Edgar Filing: EDISON MISSION ENERGY

PROSPECTUS

Offer to Exchange $400 Million 10% Senior Notes due August 15, 2008 for $400
Million
10% Senior Notes due August 15, 2008, Which Have Been Registered Under
the Securities Act of 1933, of

[EDISON MISSION ENERGY LOGO]

The exchange offer will expire at 5:00 P.M., New York City time,
on November 2, 2001, unless extended.

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

Terms of the exchange offer:

- The new notes are being registered with the Securities and Exchange
Commission and are being offered in exchange for the original notes that
were previously issued in an offering exempt from the Securities and
Exchange Commission's registration requirements. The terms of the exchange
offer are summarized below and more fully described in this prospectus.

- We will exchange all original notes that are validly tendered and not
withdrawn prior to the expiration of the exchange offer.

- You may withdraw tenders of original notes at any time prior to the
expiration of the exchange offer.

- We believe that the exchange of original notes will not be a taxable event
for U.S. federal income tax purposes, but you should see "Material United
States Federal Income Tax Considerations" on page 115 for more
information.

- We will not receive any proceeds from the exchange offer.

- The terms of the exchange notes are substantially identical to the
original notes, except that the exchange notes are registered under the
Securities Act and the transfer restrictions and registration rights
applicable to the original notes do not apply to the exchange notes.

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SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR A DISCUSSION OF THE RISKS THAT
SHOULD BE CONSIDERED BY HOLDERS PRIOR TO TENDERING THEIR ORIGINAL NOTES.

PRINCIPAL AMOUNT ANNUAL INTEREST RATE FINAL DISTRIBUTION DATE
---------------- -------------------- -----------------------

$400,000,000................................ 10% August 15, 2008

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or passed upon the
adequacy or accuracy of this prospectus. Any representation to the contrary is a
criminal offense.

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The date of this prospectus is October 2, 2001.

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS.................................. ii
AVAILABLE INFORMATION....................................... ii
INCORPORATION OF DOCUMENTS BY REFERENCE..................... iii
NOTICE TO NEW HAMPSHIRE RESIDENTS........................... iv
PROSPECTUS SUMMARY.......................................... 1
RISK FACTORS................................................ 12
USE OF PROCEEDS............................................. 20
CAPITALIZATION.............................................. 21
SELECTED CONSOLIDATED FINANCIAL DATA........................ 22
THE EXCHANGE OFFER.......................................... 23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................. 32
BUSINESS.................................................... 70
MANAGEMENT.................................................. 99
CERTAIN TRANSACTIONS AND RELATIONS WITH AFFILIATES.......... 102
DESCRIPTION OF THE NOTES.................................... 103
EXCHANGE OFFER; REGISTRATION RIGHTS......................... 113
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS.... 115
PLAN OF DISTRIBUTION........................................ 118
LEGAL MATTERS............................................... 119
EXPERTS..................................................... 119

FORWARD-LOOKING STATEMENTS

This prospectus 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
prospectus 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 on 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 or the sale of the Ferrybridge and Fiddlers' Ferry plants;

- 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, including funds to pay down or refinance our
three credit facilities maturing in October 2001.

We use words like "anticipate," "estimate," "projected," "plan," "expect,"
"will," "believe," "intend," "may," "should" and similar expressions to help
identify forward-looking statements in this prospectus.

For additional factors that could affect the validity of our forward-looking
statements, you should read "Risk Factors" beginning on page 12. 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 prospectus, 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.

AVAILABLE INFORMATION

We are subject to the informational requirements of the Securities Exchange
Act of 1934 and, in accordance with these requirements, file reports and
information statements and other information with the Securities and Exchange
Commission. These reports and information statements and other information filed
by us with the SEC can be inspected and copied at the Public Reference Section
of the SEC at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington, D.C. 20549, and at the

regional offices of the SEC located at 500 West Madison Street, Suite 1400,
Chicago, Illinois 60661. Copies of this material can be obtained from the Public
Reference Room of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549 at
prescribed rates. You may obtain information on the operation of the Public
Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a Web
site that contains reports, proxy and information statements and other materials
that are filed through the SEC's Electronic Data Gathering, Analysis and
Retrieval (EDGAR) system. This Web site can be accessed at http://www.sec.gov.

