750 179,375 210,000 227,500 245,000
400,000 100,000 135,000 170,000 205,000 240,000 260,000 280,000
450,000 112,500 151,875 191,250 230,625 270,000 292,500 315,000
500,000 125,000 168,750 212,500 256,250 300,000 325,000 350,000
550,000 137,500 185,625 233,750 281,875 330,000 357,500 385,000
600,000 150,000 202,500 255,000 307,500 360,000 390,000 420,000

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

(1) Estimates are based on the terms of the retirement plan, a qualified defined
benefit employee retirement plan, and the executive retirement plan, a
non-qualified supplemental executive retirement plan, currently covering
Edison Mission Energy's executive officers with the following assumptions:
(i) the qualified retirement plan will be maintained, (ii) optional forms of
payment that reduce benefit amounts have not been selected, and (iii) any
benefits in excess of limits contained in the Internal Revenue Code of 1986
and any incremental retirement benefits attributable to consideration of the
annual bonus or participation in Edison Mission Energy's deferred
compensation plans will be paid out of the executive retirement plan as
unsecured obligations of Edison Mission Energy. For purposes of the
executive retirement plan, as of December 31, 2000, the years of service
completed for: Mr. Fohrer, 27; Mr. Muller, 6; Mr. Edgell, 30; Mr. Vickers, 2
and Ms. Nelson, 30. Amounts in the Pension Plan Table include neither the
Income Continuation Plan nor the Survivor Income/Retirement Income plans,
which provide post-retirement death benefits and supplemental retirement
income benefits. These plans are discussed in "--Other Retirement Benefits."

The retirement plans provide monthly benefits at normal retirement age,
65 years, determined by a percentage of the average of the executive's highest
36 consecutive months of regular salary and, in the case of the executive
retirement plan with respect to senior officers, the executive's highest 36
consecutive months of salary and bonus prior to attaining age 65. Compensation
used to calculate combined benefits under the plans is based on base salary and
bonus as reported in the Summary Compensation Table. The service percentage is
based on 1 3/4% per year for the first 30 years of service (52 1/2% upon
completion of 30 years' service) and 1% for each year in excess of 30. Senior
officers receive an additional service percentage of 3/4 percent per year for
the first ten years of service (7.5% upon completion of ten years of service).
The actual benefit is offset by up to 40% of the executive's primary Social
Security benefits.

The normal form of benefit is a life annuity with a 50% survivor benefit
following the death of the participant. Retirement benefits are reduced for
retirement prior to age 61. The amounts shown in the Pension Plan Table above do
not reflect reductions in retirement benefits due to the Social Security offset
or early retirement.

134

Messrs. Fohrer and Edgell have elected to retain coverage under a prior
benefit program. This program provided, among other benefits, the
post-retirement benefits discussed in the following section. The retirement
benefits provided under the prior program are less than the benefits shown in
the Pension Plan Table in that they do not include the additional 7.5% service
percentage. To determine these reduced benefits, multiply the dollar amounts
shown in each column by the following factors: 10 years of service--70%,
15 years--78%, 20 years--82%, 25 years--85%, 30 years--88%, 35 years--88%, and
40 years--89%.

OTHER RETIREMENT BENEFITS

Additional post-retirement benefits are provided pursuant to the Survivor
Income Continuation Plan and the Survivor Income/Retirement Income Plan under
the Executive Supplemental Benefit Program.

The Survivor Income Continuation Plan provides a post-retirement survivor
benefit payable to the beneficiary of the executive officer following his or her
death. The benefit is approximately 23% of final compensation (salary at
retirement and the average of the three highest bonuses paid in the five years
prior to retirement) payable for ten years certain. If a named executive
officer's final annual compensation were $600,000 (the highest compensation
level in the Pension Plan Table above), the beneficiary's estimated annual
survivor benefit would be approximately $138,000. Messrs. Fohrer and Edgell have
elected coverage under this plan.

The Supplemental Survivor Income/Retirement Income Plan provides a
post-retirement survivor benefit payable to the beneficiary of the executive
officer following his or her death. The benefit is 25% of final compensation
(salary at retirement and the average of the three highest bonuses paid in the
five years prior to retirement) payable for ten years certain. At retirement, an
executive officer has the right to elect the retirement income benefit in lieu
of the survivor income benefit. The retirement income benefit is 10% of final
compensation (salary at retirement and the average of the three highest bonuses
paid in the five years prior to retirement) payable to the executive officer for
ten years certain immediately following retirement. If a named executive
officer's final annual compensation were $600,000 (the highest compensation
level in the Pension Plan Table above), the beneficiary's estimated annual
survivor benefit would be approximately $150,000. If a named executive officer
were to elect the retirement income benefit in lieu of survivor income and had
final annual compensation of approximately $600,000 (the highest compensation
level in the Pension Plan Table above), the named executive officer's estimated
annual benefit would be approximately $60,000. Messrs. Fohrer and Edgell have
elected coverage under this plan.

EMPLOYMENT CONTRACT AND TERMINATION OF EMPLOYMENT ARRANGEMENTS

EDWARD R. MULLER Mr. Muller served as the president and chief executive
officer of Edison Mission Energy beginning on August 23, 1993. On January 17,
2000, Mr. Muller resigned by mutual agreement from all positions with Edison
Mission Energy and related companies. Pursuant to the agreement, Mr. Muller was
paid $500,000 as a one-time severance payment. In addition, Edison Mission
Energy made a further payment to Mr. Muller in cancellation of his vested Edison
Mission Energy phantom stock options of $34.548 million in the aggregate. This
payment equaled an agreed upon amount per phantom stock option over the exercise
prices of Mr. Muller's vested phantom stock options and was accrued as of the
end of 1999 in anticipation of a contemplated exchange offer or future phantom
stock option exercises.

The agreement with Mr. Muller also provided for consulting services to be
rendered by him to Edison Mission Energy for a period of up to 24 months,
subject to earlier termination under certain circumstances. During the
consulting period, Edison Mission Energy will pay Mr. Muller a consulting fee at
the rate of $300,000 per annum and his unvested Edison International stock
options will

135

continue to vest ratably. Mr. Muller's unvested Edison Mission Energy phantom
stock options will also vest ratably during the consulting period and be paid
out at the same rate per phantom stock option as was paid in cancellation of his
vested phantom stock options, up to $1.712 million in the aggregate.

Under the agreement with Edison Mission Energy, Mr. Muller is subject to a
number of covenants, including non-competition, confidentiality,
non-solicitation, non-disparagement and non-interference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

CERTAIN BENEFICIAL OWNERS

Set forth below is certain information regarding each person who is known to
us to be the beneficial owner of more than five percent of our common stock.

NAME AND ADDRESS AMOUNT AND NATURE OF
TITLE OF CLASS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP PERCENT OF CLASS
- -------------- ----------------------- ----------------------- ----------------

Common Stock, no par
value................ The Mission Group 100 shares held 100%
18101 Von Karman directly and with
Avenue, Suite 1700 exclusive voting and
Irvine, California investment power
92612

MANAGEMENT

Set forth below is certain information about the beneficial ownership in
equity securities of Edison International by all directors of Edison Mission
Energy, the executive officers of Edison Mission Energy named in the Summary
Compensation Table in Item 11 and all directors and executive officers of Edison
Mission Energy as a group as of December 31, 2000. The table includes shares
that can be acquired through March 1, 2001; through the exercise of stock
options. Unless otherwise indicated, each named person has sole voting and
investment power.

AMOUNT AND NATURE OF
BENEFICIAL OWNERSHIP
AS OF DECEMBER 31,
NAME COMPANY AND CLASS OF STOCK 2000(A)
- ---- --------------------------------- --------------------

John E. Bryson................... Edison International Common Stock 916,135(b)
Dean A. Christiansen(k).......... Edison International Common Stock --
Theodore F. Craver, Jr........... Edison International Common Stock 109,751(c)
Bryant C. Danner................. Edison International Common Stock 279,590(d)
Alan J. Fohrer................... Edison International Common Stock 299,237(e)
Robert M. Edgell................. Edison International Common Stock 107,837(f)
Raymond W. Vickers............... Edison International Common Stock 24,603(g)
Georgia R. Nelson................ Edison International Common Stock 33,162(h)
Mark Maisto(l)................... Edison International Common Stock 7,548(i)
All directors and executive
officers as a group............ Edison International Common Stock 1,950,245(j)

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

(a) No named person or group owns more than 1% of the outstanding shares of the
class.

(b) Includes 16,025 shares credited under the Stock Savings Plus Plan and
839,501 shares that can be acquired through the exercise of options.
Includes 14,000 shares held as co-trustee of trust with shared voting and
investment power, 6,000 shares held as trustee of trust with shared voting
and sole investment power, 40,409 shares held as co-trustee and
co-beneficiary of trust with shared

136

voting and investment power, and 200 shares held by spouse with shared
voting and investment power.

(c) Includes 103,751 shares that can be acquired through the exercise of
options. Includes 6,000 shares held as co-trustee and co-beneficiary of
trust with shared voting and investment power.

(d) Includes 3,139 shares credited under the Stock Savings Plus Plan and 269,451
shares that can be acquired through the exercise of options.

(e) Includes 28,889 shares credited under the Stock Savings Plus Plan and
267,426 shares that can be acquired through the exercise of options.

(f) Includes 42,262 shares credited under the Stock Savings Plus Plan and 65,575
shares that can be acquired through the exercise of options.

(g) Includes 852 shares credited under the Stock Savings Plus Plan and 20,551
shares that can be acquired through the exercise of options.

(h) Includes 5,220 shares credited under the Stock Savings Plus Plan and 27,942
shares that can be acquired through the exercise of options.

(i) Includes 48 shares credited under the Stock Savings Plus Plan and 7,500
shares that can be acquired through the exercise of options.

(j) Includes 102,166 shares credited under the Stock Savings Plus Plan and
1,768,348 shares that can be acquired through the exercise of options. Stock
Savings Plus Plan shares for which instructions are not received from any
plan participant may be voted by the Stock Savings Plus Plan Trustee in its
discretion.

(k) Mr. Christiansen was elected as an independent director of Edison Mission
Energy's Board, effective January 15, 2001.

(l) Mr. Maisto resigned as president of Edison Mission Marketing &
Trading, Inc., effective February 23, 2001.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In July 1999, Edison Mission Energy made an interest-free loan to Georgia R.
Nelson, Senior Vice President and President of Midwest Generation EME, LLC, in
the amount of $179,800 in exchange for a note executed by Ms. Nelson and payable
to us 365 days following the conclusion of her assignment in Chicago, Illinois.

In October 2000, we made a loan to Gregory C. Hoppe, Vice President of
Edison Mission Energy, and Director, Australia, in the amount of $350,000 in
exchange for a secured promissory note executed by Mr. Hoppe and payable to us
at simple interest of 6.37%. The entire note, together with accrued interest, is
due January 2002.

137

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) (1) List of Financial Statements

See Index to Consolidated Financial Statements at Item 8 of this
report.

(2) List of Financial Statement Schedules

The following items are filed as a part of this report pursuant to
Item 14(d) of Form 10-K:

- The Cogeneration Group Combined Financial Statements as of
December 31, 2000, 1999 and 1998.

- Four Star Financial Statements as of December 31, 2000, 1999 and
1998.

Schedule I--Condensed Financial Information of Parent
Schedule II--Valuation and Qualifying Accounts

All other schedules have been omitted since the required information
is not present in amounts sufficient to require submission of the
schedule, or because the required information is included in the
consolidated financial statements or notes thereto.

(b) Reports on Form 8-K

No reports on Form 8-K were filed during the quarter ended December 31,
2000.

(c) Exhibits

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

2.1 Agreement for the sale and purchase of shares in First Hydro
Limited, dated December 21, 1995, between PSB Holding
Limited and First Hydro Finance Plc, incorporated by
reference to Exhibit 2.1 to Edison Mission Energy's
Form 8-K dated December 21, 1995.

2.2 Transaction Implementation Agreement, dated March 29, 1997,
between The State Electricity Commission of Victoria, Edison
Mission Energy Australia Limited, Loy Yang B Power Station
Pty Ltd, Loy Yang Power Limited, The Honorable Alan Robert
Stockdale, Leanne Power Pty Ltd and Edison Mission Energy,
incorporated by reference to Exhibit 2.2 to Edison Mission
Energy's Form 8-K dated May 22, 1997.