This prospectus constitutes a part of a registration statement on Form S-4
filed by us with the SEC under the Securities Act. As permitted by the rules and
regulations of the SEC, the prospectus does not contain all the information
contained in the registration statement and the exhibits and schedules to the
registration statement. Reference is made to the registration statement and its
exhibits and schedules for further information with respect to us and the
securities offered through this exchange offer. Statements contained in this
prospectus concerning the provisions of any documents filed as an exhibit to the
registration statement or otherwise filed with the SEC are not necessarily
complete, and in each instance reference is made to the copy of the document so
filed. Each of those statements is qualified in its entirety by reference to
that document.

INCORPORATION OF DOCUMENTS BY REFERENCE

The following documents filed with the SEC are incorporated by reference
into this prospectus:

(i) Our Annual Report on Form 10-K for the year ended December 31, 2000;

(ii) Our Quarterly Reports on Form 10-Q for the periods ended March 31, 2001
and June 30, 2001; and

(iii) Our Current Reports on Form 8-K, dated March 22, 2001 and August 1,
2001.

All reports and other documents we subsequently file under Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this prospectus
and prior to the date on which the exchange offer described in this prospectus
is terminated shall be deemed to be incorporated by reference into this
prospectus and to be part of this prospectus from the date we subsequently file
these reports and documents.

Copies of our Annual Report on Form 10-K for the year ended December 31,
2000, Quarterly Reports for the periods ended March 31, 2001 and June 30, 2001
and Current Reports on Form 8-K, dated March 22, 2001 and August 1, 2001, are
available, without charge, from us. You may request a copy of any of these
filings, at no cost, by writing or telephoning us at the following address or
phone number:

Edison Mission Energy
18101 Von Karman Avenue, Suite 1700
Irvine, California 92612
(949) 752-5588
Attention: Corporate Secretary

IN ORDER TO OBTAIN TIMELY DELIVERY, YOU MUST REQUEST THIS INFORMATION NO
LATER THAN 5 BUSINESS DAYS BEFORE YOU MAKE YOUR INVESTMENT DECISION.

Any statement contained in a document incorporated by reference in this
prospectus will be deemed to be modified or superseded for purposes of this
prospectus to the extent that a statement contained in this prospectus modifies
or supersedes this statement. Any statement so modified or

iii

superseded will not be deemed to constitute a part of this prospectus except as
so modified or superseded.

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NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES
WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY
REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A
FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS
TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN
EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT
THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS
OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT
IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER
OR CLIENT ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

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

PROSPECTUS SUMMARY

The following summary highlights selected information from this prospectus
and may not contain all of the information that is important to you. This
prospectus includes specific terms of the exchange notes we are offering, as
well as information regarding our business and detailed financial data. We
encourage you to read this prospectus in its entirety. You should pay special
attention to the "Risk Factors" section beginning on page 12 of this prospectus.

SUMMARY OF THE EXCHANGE OFFER

On August 10, 2001, we completed the private offering of $400 million
aggregate principal amount of 10% Senior Notes due August 15, 2008. As part of
that offering, we entered into a registration rights agreement with the initial
purchasers of these original notes in which we agreed, among other things, to
deliver this prospectus to you and to complete an exchange offer for the
original notes. Below is a summary of the exchange offer.

Securities Offered..................... Up to $400,000,000 aggregate principal amount of new 10%
Senior Notes due August 15, 2008, which have been
registered under the Securities Act. The form and terms of
these exchange notes are identical in all material
respects to those of the original notes. The exchange
notes, however, will not contain transfer restrictions and
registration rights applicable to the original notes.

The Exchange Offer..................... We are offering to exchange new $1,000 principal amount of
our 10% Senior Notes due August 15, 2008, which have been
registered under the Securities Act, for $1,000 principal
amount of our outstanding 10% Senior Notes due August 15,
2008.

In order to be exchanged, an original note must be
properly tendered and accepted. All original notes that
are validly tendered and not withdrawn will be exchanged.
As of the date of this prospectus, there are $400 million
principal amount of original notes outstanding. We will
issue exchange notes promptly after the expiration of the
exchange offer.

Resales................................ Based on interpretations by the staff of the SEC, as
detailed in a series of no-action letters issued by the
SEC to third parties, we believe that the exchange notes
issued in the exchange offer may be offered for resale,
resold or otherwise transferred by you without compliance
with the registration and prospectus delivery requirements
of the Securities Act as long as:

- you are acquiring the exchange notes in the ordinary
course of your business;

- you are not participating, do not intend to participate
and have no arrangement or understanding with any person
to participate, in a distribution of the exchange notes;
and

- you are not an "affiliate" of ours.

If you are an affiliate of ours, are engaged in or intend
to engage in or have any arrangement or understanding with
any person to participate in the distribution of the
exchange notes:

(1) you cannot rely on the applicable interpretations of
the staff of the SEC; and

(2) you must comply with the registration requirements of
the Securities Act in connection with any resale
transaction.

Each broker or dealer that receives exchange notes for its
own account in exchange for original notes that were
acquired as a result of market-making or other trading
activities must acknowledge that it will comply with the
registration and prospectus delivery requirements of the
Securities Act in connection with any offer to resell,
resale, or other transfer of the exchange notes issued in
the exchange offer, including the delivery of a prospectus
that contains information with respect to any selling
holder required by the Securities Act in connection with
any resale of the exchange notes.

Furthermore, any broker-dealer that acquired any of its
original notes directly from us:

-may not rely on the applicable interpretation of the
staff of the SEC's position contained in Exxon Capital
Holdings Corp., SEC no-action letter (April 13, 1988),
Morgan, Stanley & Co. Inc., SEC no-action letter (June 5,
1991) and Shearman & Sterling, SEC no-action letter (July
2, 1983); and

-must also be named as a selling noteholder in connection
with the registration and prospectus delivery requirements
of the Securities Act relating to any resale transaction.

Expiration Date........................ 5:00 p.m., New York City time, on November 2, 2001 unless
we extend the expiration date.

Accrued Interest on the Exchange Notes
and Original Notes................... The exchange notes will bear interest from the most recent
date to which interest has been paid on the original
notes. If your original notes are accepted for exchange,
then you will receive interest on the exchange notes and
not on the original notes.

Conditions to the Exchange Offer....... The exchange offer is subject to customary conditions. We
may assert or waive these conditions in our sole
discretion. If we materially change the terms of the
exchange offer, we will resolicit tenders of the original
notes. See "The Exchange Offer--Conditions to the Exchange
Offer" for more information regarding conditions to the
exchange offer.

Procedures for Tendering Original
Notes................................ Except as described in the section titled "The Exchange
Offer--Guaranteed Delivery Procedures," a tendering holder
must, on or prior to the expiration date:

-transmit a properly completed and duly executed letter of
transmittal, including all other documents required by
the letter of transmittal, to The Bank of New York at the
address listed in this prospectus; or

-if original notes are tendered in accordance with the
book-entry procedures described in this prospectus, the
tendering holder must transmit an agent's message to the
exchange agent at the address listed in this prospectus.

See "The Exchange Offer--Procedures for Tendering."

Special Procedures for Beneficial
Holders.............................. If you are the beneficial holder of original notes that
are registered in the name of your broker, dealer,
commercial bank, trust company or other nominee, and you
wish to tender in the exchange offer, you should promptly
contact the person in whose name your original notes are
registered and instruct that person to tender on your
behalf. See "The Exchange Offer--Procedures for
Tendering."

Guaranteed Delivery Procedures......... If you wish to tender your original notes and you cannot
deliver your notes, the letter of transmittal or any other
required documents to the exchange agent before the
expiration date, you may tender your original notes by
following the guaranteed delivery procedures under the
heading "The Exchange Offer--Guaranteed Delivery
Procedures."

Withdrawal Rights...................... Tenders may be withdrawn at any time before 5:00 p.m., New
York City time, on the expiration date.

Acceptance of Original Notes and
Delivery of Exchange Notes........... Subject to the conditions stated in the section "The
Exchange Offer--Conditions to the Exchange Offer" of this
prospectus, we will accept for exchange any and all
original notes which are properly tendered in the exchange
offer before 5:00 p.m., New York City time, on the
expiration date. The exchange notes will be delivered
promptly after the expiration date. See "The Exchange
Offer--Terms of the Exchange Offer."