2.3 Stock Purchase and Assignment Agreement, dated December 23,
1998, between KES Puerto Rico, L.P., KENETECH Energy
Systems, Inc., KES Bermuda, Inc. and Edison Mission Energy
del Caribe for the (i) sale and purchase of KES Puerto
Rico, L.P.'s shares in EcoElectrica Holdings Ltd.; (ii)
assignment of KENETECH Energy Systems' rights and interests
in that certain Project Note from the Partnership; and
(iii) assignment of KES Bermuda, Inc.'s rights and interests
in that certain Administrative Services Agreement dated
October 31 1997, incorporated by reference to Exhibit 2.3 to
Edison Mission Energy's Form 10-K for the year ended
December 31, 1998.

2.4 Asset Purchase Agreement, dated August 1, 1998, between
Pennsylvania Electric Company, NGE Generation, Inc., New
York State Electric & Gas Corporation and Mission Energy
Westside, Inc., incorporated by reference to Exhibit 2.4 to
Edison Mission Energy's Form 10-K for the year ended
December 31, 1998.

2.5 Asset Sale Agreement, dated March 22, 1999, between
Commonwealth Edison Company and Edison Mission Energy as to
the Fossil Generating Assets, incorporated by reference to
Exhibit 2.5 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1998.

138

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

2.6 Agreement for the Sale and Purchase of Shares in Contact
Energy Limited, dated March 10, 1999, between Her Majesty
the Queen in Right of New Zealand, Edison Mission Energy
Taupo Limited and Edison Mission Energy, incorporated by
reference to Exhibit 2.6 to the Edison Mission Energy's
Form 10-Q for the quarter ended March 31, 1999.

2.7 Sale, Purchase and Leasing Agreement between PowerGen UK plc
and Edison First Power Limited for the purchase of the
Ferrybridge C Power Station, incorporated by reference to
Exhibit 2.7 to Edison Mission Energy's Form 8-K/A dated
July 19, 1999.

2.8 Sale, Purchase and Leasing Agreement between PowerGen UK plc
and Edison First Power Limited for the purchase of the
Fiddler's Ferry Power Station, incorporated by reference to
Exhibit 2.8 to Edison Mission Energy's Form 8-K/A dated
July 19, 1999.

2.9 Purchase and Sale Agreement, dated May 10, 2000, between
Edison Mission Energy, P & L Coal Holdings Corporation and
Gold Fields Mining Corporation, incorporated by reference to
Exhibit 2.9 to Edison Mission Energy's 10-Q for the quarter
ended September 30, 2000.

2.10 Asset Purchase Agreement dated 3 March 2000 between MEC
International B.V. and UPC International Partnership CV II,
incorporated by reference to Exhibit 10.80 to Edison Mission
Energy's Form 10-Q for the quarter ended March 31, 2000.

2.11 Stock Purchase Agreement, dated November 17, 2000 between
Mission Del Sol, LLC and Texaco Inc.*

3.1 First Amended and Restated Articles of Incorporation of
Edison Mission Energy. Originally filed with Edison Mission
Energy's Registration Statement on Form 10 to the Securities
and Exchange Commission on September 30, 1994 and amended by
Amendment No. 1 thereto dated November 19, 1994 and
Amendment No. 2 thereto dated November 21, 1994 (as so
amended, the "Form 10").*

3.1.1 Certificate of Amendment of Articles of Incorporation of
Edison Mission Energy dated October 18, 1988, originally
filed with Edison Mission Energy's Form 10.*

3.1.2 Certificate of Amendment of Articles of Incorporation of
Edison Mission Energy dated January 17, 2001.*

3.2 By-Laws of Edison Mission Energy as amended to and including
January 1, 2000.*

3.2.1 Amendment to By-Laws of Edison Mission Energy dated
January 15, 2001.*

4.1 Copy of the Global Debenture representing Edison Mission
Energy's 9 7/8% Junior Subordinated Deferrable Interest
Debentures, Series A, Due 2024, incorporated by reference to
Exhibit 4.1 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1994.

4.2 Conformed copy of the Indenture, dated as of November 30,
1994, between Edison Mission Energy and The First National
Bank of Chicago, as Trustee, incorporated by reference to
Exhibit 4.2 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1994.

4.2.1 First Supplemental Indenture, dated as of November 30, 1994,
to Indenture dated as of November 30, 1994 between Edison
Mission Energy and The First National Bank of Chicago, as
Trustee, incorporated by reference to Exhibit 4.2.1 to
Edison Mission Energy's Form 10-K for the year ended
December 31, 1994.

4.3 Indenture, dated as of June 28, 1999, between Edison Mission
Energy and The Bank of New York, as Trustee, incorporated by
reference to Exhibit 4.1 to Edison Mission Energy's
Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 18, 2000.

139

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

4.3.1 First Supplemental Indenture, dated as of June 28, 1999, to
Indenture dated as of June 28, 1999, between Edison Mission
Energy and The Bank of New York, as Trustee, incorporated by
reference to Exhibit 4.2 to Edison Mission Energy's
Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 18, 2000.

4.4 Copy of the Security representing Edison Mission Energy's
8 1/8% Senior Notes Due 2002.*

4.5 Promissory Note ($499,450,800), dated as of August 24, 2000,
by Edison Mission Energy in favor of Midwest
Generation, LLC.*

4.5.1 Schedule identifying substantially identical agreements to
Promissory Note constituting Exhibit 4.4 hereto.*

4.6 Promissory Note, dated as of June 23, 2000, by Edison
Mission Energy in favor of Midwest Generation, LLC.*

10.1 Registration Rights Agreement, dated as of June 23, 1999,
between Edison Mission Energy and the Initial Purchasers
specified therein, incorporated by reference to
Exhibit 10.1 to Edison Mission Energy's Registration
Statement on Form S-4 to the Securities and Exchange
Commission on February 18, 2000.

10.2 Power Purchase Contract between Southern California Edison
Company and Champlin Petroleum Company, dated March 8, 1985,
incorporated by reference to Exhibit 10.2 to Edison Mission
Energy's Form 10.

10.2.1 Amendment to Power Purchase Contract between Southern
California Edison Company and Champlin Petroleum Company,
dated July 29, 1985, incorporated by reference to
Exhibit 10.2.1 to Edison Mission Energy's Form 10.

10.2.2 Amendment No. 2 to Power Purchase Contract between Southern
California Edison Company and Champlin Petroleum Company,
dated October 29, 1985, incorporated by reference to
Exhibit 10.2.2 to Edison Mission Energy's Form 10.

10.4 Power Purchase Contract between Southern California Edison
Company and Imperial Energy Company, dated February 22,
1984, incorporated by reference to Exhibit 10.4 Edison
Mission Energy's Form 10.

10.4.1 Amendment to Power Purchase Contract between Southern
California Edison Company and Imperial Energy Company, dated
November 13, 1984, incorporated by reference to
Exhibit 10.4.1 to Edison Mission Energy's Form 10.

10.6 Power Purchase Contract between Southern California Edison
Company and Imperial Energy Company Niland No. 2, dated
April 16, 1985, incorporated by reference to Exhibit 10.6 to
Edison Mission Energy's Form 10.

10.7 Power Purchase Contract between Southern California Edison
Company and Chevron U.S.A. Inc., dated November 9, 1984,
incorporated by reference to Exhibit 10.7 to Edison Mission
Energy's Form 10.

10.7.1 Amendment No. 1 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated
March 29, 1985, incorporated by reference to Exhibit 10.7.1
to Edison Mission Energy's Form 10.

10.7.2 Amendment No. 2 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated
November 21, 1985, incorporated by reference to
Exhibit 10.7.2 to Edison Mission Energy's Form 10.

10.7.3 Amendment No. 3 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated
November 21, 1985, incorporated by reference to
Exhibit 10.7.3 to Edison Mission Energy's Form 10.

140

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.8 Power Purchase Contract between Southern California Edison
Company and Arco Petroleum Products Company (Watson
Refinery), incorporated by reference to Exhibit 10.8 to
Edison Mission Energy's Form 10.

10.9 Power Supply Agreement between State Electricity Commission
of Victoria, Loy Yang B Power Station Pty. Ltd. and the
Company Australia Pty. Ltd., as managing partner of the
Latrobe Power Partnership, dated December 31, 1992,
incorporated by reference to Exhibit 10.9 to Edison Mission
Energy's Form 10.

10.10 Power Purchase Agreement between P.T. Paiton Energy Company
as Seller and Perusahaan Umum Listrik Negara as Buyer, dated
February 12, 1994, incorporated by reference to
Exhibit 10.10 to Edison Mission Energy's Form 10.

10.11 Amended and Restated Power Purchase Contract between
Southern California Energy Company and Midway-Sunset
Cogeneration Company, dated May 5, 1988, incorporated by
reference to Exhibit 10.11 to Edison Mission Energy's
Form 10.

10.12 Parallel Generation Agreement between Kern River
Cogeneration Company and Southern California Energy Company,
dated January 6, 1984, incorporated by reference to
Exhibit 10.12 to Edison Mission Energy's Form 10.

10.13 Parallel Generation Agreement between Kern River
Cogeneration (Sycamore Project) Company and Southern
California Energy Company, dated December 18, 1984,
incorporated by reference to Exhibit 10.13 to Edison Mission
Energy's Form 10.

10.15 Conformed copy of the Second Amended and Restated U.S.
$500 million Bank of America National Trust and Savings
Association Credit Agreement, dated as of October 11, 1996,
incorporated by reference to Exhibit 10.15.3 to Edison
Mission Energy's Form 10-K for the year ended December 31,
1996.

10.15.1 Amendment One to Second Amended and Restated U.S.
$500 million Bank of America National Trust and Savings
Association Credit Agreement, dated as of August 17, 2000.*

10.16 Amended and Restated Ground Lease Agreement between Texaco
Refining and Marketing Inc. and March Point Cogeneration
Company, dated August 21, 1992, incorporated by reference to
Exhibit 10.16 to Edison Mission Energy's Form 10.

10.16.1 Amendment No. 1 to Amended and Restated Ground Lease
Agreement between Texaco Refining and Marketing Inc. and
March Point Cogeneration Company, dated August 21, 1992,
incorporated by reference to Exhibit 10.16 to Edison Mission
Energy's Form 10.

10.17 Memorandum of Agreement between Atlantic Richfield Company
and Products Cogeneration Company, dated September 17, 1987,
incorporated by reference to Exhibit 10.17 to Edison Mission
Energy's Form 10.

10.18 Memorandum of Ground Lease between Texaco Producing Inc. and
Sycamore Cogeneration Company, dated January 19, 1987,
incorporated by reference to Exhibit 10.18 to Edison
Mission Energy's Form 10.

10.19 Amended and Restated Memorandum of Ground Lease between
Getty Oil Company and Kern River Cogeneration Company, dated
November 14, 1984, incorporated by reference to
Exhibit 10.19 to Edison Mission Energy's Form 10.

10.20 Memorandum of Lease between Sun Operating Limited
Partnership and Midway-Sunset Cogeneration Company,
incorporated by reference to Exhibit 10.20 to Edison Mission
Energy's Form 10.

10.21 Executive Supplemental Benefit Program, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File
No. 1-2313).

141

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.22 1981 Deferred Compensation Agreement, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File
No. 1-2313).

10.23 1985 Deferred Compensation Agreement for Executives,
incorporated by reference to Exhibits to Forms 10-K filed by
SCEcorp (File No. 1-2313).

10.24 1987 Deferred Compensation Plan for Executives, incorporated
by reference to Exhibits to Forms 10-K filed by SCEcorp
(File No. 1-2313).

10.25 1988 Deferred Compensation Plan for Executives, incorporated
by reference to Exhibits to Forms 10-K filed by SCEcorp
(File No. 1- 2313).

10.26 1989 Deferred Compensation Plan for Executives, incorporated
by reference to Exhibits to Forms 10-K filed by SCEcorp
(File No. 1-9936).

10.27 1990 Deferred Compensation Plan for Executives, incorporated
by reference to Exhibits to Forms 10-K filed by SCEcorp
(File No. 1-9936).

10.28 Annual Deferred Compensation Plan for Executives,
incorporated by reference to Exhibits to Forms 10-K filed by
SCEcorp (File No. 1-9936).

10.29 Executive Retirement Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File
No. 1-2313).

10.31 Estate and Financial Planning Program for Executive
Officers, incorporated by reference to Exhibits to
Forms 10-K filed by SCEcorp (Fi1e No 1-9936).

10.32 Letter Agreement with Edward R. Muller, incorporated by
reference to Exhibit 10.32 to Edison Mission Energy's
Form 10.

10.33 Agreement with James S. Pignatelli, incorporated by
reference to Exhibit 10.33 to Edison Mission Energy's
Form 10.

10.34 Conformed copy of the Guarantee Agreement dated as of
November 30, 1994, incorporated by reference to
Exhibit 10.34 to Edison Mission Energy's Form 10.