Material United States Federal Income
Tax Considerations................... We believe that your exchange of original notes for
exchange notes to be issued in connection with the
exchange offer will not result in any gain or loss to you
for U.S. federal income tax purposes. See "Material United
States Federal Income Tax Considerations."

Exchange Agent......................... The Bank of New York is serving as exchange agent in
connection with the exchange offer. The address and
telephone number of the exchange agent are listed under
the heading "The Exchange Offer--Exchange Agent."

Use of Proceeds........................ We will not receive any proceeds from the issuance of
exchange notes in the exchange offer. We will pay all
expenses incident to the exchange offer. See "Use of
Proceeds" and "--The Company--Recent
Developments--Offering of Original Notes."

SUMMARY OF TERMS OF THE EXCHANGE NOTES

The form and terms of the exchange notes and the original notes are
identical in all material respects, except that transfer restrictions and
registration rights applicable to the original notes do not apply to the
exchange notes. The exchange notes will evidence the same debt as the original
notes and will be governed by the same indenture. Where we refer to "notes" in
this document, we are referring to both original notes and exchange notes.

Exchange Notes Offered................. Up to $400 million principal amount of 10% Senior Notes
due August 15, 2008.

Maturity............................... August 15, 2008.

Interest............................... Interest accrues on the principal amount of the notes at
10% per year. Interest is payable on the notes, and
interest payments will be made semi-annually in arrears on
February 15 and August 15 of each year. The first payment
will be made on February 15, 2002.

Ranking................................ The notes are senior unsecured obligations of ours and
rank equally with all of our senior unsecured indebtedness
and rank senior to our subordinated indebtedness. All
existing and future liabilities of our subsidiaries will
be effectively senior to the notes.

The indenture permits us to incur significant additional
indebtedness. See "Description of the Notes."

Ratings................................ The notes are currently rated "BBB-" by Standard & Poor's
Ratings Services and "Baa3" by Moody's Investors Service,
Inc.

Optional Redemption.................... We may redeem any or all of the notes at a redemption
price equal to the greater of:

- 100% of the principal amount of the notes being
redeemed; or

- the sum of the present values of the remaining scheduled
payments on the notes being redeemed discounted to the
date of redemption on a semiannual basis at a rate based
on the rates of U.S. Treasury securities with average
lives comparable to the remaining lives of the notes
plus 75 basis points;

plus accrued and unpaid interest on the notes being
redeemed.

THE COMPANY

THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY, AND SHOULD BE READ IN
CONJUNCTION WITH, THE MORE DETAILED INFORMATION APPEARING ELSEWHERE IN THIS
PROSPECTUS. REFERENCE IS MADE TO "RISK FACTORS" FOR A DISCUSSION OF SEVERAL
ISSUES THAT SHOULD BE CONSIDERED IN EVALUATING AN INVESTMENT IN THE NOTES. IN
THIS PROSPECTUS, THE TERMS "THE COMPANY," "WE," "OUR," "OURS" AND "US" REFER TO
EDISON MISSION ENERGY AND ITS DIRECT AND INDIRECT SUBSIDIARIES UNLESS THE
CONTEXT OTHERWISE REQUIRES.

OUR BUSINESS

We are among the largest independent producers of electricity in the world
based on megawatts, or "MW," generated, with operations in North America, Europe
and the Asia Pacific region. We develop, acquire, lease and operate electric
power generation facilities that sell power both under long-term contracts and
to wholesale markets. Our portfolio of power projects as of June 30, 2001
consisted of 33 domestic and 39 international power projects with aggregate
generation capacity of 27,798 MW, our share of which was 22,923 MW. To
complement our generation capabilities, we also market energy and manage risks
associated with energy price fluctuations in power markets open to competition.
We believe our portfolio of power projects, operating and development experience
and marketing and risk management activities enable us to meet the broad range
of our customers' needs and to maximize the value of our power projects.

We play an active role in all phases of power generation, from planning and
development to 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. Our portfolio of power
projects is strategically located in domestic and international power markets
and is diversified by fuel type. A significant portion of the capacity and
energy output from our facilities is sold under long-term contracts, which
generally provide predictable revenue streams during the contract term and
reduce our exposure to fluctuations in market prices for electricity.

The table below summarizes, as of June 30, 2001, our portfolio of power
projects.

CAPACITY (IN MW)
---------------------------------
AGGREGATE
NUMBER OF GENERATION OUR
REGION PROJECTS CAPACITY SHARE
------ --------- ---------- --------

North America................................... 33 15,221 13,302
Europe.......................................... 26 7,284 6,840
Asia Pacific.................................... 13 5,293 2,781
-- ------ ------
Total......................................... 72 27,798 22,923
== ====== ======

Subsequent to June 30, 2001, we sold our 50% interest in the Saguaro project
for $67 million. We have also entered into agreements, subject to obtaining
consents from third parties and other conditions precedent to closing, for the
sale of our interests in the EcoElectrica, Gordonsville, Commonwealth Atlantic,
James River and Nevada Sun-Peak projects. In addition, we are currently offering
for sale our interest in the Brooklyn Navy Yard project. We expect the proceeds
from the sale of our interests in the above projects, if completed, will be in
excess of their book value with respect to those projects ($482 million at
June 30, 2001). We are also offering for sale the Ferrybridge and Fiddler's
Ferry plants in the United Kingdom. If we are successful in selling our
Ferrybridge and Fiddler's Ferry plants, it is likely that we will not recover
any of our investment in the subsidiary that owns these assets. At June 30,
2001, that investment was approximately $974 million. The aggregate generation
capacity set forth in the above table will be reduced by 5,800 MW, of which our
share is 4,892 MW, if we are successful in completing the sale of our interests
in all of these projects.

OUR MARKET OPPORTUNITY

Historically, electric utility monopolies were vertically integrated,
meaning that they were responsible for building and maintaining power generation
facilities, building and maintaining transmission and distribution
infrastructure and selling power to residential, commercial and industrial
customers, generally referred to as "retail sales," at regulated rates. However,
governmental and regulatory initiatives have caused significant changes in this
historical model of the electric power industry. For example, in the United
States, the passage of the Public Utility Regulatory Policies Act of 1978
encouraged the development of independent power producers 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
non-utility power producers, known as qualifying facilities, under specified
conditions. The passage of the Energy Policy Act of 1992 further encouraged the
development of independent power producers 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. In 1998, utility deregulation in
several states led utilities to divest generating assets, which has created
additional new opportunities for growth of independent power producers in the
United States. For example, we acquired fossil fuel power generating plants
located in Illinois after deregulation in that state. Finally, there has been a
movement in many foreign countries toward privatization of the power generation
industry.

These initiatives have changed the fundamental structure of the electric
power industry in the affected markets by replacing vertically integrated
operations with stratified businesses organized by power generation,
transmission, distribution and retail sales operations. We conduct most of our
operations within the power generation business line. We believe that we are
well-positioned to continue to realize opportunities as a result of these
changes in the industry.

In addition to the opportunities created by the governmental and regulatory
initiatives described above, the demand for power continues to increase as a
result of economic growth both domestically and abroad. In some countries,
including the United States, investment in new power generation facilities has
not been adequate to support the increase in demand, resulting in shortages of
electricity in many regions. As a result, there exists an increased need for
companies like ours that have a large portfolio of power projects to provide
dependable power both to the wholesale energy market and directly to
distribution companies. In addition, this situation provides us with the
opportunity to expand the generation capacity of our existing sites and to
develop new generation projects to meet market demands.

OUR STRATEGY

Our business goal is to continue 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.

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 our merchant plants sell power
into markets without the certainty of long-term contracts, we conduct power
marketing, trading, and risk 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.

Due to the impact of the California power crisis, our current operational
focus is on enhancing the performance of our existing portfolio of power
projects, expanding our generation capacity at existing sites and maintaining
our credit quality. Our long-term strategy is to continue to grow our business
while maintaining investment grade credit ratings.

OUR COMPETITIVE STRENGTHS

We believe that our competitive strengths advantageously position us to
enhance our financial performance, expand our business and pursue strategic
opportunities in independent power markets both domestically and abroad. Our key
competitive strengths are summarized below.