10.35 Indenture of Lease between Brooklyn Navy Yard Development
Corporation and Cogeneration Technologies, Inc., dated as of
December 18, 1989, incorporated by reference to
Exhibit 10.35 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1994.

10.35.1 First Amendment to Indenture of Lease between Brooklyn Navy
Yard Development Corporation and Cogeneration
Technologies, Inc., dated November 1, 1991, incorporated by
reference to Exhibit 10.35.1 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1994.

10.35.2 Second Amendment to Indenture of Lease between Brooklyn Navy
Yard Development Corporation and Cogeneration
Technologies, Inc., dated June 3, 1994, incorporated by
reference to Exhibit 10.35.2 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1994.

10.35.3 Third Amendment to Indenture of Lease between Brooklyn Navy
Yard Development Corporation and Cogeneration
Technologies, Inc., dated December 12, 1994, incorporated by
reference to Exhibit 10.35.3 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1994.

10.37 Amended and Restated Limited Partnership Agreement of
Mission Capital, L.P., dated as of November 30, 1994,
incorporated by reference to Exhibit 10.37 to Edison Mission
Energy's Form 10-K for the year ended December 31, 1994.

142

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.38 Action of General Partner of Mission Capital, L.P. creating
the 9 7/8% Cumulative Monthly Income Preferred Securities,
Series A, dated as of November 30, 1994, incorporated by
reference to Exhibit 10.38 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1994.

10.39 Action of General Partner of Mission Capital, L.P., creating
the 8 1/2% Cumulative Monthly Income Preferred Securities,
Series B, dated as of August 8, 1995, incorporated by
reference to Exhibit 10.39 to Edison Mission Energy's
Form 10-Q for the quarter ended June 30, 1995.

10.40 Power Purchase Contract between ISAB Energy, S.r.l. as
Seller and Enel, S.p.A. as Buyer, dated June 9, 1995,
incorporated by reference to Exhibit 10.40 to Edison Mission
Energy's Form 10-Q for the quarter ended June 30, 1995.

10.41 400 million sterling pounds Barclays Bank Plc Credit
Agreement, dated December 18, 1995, incorporated by
reference to Exhibit 10.41 to Edison Mission Energy's
Form 8-K, dated December 21, 1995.

10.44 Guarantee by Edison Mission Energy, dated December 20, 1996,
in favor of The Fuji Bank, Limited, Los Angeles Agency, to
secure Camino Energy Company's payments pursuant to Camino
Energy Company's Credit Agreement and Defeasance Agreement,
incorporated by reference to Exhibit 10.44 to Edison Mission
Energy's Form 10-K for the year ended December 31, 1996.

10.45 Power Purchase Agreement between National Power Corporation
and San Pascual Cogeneration Company International B.V.,
dated September 10, 1997, incorporated by reference to
Exhibit 10.45 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1997.

10.46 Power Purchase Agreement between Gulf Power Generation Co.,
LTD., and Electricity Generating Authority of Thailand,
dated December 22, 1997, incorporated by reference to
Exhibit 10.46 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1997.

10.49 Equity Support Guarantee by Edison Mission Energy, dated
December 23, 1998, in favor of ABN AMRO Bank N.V., and the
Chase Manhattan Bank to guarantee certain equity funding
obligations of EcoElectrica Ltd. and EcoElectrica Holdings
Ltd. pursuant to EcoElectrica Ltd.'s Credit Agreement dated
as of October 31, 1997, incorporated by reference to
Exhibit 10.49 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1998.

10.50 Master Guarantee and Support Instrument by Edison Mission
Energy, dated December 23, 1998, in favor of ABN AMRO Bank
N.V., and the Chase Manhattan Bank to guarantee the
availability of funds to purchase fuel for the EcoElectrica
project pursuant to EcoElectrica Ltd.'s Credit Agreement
dated as of October 31, 1997 and Intercreditor Agreement
dated as of October 31, 1997, incorporated by reference to
Exhibit 10.50 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1998.

10.51 Guarantee Assumption Agreement from Edison Mission Energy,
dated December 23, 1998, under which Edison Mission Energy
assumed all of the obligations of KENETECH Energy
Systems, Inc. to Union Carbide Caribe Inc., under the
certain Guaranty dated November 25, 1997, incorporated by
reference to Exhibit 10.51 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1998.

143

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.52 Transition Power Purchase Agreement, dated August 1, 1998,
between New York State Electric & Gas Corporation and
Mission Energy Westside, Inc, incorporated by reference to
Exhibit 10.52 to Edison Mission Energy's Form 10-K for the
year ended December 31, 1998.

10.53 Transition Power Purchase Agreement, dated August 1, 1998,
between Pennsylvania Electric Company and Mission Energy
Westside, Inc., incorporated by reference to Exhibit 10.53
to Edison Mission Energy's Form 10-K for the year ended
December 31, 1998.

10.54 Guarantee, dated August 1, 1998, between Edison Mission
Energy, Pennsylvania Electric Company, NGE Generation, Inc.
and New York State Electric & Gas Corporation, incorporated
by reference to Exhibit 10.54 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1998.

10.55 Credit Agreement, dated March 18, 1999, among Edison Mission
Holdings Co. and Certain Commercial Lending Institutions,
and Citicorp USA, Inc., incorporated by reference to
Exhibit 10.55 to Edison Mission Energy's Form 8-K dated
March 18, 1999.

10.56 Guarantee and Collateral Agreement made by Edison Mission
Holdings Co., Edison Mission Finance Co., Homer City
Property Holdings, Inc., Chestnut Ridge Energy Co., Mission
Energy Westside, Inc., EME City Generation L.P. and Edison
Mission Energy in favor of United States Trust Company of
New York, dated as of March 18, 1999, incorporated by
reference to Exhibit 10.56 to Edison Mission Energy's
Form 8-K dated March 18, 1999.

10.56.1 Amendment No. 1 to the Guarantee and Collateral Agreement,
dated May 27, 1999, between Edison Mission Holdings, Edison
Mission Finance Co., Homer City Property Holdings, Inc.,
Chestnut Ridge Energy Company, Mission Energy
Westside, Inc., EME Homer City Generation L.P. and Edison
Mission Energy in favor of United States Trust Company of
New York, incorporated by reference to Exhibit 10.56.1 to
Amendment No. 1 of Edison Mission Holdings Co.'s
Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 8, 2000.

10.56.2 Open-End Mortgage, Security Agreement and Assignment of
Leases and Rents, dated March 18, 1999 from EME Homer City
Generation L.P. to United States Trust Company of New York,
incorporated by reference to Exhibit 10.56.2 to
Amendment No. 1 of Edison Mission Holdings Co.'s
Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 8, 2000.

10.56.3 Amendment No. 1 to the Open-End Mortgage, Security Agreement
and Assignment of Leases and Rents, dated May 27, 1999, from
EME Homer City Generation L.P. to United States Trust
Company of New York, incorporated by reference to
Exhibit 10.56.3 to Amendment No. 1 of Edison Mission
Holdings Co.'s Registration Statement on Form S-4 to the
Securities and Exchange Commission on February 8, 2000.

10.57 Collateral Agency and Intercreditor Agreement among Edison
Mission Holdings Co., Edison Mission Finance Co., Homer
City Property Holdings, Inc., Chestnut Ridge Energy Co.,
Mission Energy Westside, Inc., EME Homer City
Generation L.P., The Secured Parties' Representatives,
Citicorp USA, Inc. as Administrative Agent and United States
Trust Company of New York as Collateral Agent, dated as of
March 18, 1999, incorporated by reference to Exhibit 10.57
to Edison Mission Energy's Form 8-K dated March 18, 1999.

10.58 Security Deposit Agreement among Edison Mission
Holdings Co., Edison Mission Finance Co., Homer City
Property Holdings, Inc., Chestnut Ridge Energy Co., Mission
Energy Westside, Inc., EME Homer City Generation L.P. and
United States Trust Company of New York, as Collateral
Agent, dated as of March 18, 1999, incorporated by reference
to Exhibit 10.58 to Edison Mission Energy's Form 8-K dated
March 18, 1999.

144

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.58.1 Amendment No. 1 to the Security Deposit Agreement, dated
May 27, 1999, between Edison Mission Holdings, Edison
Mission Finance Co., Homer City Property Holdings, Inc.,
Chestnut Ridge Energy Company, Mission Energy
Westside, Inc., EME Homer City Generation L.P. and United
States Trust Company of New York, as Collateral Agent,
incorporated by reference to Exhibit 10.58.1 to
Amendment No. 1 of Edison Mission Holdings Co.'s
Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 8, 2000.

10.59 Credit Support Guarantee, dated as of March 18, 1999, made
by Edison Mission Energy in favor of United States Trust
Company of New York, incorporated by reference to
Exhibit 10.59 to Edison Mission Energy's Form 8-K dated
March 18, 1999.

10.59.1 Amendment No. 1 to the Credit Support Guarantee, dated
May 27, 1999, made by Edison Mission Energy in favor of
United States Trust Company of New York, incorporated by
reference to Exhibit 10.59.1 to Amendment No. 1 of Edison
Mission Holdings Co.'s Registration Statement on Form S-4
to the Securities and Exchange Commission on February 8,
2000.

10.60 Debt Service Reserve Guarantee, dated as of March 18, 1999,
made by Edison Mission Energy in favor of United States
Trust Company of New York on behalf of the various financial
institutions (Lenders) as are or may become parities to the
Credit Agreement, dated as of March 18, 1999, among Edison
Mission Holdings Co., the Lenders and Citicorp USA, Inc.,
incorporated by reference to Exhibit 10.60 to Edison Mission
Energy's Form 8-K dated March 18, 1999.

10.60.1 Amendment No. 1 to the Debt Service Reserve Guarantee, dated
May 27, 1999, made by Edison Mission Energy in favor of
United States Trust Company of New York, incorporated by
reference to Exhibit 10.60.1 to Amendment No. 1 of Edison
Mission Holdings Co.'s Registration Statement on Form S-4
to the Securities and Exchange Commission on February 8,
2000.

10.60.2 Bond Debt Service Reserve Guarantee, dated May 27, 1999,
made by Edison Mission Energy in favor of United States
Trust Company of New York, incorporated by reference to
Exhibit 10.60.2 to Amendment No. 1 of Edison Mission
Holdings Co.'s Registration Statement on Form S-4 to the
Securities and Exchange Commission on February 8, 2000.

10.60.3 Intercompany Loan Subordination Agreement, dated March 18,
1999, among Edison Mission Holdings Co., Edison Mission
Finance Co., Homer City Property Holdings, Inc., Chestnut
Ridge Energy Co., Mission Energy Westside, Inc., EME Homer
City Generation L.P. and United States Trust Company of New
York, incorporated by reference to Exhibit 10.60.3 to
Amendment No. 2 of Edison Mission Holdings Co.'s
Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 29, 2000.

10.61 Credit Agreement, dated March 18, 1999, among Edison Mission
Energy and Certain Commercial Lending Institutions, and
Citicorp USA, Inc., incorporated by reference to
Exhibit 10.61 to Edison Mission Energy's Form 8-K dated
March 18, 1999.

10.61.1 Amendment One to Credit Agreement, dated as of August 17,
2000, by and among Edison Mission Energy, Certain Commercial
Lending Institutions, and Citicorp USA, Inc., as
Administrative Agent.*

10.62 Edison Power Limited L1,150,000,000 Guaranteed Secured
Variable Rate Bonds due 2019 Guaranteed by Maplekey UK
Limited, incorporated by reference to Exhibit 10.62 to
Edison Mission Energy's Form 8-K dated Ju1y 19, 1999.

145

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.64 Coal and Capex Facility Agreement, dated July 16, 1999
between EME Finance UK Limited, Barclay's Capital and Credit
Suisse First Boston, The Financial Institutions named as
Banks, and Barclays Bank PLC as Facility Agent, incorporated
by reference to Exhibit 10.64 to Edison Mission Energy's
Form 10-Q for the quarter ended September 30, 1999.

10.65 Guarantee by Edison Mission Energy dated July 16, 1999
supporting the Coal and Capex Facility Agreement (Facility
Agreement) issued by Barclays Bank PLC to secure EME Finance
UK Limited obligations pursuant to the Facility Agreement,
incorporated by reference to Exhibit 10.65 to Edison Mission
Energy's Form 10-Q for the quarter ended September 30, 1999.

10.65.1 Amendment One to Guarantee by Edison Mission Energy
supporting the Facility Agreement, dated as of August 17,
2000.*

10.66 Debt Service Reserve Guarantee, dated as of July 16, 1999,
made by Edison Mission Energy in favor of Bank of America
National Trust and Savings Association, incorporated by
reference to Exhibit 10.66 to Edison Mission Energy's
Form 10-K for the year ended December 31, 1999.

10.71 Indenture, dated as of May 27, 1999, between Edison Mission
Holdings Co. and United States Trust Company of New York, as
Trustee, incorporated by reference to Exhibit 4.1 to Edison
Mission Holdings Co.'s Registration Statement on Form S-4 to
the Securities and Exchange Commission on December 3, 1999.

10.75 Exchange and Registration Rights Agreement, dated as of
May 27, 1999, by and among the Initial Purchasers named
therein, the Guarantors named therein and Edison Mission
Holdings Co., incorporated by reference to Exhibit 10.1 to
Edison Mission Holdings Co.'s Registration Statement on
Form S-4 to the Securities and Exchange Commission on
December 3, 1999.

10.76 Agreement among Edward R. Muller, Edison International and
Edison Mission Energy concerning the terms of Mr. Muller's
employment separation, incorporated by reference to
Exhibit 10.76 to Edison Mission Energy's Form 10-Q for the
quarter ended March 31, 2000.

10.77 Agreement By and Between S. Linn Williams and Edison Mission
Energy dated February 5, 2000, incorporated by reference to
Exhibit 10.77 to Edison Mission Energy's Form 10-Q for the
quarter ended March 31, 2000.

10.78 Form of Agreement for 2000 Employee Awards under the Equity
Compensation Plan, incorporated by reference to
Exhibit 10.78 to Edison Mission Energy's Form 10-Q for the
quarter ended March 31, 2000.

10.79 Resolution regarding the computation of disability and
survivor benefits prior to age 55 for Alan J. Fohrer,
incorporated by reference to Exhibit 10.79 to Edison Mission
Energy's Form 10-Q for the quarter ended March 31, 2000.

10.81 Edison International 2000 Equity Plan, incorporated by
reference to Exhibit 10.1 to Edison International's
Form 10-Q for the quarter ended June 30, 2000. (File
No. 1-9936).

10.82 Form of Agreement for 2000 Employee Awards under the 2000
Equity Plan, incorporated by reference to Exhibit 10.2 to
Edison International's Form 10-Q for the quarter ended
June 30, 2000. (File No. 1-9936).

10.83 Amendment No. 1 to the Edison International Equity
Compensation Plan (as restated January 1, 1998),
incorporated by reference to Exhibit 10.4 to Edison
International's Form 10-Q for the quarter ended June 30,
2000. (File No. 1-9936).

146

EXHIBIT NO. DESCRIPTION
- ------------------------- ------------------------------------------------------------

10.84 Credit Agreement, dated May 30, 2000, among Edison Mission
Energy, Certain Commercial Lending Institutions and Bank of
America, N.A., incorporated by reference to Exhibit 10.84 to
Edison Mission Energy's Form 10-Q for the quarter ended
June 30, 2000.

10.84.1 Amendment One to Credit Agreement, dated as of August 17,
2000, by and among Edison Mission Energy, Certain Commercial
Lending Institutions and Bank of America, N.A. as
Administrative Agent.*

10.85 Guarantee, dated as of June 23, 2000, in favor of EME/CDL
Trust and Midwest Generation, LLC made by Edison Mission
Energy.*

10.86 Power Purchase Agreement (Crawford, Fisk, Waukegan, Will
County, Joliet and Powerton Generating Stations), dated as
of December 15, 1999, between Commonwealth Edison Company
and Midwest Generation, LLC.*

10.87 Power Purchase Agreement (Collins Generating Station), dated
as of December 15, 1999, between Commonwealth Edison Company
and Midwest Generation, LLC.*

10.87.1 Amendment No. 1 to the Power Purchase Agreement, dated
July 12, 2000, between Commonwealth Edison Company and
Midwest Generation, LLC.*

10.87.2 Amended and Restated Power Purchase Agreement (Collins
Generating Station), dated as of September 13, 2000, between
Commonwealth Edison Company and Midwest Generation, LLC.*

10.88 Power Purchase Agreement (Crawford, Fisk, Waukegan, Calumet,
Joliet, Bloom, Electric Junction, Sabrooke and Lombard
Peaking Units), dated as of December 15, 1999, between
Commonwealth Edison Company and Midwest Generation, LLC.*

10.89 Participation Agreement, dated as of June 23, 2000, among
Midwest Generation, LLC, Edison Mission Energy, EME/CDL
Trust, the Investor party to the Trust Agreement, Wilmington
Trust Company, the Persons listed as Noteholders on
Schedule I thereto, Citicorp North America, Inc. and
Citicorp North America, Inc.*

10.89.1 Amendment One, dated as of August 17, 2000, by and among
Midwest Generation, LLC, Edison Mission Energy, EME/CDL
Trust, Citicorp Del-Lease, Inc., Wilmington Trust Company,
Certain Noteholders Party Thereto, Citicorp North
America, Inc. and Citicorp North America, Inc.*

10.90 Reimbursement Agreement, dated as of August 17, 2000,
between Edison Mission Energy and Midwest Generation, LLC.*

18.1 Preferability Letter Regarding Change in Accounting
Principle for Major Maintenance Costs, incorporated by
reference to Exhibit 18.1 to Edison Mission Energy's
Form 10-Q for the quarter ended March 31, 2000.

21 List of Subsidiaries of Edison Mission Energy.*

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

* Filed herewith.

(d) Financial Statement Schedules

Financial information for the Cogeneration Group and Four Star Oil & Gas
Company is for the years ended December 31, 2000, 1999 and 1998. The financial
statements of the Cogeneration Group present the combination of those entities
that are energy projects and 50% or less owned by Edison Mission Energy and that
met the requirements of Rule 3-09 of Regulation S-X in 2000 and 1999. The
financial statements of Four Star Oil & Gas Company represent an oil and gas
investment that is 50% or less owned by Edison Mission Energy and that met the
requirements of Rule 3-09 of Regulation S-X in 2000. There were no entities
which were 50% or less owned by Edison Mission Energy that met the requirements
of Rule 3-09 of Regulation S-X in 1998.

147

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of Edison Mission Energy:

We have audited the accompanying combined balance sheets of Kern River
Cogeneration Company (a general partnership between Getty Energy Company and
Southern Sierra Energy Company), Sycamore Cogeneration Company (a general
partnership between Texaco Cogeneration Company and Western Sierra Energy
Company), Watson Cogeneration Company (a general partnership between Camino
Energy Company and Products Cogeneration Company) and CPC Cogeneration LLC (a
Delaware limited liability company, (collectively the Cogeneration Group) as of
December 31, 2000 and 1999, and the related combined statements of income,
partners' equity and cash flows for the years then ended. These financial
statements are the responsibility of the Group's management. Our responsibility
is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally
accepted in the United States. 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 audit provides a reasonable basis
for our opinion.

In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the financial position of the Cogeneration
Group as of December 31, 2000 and 1999, and the results of its operations and
its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States.

As more fully disclosed in Note 2 to the financial statements, effective
January 1, 2000, Kern River Cogeneration Company and Sycamore Cogeneration
Company changed their method of accounting for major maintenance costs from the
"accrue in advance" method to the "expense as incurred" method.

ARTHUR ANDERSEN LLP

Los Angeles, California
March 21, 2001

148

THE COGENERATION GROUP
COMBINED STATEMENTS OF INCOME
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
-------- -------- -----------
(UNAUDITED)

OPERATING REVENUES
Sales of energy to Southern California Edison............. $601,255 $432,989 $379,852
Sales of energy to Texaco Exploration and Production...... 20,760 13,797 11,755
Sales of energy to ARCO Products Company.................. 58,941 28,961 26,229
Sales of steam to Texaco Exploration and Production
Inc..................................................... 102,561 67,357 68,441
Sales of steam to ARCO Products Company................... 70,130 51,831 46,943
-------- -------- --------

Total operating revenues................................ 853,647 594,935 533,220
-------- -------- --------

OPERATING EXPENSES
Plant and other operating expenses........................ 548,027 316,097 305,465
Depreciation and amortization............................. 23,980 22,530 22,573
Administrative and general................................ 21,516 20,712 19,884
-------- -------- --------

Total operating expenses................................ 593,523 359,339 347,922
-------- -------- --------

Income from operations.................................. 260,124 235,596 185,298
-------- -------- --------

OTHER INCOME (EXPENSE)
Interest and other income................................. 2,256 2,078 2,742
Interest expense.......................................... (2,687) (2,699) (3,327)
-------- -------- --------

Total other income (expense)............................ (431) (621) (585)
-------- -------- --------
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE................ $259,693 $234,975 $184,713
-------- -------- --------
Cumulative effect on prior years of change in accounting for
major maintenance costs (Note 2).......................... 13,808 -- --
-------- -------- --------
NET INCOME.................................................. $273,501 $234,975 $184,713
======== ======== ========

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

149

THE COGENERATION GROUP
COMBINED BALANCE SHEETS
(IN THOUSANDS)

DECEMBER 31,
-------------------
2000 1999
-------- --------

ASSETS

CURRENT ASSETS
Cash and cash equivalents................................. $ 10,703 $ 16,026
Trade receivables--affiliates............................. 196,536 70,461
Other receivables......................................... 68 510
Inventories............................................... 14,034 19,274
Prepaid expenses and other assets......................... 2,485 2,480
-------- --------

Total current assets.................................... 223,826 108,751
-------- --------
PROPERTY, PLANT AND EQUIPMENT............................... 690,344 683,744
Less accumulated depreciation and amortization............ 324,767 298,914
-------- --------

Net property, plant and equipment....................... 365,577 384,830
-------- --------

INTANGIBLE ASSETS, NET...................................... 19,441 20,566
-------- --------

TOTAL ASSETS................................................ $608,844 $514,147
======== ========
LIABILITIES, PARTNERS' EQUITY AND MEMBERS' EQUITY

CURRENT LIABILITIES
Accounts payable--affiliates.............................. $134,667 $ 44,497
Accounts payable and accrued liabilities.................. 10,408 13,493
-------- --------
Total current liabilities............................... 145,075 57,990
-------- --------

LOANS PAYABLE, net of current maturities.................... 53,733 53,733
-------- --------

MAINTENANCE ACCRUAL......................................... -- 23,039
-------- --------

Total liabilities....................................... 198,808 134,762
-------- --------

COMMITMENTS AND CONTINGENCIES (NOTE 6)

PARTNERS' EQUITY............................................ 380,349 379,385

MEMBERS' EQUITY............................................. 29,687 --
-------- --------
Total Partners' Equity and Members' Equity.............. 410,036 379,385
-------- --------
TOTAL LIABILITIES, PARTNERS' EQUITY AND MEMBERS' EQUITY..... $608,844 $514,147
======== ========

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

150

THE COGENERATION GROUP

COMBINED STATEMENTS OF PARTNERS' EQUITY AND MEMBERS' EQUITY

(IN THOUSANDS)

EDISON
MISSION
ENERGY TEXACO ARCO
AFFILIATES AFFILIATES AFFILIATES TOTAL
---------- ---------- ---------- ---------

Balances at December 31, 1997 (Unaudited).......... $ 222,417 $ 89,929 $ 95,501 $ 407,847

Cash distributions (Unaudited)..................... (98,630) (56,000) (44,370) (199,000)

Net income (Unaudited)............................. 91,634 56,218 36,861 184,713
--------- -------- -------- ---------

Balances at December 31, 1998 (Unaudited).......... 215,421 90,147 87,992 393,560

Cash distributions................................. (123,510) (71,325) (54,315) (249,150)

Net income......................................... 116,509 68,588 49,878 234,975
--------- -------- -------- ---------

Balances at December 31, 1999...................... 208,420 87,410 83,555 379,385

Cash distributions................................. (120,425) (71,425) (51,000) (242,850)

Net income......................................... 135,680 83,183 54,638 273,501
--------- -------- -------- ---------

Balances at December 31, 2000...................... $ 223,675 $ 99,168 $ 87,193 $ 410,036
========= ======== ======== =========

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

151

THE COGENERATION GROUP

COMBINED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
-----------------------------------
2000 1999 1998
--------- --------- -----------
(UNAUDITED)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................................... $ 273,501 $ 234,975 $ 184,713
Adjustments to reconcile net income to net cash provided
by operating activities:
Cumulative effect change of accounting principle....... (13,808) -- --
Depreciation and amortization.......................... 23,980 22,530 22,573
Loss on disposal of assets............................. 53 51 --
Increase in receivables.................................. (125,634) (1,847) (5,721)
Increase in inventories.................................. (1,921) (138) (2,255)
(Decrease) increase in payables.......................... 87,083 7,299 (12,335)
(Decrease) increase in maintenance accrual............... (1,670) 2,757 3,100
Other, net............................................... (4) (41) (146)
--------- --------- ---------
Net cash provided by operating activities.................. 241,580 265,586 189,929
--------- --------- ---------

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures..................................... (4,066) (4,835) (7,962)
Proceeds from disposal of assets......................... 13 9 --
--------- --------- ---------
Net cash used in investing activities...................... (4,053) (4,826) (7,962)
--------- --------- ---------

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from escrow account............................. -- 112 670
Loan repayments.......................................... -- (2,233) (13,404)
Distribution to partners................................. (242,850) (249,150) (199,000)
--------- --------- ---------
Net cash used in financing activities...................... (242,850) (251,271) (211,734)
--------- --------- ---------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....... (5,323) 9,489 (29,767)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............. 16,026 6,537 36,304
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR................... $ 10,703 $ 16,026 $ 6,537
========= ========= =========

SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid............................................ $ 2,687 $ 2,712 $ 3,378
--------- --------- ---------
Capital expenditures accrued in accounts payable......... $ -- $ 1,613 $ --
--------- --------- ---------

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

152

THE COGENERATION GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 2000, 1999 AND 1998 (UNAUDITED)

NOTE 1. GENERAL

Principles of Combination

Edison Mission Energy, a wholly owned subsidiary of The Mission Group, a
wholly owned non-utility subsidiary of Edison International, the parent holding
company of Southern California Edison Company (SCE), has a general partnership
interest in Kern River Cogeneration Company, Sycamore Cogeneration Company,
Watson Cogeneration Company and CPC Cogneration LLC(jointly referred to herein
as the Cogeneration Group). Southern Sierra Energy Company, Western Sierra
Energy Company, and Camino Energy Company are separate legal entities from
Edison Mission Energy. The accompanying combined financial statements have been
prepared for purposes of Edison Mission Energy complying with certain
requirements of the Securities and Exchange Commission.