- GLOBAL PRESENCE. We are among the largest independent power producers in
the world based on MW generated. As of June 30, 2001, we owned interests
in 33 domestic operating projects with total generating capacity of 15,221
MW, of which our share was 13,302 MW. In addition, as of June 30, 2001, we
owned interests in 39 projects outside the United States with total
generation capacity of 12,577 MW, of which our share was 9,621 MW. In
assembling and operating this global portfolio, we have gained substantial
experience and expertise in major U.S. and foreign power markets and, as a
result, enjoy access to a broader range of development and acquisition
opportunities worldwide.

- DIVERSIFIED ASSET PORTFOLIO. In addition to owning interests in power
generation facilities in 10 countries worldwide, our portfolio of power
projects is also diversified by fuel type. As of June 30, 2001, our
portfolio of power projects was comprised of 57% coal, 30% natural gas,
11% hydroelectric and 2% oil and geothermal, as a percentage of our share
of aggregate generation capacity. The fuel type diversification of our
portfolio of power projects reduces our exposure to shortages or other
disruptions in the market for any particular fuel source. The geographic
diversification of our portfolio of power projects spreads our operations
across different regions and market segments, thereby allowing us to
participate in multiple segments of the domestic and international power
markets and reducing the level of risk presented by any particular market.

- BALANCED CONTRACT POSITION. The contract status of our generation
facilities reflects a blend of long-term contracts and sales from our
merchant plants. As of June 30, 2001, the majority of our MW were subject
to long-term power purchase agreements, which provide us with contracted
revenue streams from those generation facilities. Our remaining MW were
generated by our merchant plants which sell power into wholesale power
markets. This blend of contracted and merchant generation provides for a
stream of contract revenue while allowing us the flexibility to sell power
into wholesale markets.

- DISCIPLINED MARKETING AND RISK MANAGEMENT ACTIVITIES. We use a disciplined
approach to energy marketing and risk management that is centered around
our merchant plants and is designed primarily to stabilize and enhance the
operational and financial performance of those facilities. These
activities also reduce our exposure to energy price fluctuations.

- STRONG AND EXPERIENCED PROJECT MANAGEMENT TEAM. We have an experienced
project management team that continues to focus on our core competencies
and to draw upon our significant domestic and international development
and operating experience.

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THE CALIFORNIA POWER CRISIS AND OUR RELATIONSHIP WITH AFFECTED AFFILIATES

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, including us, and
others. Given these and other payment defaults, Southern California Edison could
face bankruptcy at any time. Pacific Gas and Electric filed a voluntary
bankruptcy petition on April 6, 2001. See "Risk Factors--The ongoing California
power crisis has had, and is likely to continue to have, an adverse impact on
us."

Edison International, our ultimate parent company, is also the corporate
parent of Southern California Edison. Both Edison International and Southern
California Edison have faced and continue to face material operating disruptions
as a result of the California power crisis. The chart below, although not a
complete representation of our corporate structure, generally outlines our
relationship with Edison International and Southern California Edison.

[CHART]

Through the enactment of provisions in our articles of incorporation and
bylaws and other measures, (1) we have taken steps to preserve our investment
grade credit ratings and (2) we have attempted to isolate ourselves from
potential bankruptcies of Edison International, Southern California Edison and
their subsidiaries by preserving us as a stand-alone entity, despite the current
credit difficulties of Edison International and Southern California Edison. For
a discussion of the specific provisions, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--The California Power
Crisis and Our Response." However, we cannot assure you that these measures will
effectively isolate us from the credit downgrades or the potential bankruptcies
of Edison International, Southern California Edison or any of their
subsidiaries.

In addition to the risks described above, the California power crisis has
adversely affected our liquidity. We have undertaken a series of initiatives in
response. These initiatives are summarized below.

- On August 10, 2001, we issued and sold the original notes, the proceeds of
which were used to permanently repay $400 million of outstanding
indebtedness.

- On April 5, 2001, we issued $600 million of 9.875% senior notes due
April 15, 2011, the proceeds of which were used to permanently repay
$225 million of outstanding indebtedness and to provide for additional
working capital.

- On June 25, 2001, we completed the sale of a 50% interest in the Sunrise
project to Texaco Power & Gasification Holdings Inc. for $84 million.