Background of operations

Kern River Cogeneration Company, which is commonly referred to as Kern
River, is a general partnership between Getty Energy Company, a wholly owned
subsidiary of Texaco, Inc., and Southern Sierra Energy Company, a wholly owned
subsidiary of Edison Mission Energy. Kern River owns and operates a 300-MW
natural gas-fired cogeneration facility located near Bakersfield, California,
which sells electricity to Southern California Edison Company and which sells
electricity and steam to Texaco Exploration and Production, Inc., a wholly owned
subsidiary of Texaco, for use in Texaco Exploration and Production, Inc.'s
enhanced oil recovery operations in the Kern River Oil Field. Partnership income
(loss) is allocated equally to the partners.

Sycamore Cogeneration Company, which is commonly referred to as Sycamore, is
a general partnership between Texaco Cogeneration Company, a wholly owned
subsidiary of Texaco, and Western Sierra Energy Company, a wholly owned
subsidiary of Edison Mission Energy. Sycamore owns and operates a 300-MW natural
gas-fired cogeneration facility located near Bakersfield, California, which
sells electricity to Southern California Edison Company and which sells steam to
Texaco Exploration and Production, Inc. for use in Texaco Exploration and
Production, Inc.'s enhanced oil recovery operations in the Kern River Oil Field.
Partnership income (loss) is allocated equally to the partners.

Watson Cogeneration Company, which is commonly referred to as Watson, is a
general partnership between Carson Cogeneration Company, a wholly owned
subsidiary of CH-Twenty, Inc., a majority owned subsidiary of Atlantic Richfield
Company, which is commonly referred to as ARCO, Products Cogeneration Company, a
wholly owned subsidiary of ARCO and Camino Energy Company, a wholly owned
subsidiary of Edison Mission Energy. Carson Cogeneration Company, Products
Cogeneration Company and Camino Energy Company own 49 percent, 2 percent, and
49 percent, respectively. Watson owns and operates a 385-MW natural gas-fired
cogeneration facility located in Carson, California, which sells electricity to
Southern California Edison Company and which sells electricity and steam to ARCO
Products Company for use at ARCO Products Company's refinery. Partnership income
(loss) is allocated based upon the partners' respective ownership percentage.

Effective January 1, 2000, the partners in Watson created CPC Cogeneration
LLC (commonly referred to as CPC). Watson's partners own CPC in the same
percentage in which they own Watson. The general purpose of CPC is to act as an
intermediary between Watson and ARCO by purchasing power from Watson and selling
it to ARCO.

153

Current developments

The three projects making up the Cogeneration Group sell the majority of
their electricity to SCE. As a result of Southern California Edison's current
liquidity crisis, SCE has failed to make payments to qualifying facilities
supplying them power. These qualifying facilities include the Cogeneration
Group. Southern California Edison did not pay any of the amounts due to the
Cogeneration Group in January, February and March of 2001 and may continue to
miss future payments.

Southern California Edison's failure to pay has adversely affected the
operations of the Cogeneration Group. Continuing failures to pay could have an
adverse impact on the operations of the California qualifying facilities. Some
of the partnerships in the Cogeneration Group have sought to minimize their
exposure to Southern California Edison by reducing deliveries under their power
purchase agreements. It is unclear at this time what additional actions, if any,
the Cogeneration Group will take in regard to the utility's suspension of
payments due to the qualifying facilities. As a result of the utility's failure
to make payments due under these power purchase agreements, the Cogeneration
Group has called on the partners to provide additional capital to fund operating
costs of the power plants. From January 1, 2001 through March 21, 2001, partners
have contributed $93 million to meet capital calls by the Cogeneration Group.

Southern California Edison has stated that it is attempting to avoid
bankruptcy and, subject to the outcome of regulatory and legal proceedings and
negotiations regarding purchased power costs, it intends to pay all its
obligations once a permanent solution to the current energy and liquidity crisis
has been reached. It is possible that the utility will not pay all its
obligations in full. In addition, it is possible that Southern California Edison
could be forced into bankruptcy proceedings. If this were to occur, payments to
the qualifying facilities, including the Cogeneration Group, could be subject to
significant delays associated with the lengthy bankruptcy court process and may
not be paid in full. At February 28, 2001, accounts receivable from Southern
California Edison were $349 million. Furthermore, Southern California Edison's
power purchase agreements with the qualifying facilities could be subject to
review by a bankruptcy court. While we believe that the generation of
electricity by the qualifying facilities, including the Cogeneration Group, is
needed to meet California's power needs, we cannot assure you either that the
Cogeneration Group will continue to generate electricity without payment by the
purchasing utility, or that the power purchase agreements will not be adversely
affected by a bankruptcy or contract renegotiation as a result of the current
power crisis.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Inventories

Inventories are comprised of materials and supplies, and are stated at their
lower of average cost or market.

Property, Plant and Equipment

All costs, including interest and field overhead expenses, incurred during
construction and the precommission phase of the facilities were capitalized as
part of the cost of the facilities. Revenue earned during the precommission
phase was offset against the cost of the facilities. The facilities and

154

related equipment are being depreciated on a straight-line basis over
approximately 30 years, which are the estimated useful lives of the facilities.

Intangible Assets

Intangible assets are stated net of accumulated amortization of
$16.4 million and $15.2 million at December 31, 2000 and 1999, respectively, and
consist of outside boundary limit facilities, refinery infrastructure,
environment permits and land use, as outlined in the various partnership
agreements, contributed to the Cogeneration Group. All of the intangible assets
relate to the operations of the various facilities, and as a result, are being
amortized on a straight-line basis over the estimated useful life of the
facilities.

Statements of Cash Flows

For the purposes of reporting cash flows, the Cogeneration Group considers
short-term temporary cash investments with an original maturity of three months
or less to be cash equivalents.

Maintenance Accruals

Through December 31, 1999 two of the partnerships included in the
Cogeneration Group accrued for major maintenance costs during the period between
turnarounds (referred to as "accrue in advance" accounting method). Such
accounting policy has been widely used by independent power producers as well as
several other industries. In March 2000, the Securities Exchange Commission
issued a letter to the Accounting Standards Executive Committee, stating its
position that the Securities Exchange Commission Staff does not believe it is
appropriate to use an "accrue in advance" method for major maintenance costs.
The Accounting Standards Executive Committee agreed to add accounting for major
maintenance costs as part of an existing project to issue authoritative guidance
by August 2001. Due to the position taken by the Securities Exchange Commission
Staff, the Cogeneration Group voluntarily decided to change their accounting
policy to record major maintenance costs as an expense as incurred. Such change
in accounting is considered preferable based on the recent guidance provided by
the Securities Exchange Commission. In accordance with Accounting Principles
Board Opinion No. 20, "Accounting Changes," the Cogeneration Group has recorded
a $13.8 million increase to net income, as a cumulative change in the accounting
for major maintenance costs, during the year ended December 31, 2000.

Fair Value of Financial Instruments

The carrying amount of the short-term investments approximates fair value
due to the short maturities of such investments. The estimated fair value of
loans payable is discussed in Note 4.

Income Taxes

The Cogeneration Group is treated as a partnership for income tax purposes
and the income or loss of the Cogeneration Group is included in the income tax
returns of the individual partners. Accordingly, no recognition has been given
to income taxes in the financial statements.

155

NOTE 3. PROPERTY, PLANT AND EQUIPMENT

Plant and equipment consist of the following:

DECEMBER 31,
-------------------
2000 1999
-------- --------
(IN MILLIONS)

Plant and equipment
Power plant facilities.................................... $683.4 $676.5
Building, furniture and office equipment.................. 5.0 6.1
Construction in process................................... 2.0 1.1
------ ------
690.4 683.7
Less--accumulated depreciation and amortization............. 324.8 298.9
------ ------
$365.6 $384.8
====== ======

NOTE 4. LOANS PAYABLE

DECEMBER 31,
-------------------
2000 1999
-------- --------
(IN MILLIONS)

Watson project:
Note payable to ARCO (5%)................................. $27.4 $27.4

Note payable to Camino Energy Company (5%)................ 26.3 26.3
----- -----
Subtotal.................................................... 53.7 53.7
Current maturities of loans payable......................... -- --
----- -----
Total....................................................... $53.7 $53.7
===== =====

The fair value of the two Watson project notes was approximately
$34.5 million and $52.5 million at December 31, 2000 and 1999, respectively.

The Watson project notes matures in 2008.

NOTE 5. RELATED-PARTY TRANSACTIONS/CONTRACTUAL OBLIGATIONS

Operating and Other Costs

The amounts incurred by us, Texaco and their respective affiliates for
operating and other costs charged to the Cogeneration Group, which are not
disclosed elsewhere, were as follows:

(IN MILLIONS)
---------------------------------
2000 1999 1998
-------- -------- -----------
(UNAUDITED)

Texaco and affiliates................................ $3.6 $3.8 $4.1
Edison Mission Energy and affiliates................. $1.0 $1.3 $1.3

The above costs represent salaries and wages, labor related costs and
overhead of personnel and related costs for services directly performed on
behalf of each partnership. In addition, such charges from Southern California
Edison Company and its affiliates include interconnection charges which are
billed based on tariffs applicable to similar customers. Management believes the
basis for charges between affiliates is reasonable.

156

Interconnection Facilities Agreement

Under the terms of an Interconnection Facilities Agreement, one of the
partnerships within the Cogeneration Group pays a monthly charge of 1.7 percent
of the added investment, as defined, for a portion of the Interconnection
Facilities which are owned, operated and maintained by Southern California
Edison Company. Amounts paid under this agreement were $1.6 million for the
three years ended December 31, 2000, 1999 and 1998.

Fuels Management Agreement

Certain partnerships of the Cogeneration Group are party to agreements with
Texaco Natural Gas, Inc., whereby Texaco Natural Gas, Inc. is to procure and
manage all fuel-gas supplies and transportation for two of the facilities
(except fuel-gas supplies procured and delivered under tariff-gas contracts,
provided under an excepted contract or otherwise excluded from these agreements
by the mutual consent of the partners).

As of January 01, 1996, the Amended and Restated Fuel Management Agreement,
terminating on October 01, 2002, was entered into such that Texaco Natural
Gas, Inc. will receive a fixed service fee of $.0375 per MMBtu of fuel gas
supplied to certain of partnerships within the Cogeneration Group, subject to
escalation as defined in the agreement. As of December 31, 2000, Texas Natural
Gas, Inc. received a fixed service fee of $.039 per MMBtu. The amounts incurred
under the amended agreements were $315.3 million, $177.4 million and
$168.8 million, which included fees earned by Texaco Natural Gas, Inc. of
$2.5 million, $2.5 million and $2.5 million, for the three years ended
December 31, 2000, 1999 and 1998, respectively.

One of the partnerships within Cogeneration Group has entered into a fuel,
refinery gas and butane, purchase agreement with a subsidiary of ARCO. This
partnership's purchases under this agreement amounted to $155.2 million,
$32.4 million and $39.9 million for the three years ended December 31, 2000,
1999 and 1998, respectively.

Operation and Maintenance Agreement

Two of the partnerships within the Cogeneration Group have agreements with
Edison Mission Operation & Maintenance, Inc., a wholly owned subsidiary of
Edison Mission Energy, whereby Edison Mission Operation & Maintenance, Inc.
shall perform all operation and maintenance activities necessary for the
production of electricity and steam by these partnerships' facilities. The
agreements will continue until terminated by either party. Edison Mission
Operation & Maintenance, Inc. is paid for all costs incurred in connection with
operating and maintaining the facility. Edison Mission Operation &
Maintenance, Inc. may also earn incentive compensation as set forth in the
agreements. The amounts incurred by the Cogeneration Group under these
agreements were $6.3 million, $6.1 million, and $6.1 million, which included
incentive compensation earned by Edison Mission Operation & Maintenance, Inc. of
$1.0 million, $.9million and $.9 million for the three years ended December 31,
2000, 1999 and 1998, respectively.

One partnership within the Cogeneration Group has an agreement with a
subsidiary of ARCO, whereby the subsidiary shall perform all operation and
maintenance activities necessary for the production of electricity and steam by
this Cogeneration Group's facility. The agreement will continue until
termination of the Power Purchase Agreement in April 2008. The ARCO subsidiary
is reimbursed for all costs incurred in connection with operating and
maintaining the facility. The amounts incurred under this agreement were
$5.7 million, $5.6 million, and $4.8 million for the three years ended
December 31, 2000, 1999 and 1998, respectively. Additionally, ARCO provides
other ancillary services under a service contract for a fee. Total service fees
earned by ARCO were $1.4 million for the three years ended December 31, 2000,
1999 and 1998.

157

Steam Purchase and Sale Agreements

Certain partnerships within the Cogeneration Group have agreements with
Texaco Exploration and Production, Inc. for the sale of steam generated by these
partnerships' facilities. The agreements terminate 20 years from the date of the
first sale of steam there under. Texaco Exploration and Production, Inc. pays
this group a steam fuel charge based upon the quantity and quality of steam
delivered during the month, which is priced at the lesser of the current
Southern California Gas Company Border Gas Price, or the weighted average posted
price of Kern River Crude, less any severance, excise or windfall profit taxes,
and a processing charge per MMBtu as defined in the agreements. The quantity of
steam sold under this contract is expected to be sufficient for the Cogeneration
Group to maintain qualifying facility status.

These agreements have been amended whereby the partnerships will reduce a
portion of steam prices in 2000, 1999 and to a limited extent 1998. Reductions
in steam revenues based upon these agreements totaled $24.2 million,
$20.9 million and $2.2 million for the three years ended December 31, 2000, 1999
and 1998, respectively.

Parallel Generation Agreements

The Cogeneration Group has two Parallel Generation Agreements with Southern
California Edison Company for the sale of net energy and contract capacity
generated by the Cogeneration Group. The Parallel Generation Agreements will
remain in effect 20 years from the firm operation date, August 09, 1985 and
January 01, 1998, respectively. The Parallel Generation Agreements were amended
to contain energy pricing terms that maintain the intent of the Parallel
Generation Agreements' original pricing terms. Energy payments are currently
based on an energy rate that is calculated using a short-run-avoided-cost, which
is commonly referred to as SRAC, based formula, that contains a prescribed
energy rate indexed to the Southern California Border Spot Price of natural gas,
and the quantity of kilowatts delivered during on-peak, mid-peak, off-peak and
super off-peak hours. Southern California Edison Company also pays the
Cogeneration Group for firm capacity based upon a contracted amount per kilowatt
year, as defined in the Parallel Generation Agreements.

Pursuant to the amendment, on and after the date on which SRAC energy
payments are based on the clearing price paid by the independent Power Exchange
the energy pricing shall be the greater of (i) the price obtained from the
SRAC-based formula, or (ii) the average Power Exchange prices during the month
for the delivery period which are equal to the "day ahead" market clearing
prices published by the Power Exchange, or (iii) the average Power Exchange
prices during the month for the delivery period which Southern California Edison
Company uses to establish its retail rates. The SRAC-based formula energy price
will be compared to the energy price posted by the California Power Exchange
price, which will be discounted by 4%. The higher of the two prices will be used
to calculate energy payments due the partnership.

Pursuant to the amendment, the Cogeneration Group received a one-time
payment from Southern California Edison Company in the amount of $35.3 million
during 1999 that adjusted for the difference between the sum of payments made to
the Partnership for the deliveries of energy after October 14, 1996, through
March 1999, and the sum of payments for such energy determined by the SRAC-based
formula. The amount of the payment is included in 1999 sales of energy to
Southern California Edison Company.

The Parallel Generation Agreements require the Cogeneration Group to make
repayment of capacity payments to Southern California Edison Company, the power
purchaser for the project, in the event the Partnership unilaterally terminates
its Parallel Generation Agreements prior to the term of the Parallel Generation
Agreements, or reduces its electric power output below contract capacity during
the term of the Parallel Generation Agreements. Obligations that the Partnership
could be exposed to in the event of early termination under the Parallel
Generation Agreements as of December 31, 2000,

158

would be approximately $97 million. We have no reason to believe that the
Partnership will either terminate its Parallel Generation Agreements or reduce
its electric power output below contract capacity during the term of the
Parallel Generation Agreements.

Natural Gas Supply and Transportation Agreement

The Cogeneration Group purchases gas on the spot market. As such, the
Cogeneration Group may be exposed, in the short-term, to fluctuations in the
price of natural gas, however, fluctuations in the prices paid for gas are
implicitly tied to the revenues received for either power or steam under the
agreements.

NOTE 6. COMMITMENTS AND CONTINGENCIES

Ship or Pay

Pursuant to the Master Agreement, entered into as of December 01, 1994,
certain partnerships of the Cogeneration Group executed a Security of Supply
Agreement with an affiliated partnership of Edison Mission Energy and Texaco. As
such the Cogeneration Group has agreed to accept and underwrite, on a pro-rata
basis, a portion of Texaco's commitment pursuant to the Transportation Agreement
between Texaco, the Mojave Pipeline Company and the El Paso Pipeline Company,
dated February 15, 1989 and extending through March 31, 2008. The Cogeneration
Group has agreed that Mojave Pipeline Company and El Paso Pipeline Company shall
be the exclusive means of delivery for certain partnerships within the
Cogeneration Group of the lesser of 75 percent of the annual total natural gas
fuel requirements for such Cogeneration Group and 52,012,500 MMBtu per year.

Except upon the occurrence of certain permissible events, two of the
partnerships within the Cogeneration Group are subject to certain terms and
conditions, whereby failure to transport the required quantity of natural gas on
the Mojave Pipeline Company's pipeline will result in the Cogeneration Group
paying $0.63 per deficit MMBtu. Such Cogeneration Group will share any
ship-or-pay liabilities on a pro-rata basis, as defined in the Transportation
Agreement, with the affiliated partnership.

For each of the years in the three-year period ended December 31, 2000, the
transportation quantities required under the Transportation Agreement were met.
It is the opinion of the relevant Cogeneration Group's management that these
commitments will continue to be met based upon current projections for the
operations of such Cogeneration Group's facilities.

159

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders of
Four Star Oil & Gas Company:

We have audited the accompanying consolidated balance sheets of Four Star
Oil & Gas Company (a Delaware corporation) and subsidiary as of December 31,
2000 and 1999, and the related consolidated statements of income, stockholders'
equity and cash flows for each of the three years in the period ended
December 31, 2000. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 Four Star
Oil & Gas Company and subsidiary as of December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas
March 2, 2001

160

FOUR STAR OIL & GAS COMPANY

CONSOLIDATED BALANCE SHEETS--DECEMBER 31, 2000 AND 1999

(IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS)

2000 1999
-------- --------

ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................... $ 18 $ 14
Accounts receivable, trade.................................. 21 12
Affiliate receivables....................................... 63 17
Other current assets........................................ 2 2
----- -----
Total current assets...................................... 104 45
----- -----
PROPERTIES, PLANT AND EQUIPMENT (Successful-efforts
method)................................................... 941 939
Less--Accumulated depreciation, depletion and
amortization.............................................. (618) (565)
----- -----
Net properties, plant and equipment....................... 323 374
OTHER....................................................... 4 3
----- -----
Total..................................................... $ 431 $ 422
===== =====
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities.................... $ 15 $ 12
Affiliate payables.......................................... 17 7
Taxes payable............................................... 8 1
----- -----
Total current liabilities................................. 40 20
----- -----
NOTES PAYABLE TO AN AFFILIATE............................... 239 239
----- -----
DEFERRED INCOME TAXES AND OTHER............................. 54 48
----- -----
COMMITMENTS AND CONTINGENCIES (Note 10)

STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value, 400 Class A shares
authorized, 230 shares and 310 shares issued and
outstanding at December 31, 2000 and 1999, respectively;
400 Class B authorized, 300 shares issued and outstanding
at December 31, 2000 and 1999............................. -- --
Common stock, $1.00 par value, 1,000 Class A shares
authorized, issued and outstanding; 2,000 Class B shares
authorized, 239 shares and 159 shares issued and
outstanding at December 31, 2000 and 1999, respectively;
1,000 Class C shares authorized, 25 shares issued and
outstanding............................................... -- --
Additional paid-in capital.................................. 90 90
Retained earnings........................................... 8 25
----- -----
Total stockholders' equity................................ 98 115
----- -----
Total..................................................... $ 431 $ 422
===== =====

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

161

FOUR STAR OIL & GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998

(IN MILLIONS)

2000 1999 1998
-------- -------- --------

REVENUES:
Crude oil................................................... $ 71 $ 47 $ 43
Natural gas................................................. 271 139 124
Natural gas liquids......................................... 53 25 19
Gain on sale of capital assets.............................. -- 2 --
Other....................................................... 18 12 6
---- ---- ----
413 225 192
---- ---- ----
COSTS AND EXPENSES:
Cost of sales............................................... 73 36 33
General and administrative and other........................ 45 44 50
Depreciation, depletion and amortization.................... 42 45 52
Impairment of oil and gas properties........................ 25 -- --
Taxes other than income taxes............................... 28 14 12
---- ---- ----
213 139 147
---- ---- ----
OPERATING INCOME............................................ 200 86 45

INTEREST EXPENSE AND OTHER, net............................. (17) (14) (18)
---- ---- ----
INCOME BEFORE INCOME TAXES.................................. 183 72 27
---- ---- ----
PROVISION FOR (BENEFIT FROM) INCOME TAXES:
Federal--
Current..................................................... 50 11 9
Deferred.................................................... 6 5 (20)
State and local--
Current..................................................... -- -- 2
---- ---- ----
56 16 (9)
---- ---- ----
NET INCOME.................................................. $127 $ 56 $ 36
==== ==== ====

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

162

FOUR STAR OIL & GAS COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998

(IN MILLIONS, EXCEPT SHARE AMOUNTS)

COMMON SHARES PREFERRED SHARES
------------------------------ ------------------- COMMON PREFERRED PAID-IN RETAINED
CLASS A CLASS B CLASS C CLASS A CLASS B STOCK STOCK CAPITAL EARNINGS
-------- -------- -------- -------- -------- ---------- ---------- -------- --------

BALANCE, December 31,
1997.................. 1,000 117 25 352 -- $ -- $ -- $ 80 $ 8
DIVIDENDS PAID.......... -- -- -- -- -- -- -- (11) (27)
NET INCOME.............. -- -- -- -- -- -- -- -- 36
------ ---- --- ---- ---- ---------- ---------- ---- -----
BALANCE, December 31,
1998.................. 1,000 117 25 352 -- -- -- 69 17
STOCK ISSUANCE.......... -- -- -- -- 300 -- -- 21 --
DIVIDENDS PAID.......... -- -- -- -- -- -- -- -- (48)
NET INCOME.............. -- -- -- -- -- -- -- -- 56
STOCK CONVERSION........ -- 42 -- (42) -- -- -- -- --
------ ---- --- ---- ---- ---------- ---------- ---- -----
BALANCE, December 31,
1999.................. 1,000 159 25 310 300 -- -- 90 25
DIVIDENDS PAID.......... -- -- -- -- -- -- -- -- (144)
STOCK CONVERSION........ -- 80 -- (80) -- -- -- -- --
NET INCOME.............. -- -- -- -- -- -- -- -- 127
------ ---- --- ---- ---- ---------- ---------- ---- -----
BALANCE, December 31,
2000.................. 1,000 239 25 230 300 $ -- $ -- $ 90 $ 8
====== ==== === ==== ==== ========== ========== ==== =====

TOTAL
STOCKHOLDERS'
EQUITY
-------------

BALANCE, December 31,
1997.................. $ 88
DIVIDENDS PAID.......... (38)
NET INCOME.............. 36
-----
BALANCE, December 31,
1998.................. 86
STOCK ISSUANCE.......... 21
DIVIDENDS PAID.......... (48)
NET INCOME.............. 56
STOCK CONVERSION........ --
-----
BALANCE, December 31,
1999.................. 115
DIVIDENDS PAID.......... (144)
STOCK CONVERSION........ --
NET INCOME.............. 127
-----
BALANCE, December 31,
2000.................. $ 98
=====

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

163

FOUR STAR OIL & GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998

(IN MILLIONS)

2000 1999 1998
-------- -------- --------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.................................................. $ 127 $ 56 $ 36
Reconciliation of net income to net cash provided by
operating activities--
Depreciation, depletion and amortization.................... 42 45 52
Impairment of oil and gas properties........................ 25 -- --
Deferred income taxes and other............................. 4 7 (22)
Changes in operating working capital--
Gain on sale of capital assets.............................. -- (2) --
Accounts receivable, trade.................................. (9) (4) 7
Affiliate receivables....................................... (46) (3) 35
Other current assets........................................ -- (1) 9
Accounts payable and accrued liabilities.................... 3 (10) 11
Affiliate payables.......................................... 10 3 (8)
Taxes payable............................................... 7 (1) (2)
----- ----- ----
Net cash provided by operating activities................. 163 90 118
----- ----- ----

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures........................................ (21) (19) (21)
Proceeds from property sales................................ 6 4 --
----- ----- ----
Net cash used in investing activities..................... (15) (15) (21)
----- ----- ----

CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid.............................................. (144) (48) (38)
Loan principal repayment.................................... -- (309) (21)
Borrowings.................................................. -- 239 --
----- ----- ----
Net cash used in financing activities..................... (144) (118) (59)
----- ----- ----

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 4 (43) 38

CASH AND CASH EQUIVALENTS, beginning of year................ 14 57 19
----- ----- ----

CASH AND CASH EQUIVALENTS, end of year...................... $ 18 $ 14 $ 57
===== ===== ====

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash flows from operating activities include the following
net cash payments--
Income taxes................................................ $ 41 $ 12 $ 9
Interest.................................................... 18 15 20

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

164

FOUR STAR OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE COMPANY:

The use in this report of the term "Texaco" refers solely to Texaco Inc., a
Delaware corporation, and its consolidated subsidiaries or to subsidiaries and
affiliates either individually or collectively.

In 1984, Texaco acquired all of the outstanding common stock of Four Star
Oil & Gas Company (Four Star or the Company) for $10.2 billion. At the time of
acquisition, Four Star was an integrated petroleum and natural gas company
involved in the exploration for and production, transportation, refining and
marketing of crude oil and petroleum products. The acquisition was accounted for
as a purchase, and the Four Star assets and liabilities were recorded at fair
market value.

Substantially all of Four Star's assets other than certain U.S. crude oil
and natural gas exploration and producing properties and Four Star's interest in
the Partitioned Neutral Zone were disposed of either through sales to third
parties or sales and transfers to other Texaco subsidiaries in connection with
Texaco's internal reorganization accomplished in late 1984. In 1989, Four Star's
interest in the Partitioned Neutral Zone was transferred to Texaco, and Texaco
sold 20 percent of its interest in Four Star to Edison Mission Energy (Mission
Energy). Four Star was an 80 percent owned subsidiary of Texaco from
December 31, 1989, through December 30, 1991.

Through a series of stock transactions among Four Star, Texaco Exploration
and Production Inc. (TEPI), Texaco and Mission Energy, the ownership interest in
Four Star was as follows as of December 31, 1997: Texaco--31.9 percent;
TEPI--32.3 percent; and Mission Energy--35.8 percent.

During 1998, TEPI sold 20 shares of Four Star Class A common stock and 17
shares of Four Star Class B common stock to Mission Energy. This sale resulted
in the following companies holding an interest in Four Star:
Texaco--31.9 percent; TEPI--29.8 percent; and Mission Energy--38.3 percent.

In March 1999, Four Star issued 300 shares of preferred stock in exchange
for TEPI's interest in the Hugoton Gas Field. In November 1999, Mission Energy
sold 360 shares of Class A common stock to Four Star Oil & Gas Holdings Company.
In December 1999, TEPI converted 42 Class A preferred shares to Class B common
stock. The transactions in 1999 resulted in the following companies holding an
interest in Four Star: Texaco--26.5 percent; TEPI--40.4 percent; Mission
Energy--13 percent; and Four Star Oil & Gas Holdings Company (owned jointly by
Texaco Inc. and Mission Energy)--20.1 percent.

During 2000, TEPI sold 28 shares of Four Star Class A and 12 shares Class B
common stock to Mission Energy. Also, TEPI converted 80 shares of its Class A
preferred stock into Class B common stock. The transactions resulted in the
following companies holding an interest in Four Star: Texaco--26.5 percent;
TEPI--38.2 percent; Mission Energy--15.2 percent; and Four Star Oil & Gas
Holdings Company--20.1 percent.

2. SIGNIFICANT ACCOUNTING POLICIES:

CASH AND CASH EQUIVALENTS

Highly liquid investments with a maturity of three months or less when
purchased are generally considered to be cash equivalents.

PROPERTIES, PLANT AND EQUIPMENT, AND DEPRECIATION, DEPLETION AND
AMORTIZATION

The Company follows the successful-efforts method of accounting for its oil
and gas exploration and production operations.

165

Lease acquisition costs related to properties held for oil and gas
production are capitalized when incurred. Unproved properties with acquisition
costs which are individually significant are assessed on a property-by-property
basis, and a loss is recognized, by provision of a valuation allowance, when the
assessment indicates an impairment in value. Unproved properties with
acquisition costs which are not individually significant are generally
aggregated, and the portion of such costs estimated to be nonproductive, based
on historical experience, is amortized on an average holding period basis.

Exploratory costs, excluding the costs of exploratory wells, are charged to
expense as incurred. Costs of drilling exploratory wells, including
stratigraphic test wells, are capitalized pending determination of whether the
wells have found proved reserves which justify commercial development. If such
reserves are not found, the drilling costs are charged to exploratory expenses.
Intangible drilling costs applicable to productive wells and to development dry
holes, as well as tangible equipment costs related to the development of oil and
gas reserves, are capitalized.

The costs of productive leaseholds and other capitalized costs related to
production activities, including tangible and intangible costs, are amortized
principally by field on the unit-of-production basis by applying the ratio of
produced oil and gas to estimated recoverable proved oil and gas reserves.
Estimated future restoration and abandonment costs are taken into account in
determining amortization and depreciation rates.

Depreciation of properties, plant and equipment related to operations other
than production is provided generally on the group plan, using the straight-line
method, with depreciation rates based upon estimated useful lives applied to the
cost of each class of property.

Normal maintenance and repairs of properties, plant and equipment are
charged to expense as incurred. Renewals, betterments and major repairs that
materially extend the life of properties are capitalized, and the assets
replaced, if any, are retired.

When fixed capital assets representing complete units of property are
disposed of, any profit or loss after accumulated depreciation and amortization
is credited or charged to income. When miscellaneous business properties are
disposed of, the difference between asset cost and salvage value is charged or
credited to accumulated depreciation.

Four Star has adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of." In accordance with SFAS No. 121,
the Company reviews its proved oil and gas properties for impairment whenever
events and circumstances indicate a decline in the recoverability of their
carrying value. In 2000, the Company estimated the expected future cash flows of
its oil and gas properties and compared such future cash flows to the carrying
amount of the oil and gas properties to determine if the carrying amount was
recoverable. The carrying amount of one property exceeded the estimated
undiscounted future cash flows; therefore, the Company adjusted the carrying
amount of the property to fair value as determined by discounting the estimated
future cash flows. The factors used to determine fair value included, but were
not limited to, estimates of proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures and a discount rate
commensurate with the risk on those properties. As a result, the Company
recorded an impairment of $25 million on its Green Canyon 184 property in 2000
due to downward reserve revisions. The Company did not record any impairment
charge in 1999 or 1998.

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the

166

financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.

NEW ACCOUNTING PRONOUNCEMENT

In June 1998, the Financial Accounting Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. The statement also requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. SFAS No. 133, as amended by SFAS No. 137 and
SFAS No. 138, is effective for fiscal years beginning after June 15, 2000.
Adoption of this standard will not have a material effect on the Company's
financial position as the Company has no derivatives as of December 31, 2000,
except for its physical sale contracts, which qualify as normal sales.

RECLASSIFICATIONS

Certain previously reported amounts have been reclassified to conform to
current-year presentation.

3. RELATED-PARTY TRANSACTIONS:

Four Star has various business transactions with Texaco and other Texaco
subsidiaries and affiliates. These transactions principally involve sales by
Four Star of crude oil, natural gas and natural gas liquids, and billings by
Texaco for management, professional, technical and administrative services, as
well as direct charges for exploration and production-related activities.

Effective January 1, 1990, pursuant to a service agreement between Four Star
and Texaco, Four Star pays $605,000 per month, escalating 5 percent per annum
beginning in 1991 through expiration of the agreement on December 31, 1999, for
management, professional, technical and administrative services, which amount is
included as a component of operating expenses in the accompanying consolidated
statements of income. Effective July 1, 1994, the first amendment to the service
agreement provides for an additional $476,000 per month, escalating 4 percent
per annum beginning July 1, 1994, through the expiration of the agreement.

Effective December 1, 1999, Four Star entered into a service agreement with
TEPI for management, administrative, professional and technical services through
November 1, 2004. Four Star paid a monthly fixed fee of $568,417 through
December 1, 2000. Beginning November 15, 2000, the monthly fixed fee was
adjusted to $579,785. In addition, Four Star paid a monthly unit fee of $612,368
until December 1, 2000. On November 15, 2000, Four Star commenced payment of a
monthly unit fee of $645,015. This unit fee is adjusted monthly to reflect
actual oil and gas production. The monthly fixed and unit fees are included as a
component of operating expenses in the accompanying consolidated statements of
income.

As described in Note 1, in March 1999, Four Star issued 300 shares of
preferred stock in exchange for TEPI's interest in the Hugoton Gas Field.

As described in Note 1, during 2000, TEPI sold 28 shares of Four Star
Class A common stock and 12 shares of Class B common stock to Edison.

As described in Note 5, the Company entered into a loan agreement with
Texaco in September 1999.

Pursuant to the contractual agreement described in Note 10, certain tax
benefits and liabilities are assumed by Texaco.

167

Texaco has an option to purchase, for $1.0 million, Four Star's interest in
the Headlee Devonian unit. The option is exercisable during a two-year period
commencing on the date that the accumulated production of natural gas from this
unit totals 131.4 billion cubic feet (Bcf), as measured from January 1, 1990. As
of December 31, 2000, accumulated production totaled 106.5 Bcf.

The following table summarizes sales to and purchases from affiliates during
2000, 1999 and 1998 (in millions):

2000 1999 1998
--------------------- -------------------- --------------------
SALES PURCHASES SALES PURCHASES SALES PURCHASES
-------- ---------- -------- --------- -------- ---------

Texaco Natural Gas Inc................. $214.7 $ -- $123.7 $ -- $112.9 $ --
TEPI................................... .8 -- 3.5 0.8 19.1 3.7
Texaco................................. -- -- -- -- -- --
Bridgeline LLC--Texaco Pipeline........ .5 -- 0.6 -- 1.0 --
Equilon Enterprises LLC................ 70.7 -- 46.7 -- 43.2 --
------ ---------- ------ ---- ------ ----
Total................................ $286.7 $ -- $174.5 $0.8 $176.2 $3.7
====== ========== ====== ==== ====== ====

4. PROPERTIES, PLANT AND EQUIPMENT:

In 1999, Four Star sold $2 million of its properties for $4 million,
resulting in an approximate $2 million gain on the sale. In 2000, Four Star sold
$5.9 million of its properties for $6.3 million, resulting in an approximate
$400,000 gain on the sale.

5. LONG-TERM DEBT:

In September 1999, Four Star retired its loan with Chase Bank of Texas,
N.A., and entered into a loan agreement with Texaco. The outstanding balance on
the loan agreement was $239 million at December 31, 2000 and 1999. The loan
bears interest at LIBOR plus 1 percent and matures on December 31, 2005.
Interest expense during 2000, 1999 and 1998, was $18 million, $15 million and
$20 million, respectively. Four Star pays Texaco an annual facility fee and
administrative fee of $250,000.

The borrowing base will be determined on a yearly basis as set forth in the
Four Star Oil & Gas Credit Agreement dated September 30, 1999. If the
outstanding aggregate principal amount of the loan, excluding the amount of any
debt permitted by the loan agreement, exceeds the amount of the borrowing base,
Four Star must pay such excess to Texaco in four equal quarterly installments.
In 2000, Four Star's borrowing based exceeded the amount of the loan, thus no
principal payments were due.

Four Star has the right, subject to certain conditions, to prepay the note
in whole or in part prior to the maturity date.

6. CONCENTRATION OF CREDIT RISK:

Credit risk represents the accounting loss that the Company would record if
its customers failed to perform pursuant to contractual terms. Substantially all
of the Company's accounts receivable at December 31, 2000, result from sales to
the Company's two largest customers both of which are Texaco entities, as
discussed in Note 3. This concentration of customers may impact the Company's
overall credit risk either positively or negatively in that these entities may
be similarly affected by industrywide changes in economic or other conditions.
The Company's credit policy and relatively short duration of receivable mitigate
the risk of uncollected receivables. At December 31, 2000, the Company had not
incurred any credit losses on receivables.

168

Two customers, Texaco Natural Gas Inc. and Equilon Enterprises LLC,
accounted for more than 10 percent of the Company's total revenues in 2000, 1999
and 1998. Texaco Natural Gas Inc. accounted for 52 percent, 58 percent and
59 percent of sales in 2000, 1999 and 1998, respectively. Equilon Enterprises
LLC accounted for 17 percent, 22 percent and 23 percent of sales in 2000, 1999
and 1998, respectively.

7. INCOME TAXES:

The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes." Under SFAS No. 109, deferred income taxes are
determined utilizing a liability approach. This method gives consideration to
the future tax consequences associated with utilization of energy tax credits
and differences between financial accounting and tax bases of assets and
liabilities. Such differences relate mainly to depreciable and depletable
properties, intangible drilling costs and nonproductive leases.

The composition of deferred tax assets and liabilities and the related tax
effects at December 31, 2000, 1999 and 1998, were as follows (in millions):

2000 1999 1998
----------------------- ----------------------- -----------------------
CURRENT NONCURRENT CURRENT NONCURRENT CURRENT NONCURRENT
---------- ---------- ---------- ---------- ---------- ----------

Deferred tax assets related to energy
tax credits........................ $ -- $ 4.1 $ -- $ 27 $ 5 $ 27
Deferred tax liabilities related to
oil and gas properties............. -- (57.7) -- (74) -- (73)
---------- ------ ---------- ---- ---------- ----
Net deferred tax liability........... $ -- $(53.6) $ -- $(47) $ 5 $(46)
========== ====== ========== ==== ========== ====

There are differences between income taxes computed using the statutory rate
of 35 percent and the Company's effective income tax rates (31 percent in 2000,
22 percent in 1999 and 33 percent benefit in 1998), primarily as the result of
certain tax credits available to the Company. Reconciliations of income taxes
computed using the statutory rate to the effective tax rates are as follows (in
millions):

2000 1999 1998
-------- -------- --------

Income taxes computed at the statutory rate............... $64 $ 25 $ 9
Section 29 tax credits.................................... (8) (11) (19)
Other, net................................................ -- 2 1
--- ---- ----
Provision (benefit) for income taxes...................... $56 $ 16 $ (9)
=== ==== ====

8. STOCKHOLDERS' EQUITY:

In 1995, Four Star created four additional classes of stock: Class A common
(voting), Class B common (voting), Class C common, and preferred. The Class A
common stock was issued in exchange for the outstanding common stock as of
May 15, 1995. Texaco sold 6 percent of its Class A common stock to Mission
Energy effective January 1, 1995. In addition, 25 shares of Class C common
stock, 117 shares of Class B common stock and 352 shares of preferred stock were
issued in connection with property acquisitions.

In 1995, Texaco, TEPI and Mission Energy entered into an agreement granting
Mission Energy the option to purchase shares of Class A common stock or Class B
common stock of Four Star (class determined by Texaco), provided that Mission
Energy's ownership interest in the voting common stock does not exceed
49 percent of all voting common stock outstanding. The option expires on
December 23, 2006. As of December 31, 2000 and 1999, Mission Energy owned
20 percent and 18 percent, respectively, of all voting common stock outstanding.
Four Star Oil & Gas Holdings

169

Company (owned jointly by Texaco Inc. and Mission Energy) owned 29 percent of
all voting common stock in the Company.

Each share of preferred stock is convertible into one share of Class B
common stock at any time on or after December 31, 1999. Each share of preferred
stock shall be entitled to receive cumulative cash dividends of $5,112 per share
per annum, payable semiannually. As described in Note 1, TEPI converted 80
shares of its Class A preferred stock into Class B common stock. In 2000, the
Company distributed $140 million to its common stockholders and $4 million to
its preferred stockholders.

9. FAIR VALUE OF FINANCIAL INSTRUMENTS:

The Company's financial instruments consist of cash and cash equivalents,
short-term receivables and payables and long-term debt. The carrying amounts
approximate fair market value due to the highly liquid nature of the short-term
instruments and the floating interest rates associated with the long-term debt
which reflect market rates.

10. COMMITMENTS CONTINGENCIES:

Texaco has assumed any and all liabilities of Four Star incurred or
attributable to periods prior to January 1, 1990, for state and federal income,
windfall profit, ad valorem or franchise taxes, and legal proceedings. In
addition, Texaco has assumed certain of the tax liabilities of Four Star arising
from January 1, 1990, to March 1, 1990, attributable to Four Star's status as a
member of the Texaco tax consolidated group.

In the opinion of the Company, while it is impossible to ascertain the
ultimate legal and financial liability with respect to the above or other
contingent liabilities, including lawsuits, claims, guarantees, federal taxes
and federal regulations, the aggregate amount of such liability is not
anticipated to be material in relation to the financial position or results of
operations of the Company.

11. CHEVRON/TEXACO MERGER:

On October 15, 2000, Texaco and Chevron Corporation (Chevron) entered into a
merger agreement. In the merger, Texaco stockholders will receive .77 shares of
Chevron common stock for each share of Texaco common stock they own, and Chevron
stockholders will retain their existing shares.

The merger is conditioned on, among other things, the approval of the
stockholders of both companies, a pooling-of-interests accounting treatment for
the merger, and the approvals of government agencies, such as the U.S. Federal
Trade Commission (FTC). Texaco and Chevron anticipate that the FTC will require
certain divestitures in the U.S. downstream in order to address market
concentration issues, and the companies intend to cooperate with the FTC in this
process.

170

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.

EDISON MISSION ENERGY
(Registrant)

By: /s/ KEVIN M. SMITH
---------------------------------------
Kevin M. Smith
SENIOR VICE PRESIDENT AND
CHIEF FINANCIAL OFFICER

Date: March 30, 2001
---------------------------------------

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

SIGNATURE TITLE DATE
--------- ----- ----

PRINCIPAL EXECUTIVE OFFICER:

/s/ ALAN J. FOHRER
------------------------------------------- President and Chief Executive March 30, 2001
Alan J. Fohrer Officer

CONTROLLER OR PRINCIPAL ACCOUNTING OFFICER:

/s/ THOMAS E. LEGRO
------------------------------------------- Vice President and Controller March 30, 2001
Thomas E. Legro

MAJORITY OF BOARD OF DIRECTORS:

/s/ JOHN E. BRYSON
------------------------------------------- Chairman of the Board March 30, 2001
John E. Bryson

/s/ BRYANT C. DANNER
------------------------------------------- Director March 30, 2001
Bryant C. Danner

/s/ THEODORE F. CRAVER, JR.
------------------------------------------- Director March 30, 2001
Theodore F. Craver, Jr.

171

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
(IN THOUSANDS)

DECEMBER 31,
-----------------------
2000 1999
---------- ----------

ASSETS
Cash and cash equivalents................................... $ 119,377 $ 3,985
Affiliate receivables....................................... 152,244 3,904
Other current assets........................................ 4,848 2,292
---------- ----------
Total current assets........................................ 276,469 10,181
Investments in subsidiaries................................. 6,931,942 6,237,021
Other long-term assets...................................... 40,451 70,835
---------- ----------
TOTAL ASSETS................................................ $7,248,862 $6,318,037
========== ==========
LIABILITIES AND SHAREHOLDER'S EQUITY
Accounts payable and accrued liabilities.................... $ 147,641 $ 41,422
Affiliate payables.......................................... 376,400 425,237
Short-term obligations...................................... 854,676 1,122,067
Current maturities of long-term debt........................ 349,000 --
---------- ----------
Total current liabilities................................... 1,727,717 1,588,726
Long-term obligations....................................... 696,144 1,410,203
Long-term affiliate debt.................................... 1,745,000 78,000
Deferred taxes and other.................................... 131,817 172,631
---------- ----------
TOTAL LIABILITIES........................................... 4,300,678 3,249,560
COMMON SHAREHOLDER'S EQUITY................................. 2,948,184 3,068,477
---------- ----------
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY.................. $7,248,862 $6,318,037
========== ==========

172

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
--------------------------------
2000 1999 1998
--------- --------- --------

Equity in income of subsidiaries............................ $ 311,343 $ 306,603 $204,251
Operating expenses.......................................... (71,328) (225,277) (95,903)
--------- --------- --------
Operating income............................................ 240,015 81,326 108,348
Interest expense and other.................................. (229,794) (51,220) (3,808)
--------- --------- --------
Income before income taxes.................................. 10,221 30,106 104,540
Benefit for income taxes.................................... (115,031) (100,171) (27,594)
--------- --------- --------
Net income.................................................. $ 125,252 $ 130,277 $132,134
========= ========= ========

173

SCHEDULE I

EDISON MISSION ENERGY AND SUBSIDIARIES

CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

YEARS ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998
----------- ----------- ---------

Net cash provided by (used in) operating
activities........................................ $ (96,038) $ 203,658 $ 24,507
Net cash provided by financing activities........... 944,344 4,330,888 --
Net cash used in investing activities............... (732,914) (4,679,503) (490)
----------- ----------- ---------
Net increase (decrease) in cash and cash
equivalents....................................... 115,392 (144,957) 24,017
Cash and cash equivalents at beginning of period.... 3,985 148,942 124,925
----------- ----------- ---------
Cash and cash equivalents at end of period.......... $ 119,377 $ 3,985 $ 148,942
=========== =========== =========

Cash dividends received from subsidiaries........... $ 172,720 $ 233,291 $ 31,712

174

SCHEDULE II

EDISON MISSION ENERGY AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

(IN THOUSANDS)

ADDITIONS
-----------------------
BALANCE AT CHARGED TO CHARGED TO
BEGINNING COSTS AND OTHER BALANCE AT END
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS OF YEAR
- ----------- ---------- ---------- ---------- ---------- --------------

Year Ended December 31, 2000
Allowance for doubtful accounts..... $ 1,126 -- -- -- $ 1,126
Maintenance Accruals................ $25,664 -- -- $25,664(1) --

Year Ended December 31, 1999
Allowance for doubtful accounts..... -- $ 1,126 -- -- $ 1,126
Maintenance Accruals................ $26,053 $37,673 $ 54 $38,116 $25,664

Year Ended December 31, 1998
Allowance for doubtful accounts..... -- -- -- -- --
Maintenance Accruals................ $21,209 $10,663 $263 $ 6,082 $26,053

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

(1) Through December 31, 1999 we accrued for major maintenance costs during the
period between turnarounds (referred to as "accrue in advance" accounting
method). The accounting policy has been widely used by independent power
producers as well as several other industries. In March 2000, the Securities
and Exchange Commission issued a letter to the Accounting Standards
Executive Committee stating its position that the Securities and Exchange
Commission staff does not believe it is appropriate to use an "accrue in
advance" method for major maintenance costs. The Accounting Standards
Executive Committee agreed to add accounting for major maintenance costs as
part of an existing project and to issue authoritative guidance by
August 2001. Due to the position taken by the Securities and Exchange
Commission staff, we voluntarily decided to change our accounting policy to
record major maintenance costs as an expense as incurred. Such change in
accounting policy is considered preferable based on the recent guidance
provided by the Securities and Exchange Commission. In accordance with
Accounting Principles Board Opinion No. 20, "Accounting Changes," we have
recorded $17.7 million, after tax, increase to net income, as a cumulative
change in the accounting for major maintenance costs during the quarter
ended March 31, 2000.

175