- On June 29, 2001, we completed the sale of our 25% interest in the
Hopewell project to our existing partner for $26.5 million.

- On September 20, 2001, we completed the sale of our 50% interest in the
Saguaro project for $67 million.

- We have agreed to sell our interests in the EcoElectrica, Gordonsville,
Commonwealth Atlantic, James River and Nevada Sun-Peak projects. We are
also engaged in a competitive bidding process through an investment bank
for the disposition of our ownership interest in the Brooklyn Navy Yard
project. For more information on which projects are currently offered for
sale, see "Business--Regional Overview of Business Segments."

- In September 2001, we entered into a new $750 million corporate credit
facility. We used this new credit facility, together with other corporate
funds, to replace our existing corporate credit facilities. For more
information on our financing plans, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources--Corporate Financing Plans."

As a result of our focus on short-term initiatives designed to improve our
liquidity, our current focus is on operating our existing project portfolio and
focusing our development activities on expanding our generation capacity at
existing sites rather than pursuing acquisition and development opportunities at
our historical levels. Upon the improvement of our financial position through
the completion of the initiatives discussed above and the resolution of the
California power crisis, we plan to focus to a greater extent on the development
of new projects.

For a more detailed description of the California power crisis, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--The California Power Crisis and Our Response." In addition, for a
further discussion of our transactions and relations with our affiliates, see
"Business--Our Relationship with Affected Affiliates."

MISSION ENERGY HOLDING FINANCING

On June 8, 2001, Edison International created Mission Energy Holding Company
as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset
is our common stock. On July 2, 2001, Mission Energy Holding engaged in a
$1,185 million debt financing, and pledged our common stock to the lenders as
security for their debt obligations. The majority of the proceeds of this
financing was ultimately used by Edison International to repay a portion of its
indebtedness maturing in 2001. The Mission Energy Holding financing documents
contain restrictions on our ability and the ability of our subsidiaries to enter
into specified transactions or engage in specified business activities and
require in some instances that we obtain the approval of the Mission Energy
Holding board of directors for these transactions. Our articles of incorporation
bind us to the restrictions in the Mission Energy Holding financing documents by
restricting our ability to enter into specified transactions or engage in
specified business activities, as set forth in the Mission Energy Holding
financing documents, without shareholder approval. See "Risk
Factors--Restrictions in our articles of incorporation, our credit facilities
and the Mission Energy Holding financing documents limit or prohibit us from
entering into specified transactions that we otherwise may enter into."

RECENT DEVELOPMENTS

OFFERING OF ORIGINAL NOTES

On August 10, 2001, we issued and sold the original notes. We used the
proceeds of that offering, which were $400 million, to repay a portion of our
indebtedness under our three corporate credit facilities. See "Use of Proceeds."

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

Edison Mission Energy is 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.

We are considering a possible reincorporation in the State of Delaware. The
reincorporation would be accomplished through a merger with Edison Mission
Energy, a Delaware corporation and wholly-owned subsidiary of ours, in which the
Delaware corporation would be the surviving corporation. The Order Authorizing
Disposition of Jurisdictional Facilities issued by the Federal Energy Regulatory
Commission on August 24, 2001 found that our proposed transaction was consistent
with the public interest and granted our request for authority to complete the
reincorporation, subject to certain conditions. We cannot assure you that a
rehearing of the August 24, 2001 order will not be requested, and cannot provide
any assurances as to the outcome of such hearing or as to the consummation of
the reincorporation.

SUMMARY CONSOLIDATED FINANCIAL DATA

The following table sets forth our selected consolidated financial data for
the periods indicated. The selected consolidated financial data for the six
month period ended June 30, 2001 were derived from the unaudited consolidated
financial statements of Edison Mission Energy and our consolidated subsidiaries.
The selected consolidated financial data for the years ended December 31, 1996,
1997, 1998, 1999 and 2000 were derived from the audited consolidated financial
statements of Edison Mission Energy and our consolidated subsidiaries. These
selected consolidated financial data are qualified in their entirety by the more
detailed information and financial statements, including the notes to that
information and those financial statements, included in the documents
incorporated by reference in this prospectus.

SIX MONTHS
ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
---------------------------------------------------- -------------------
1996 1997 1998 1999 2000 2000 2001
-------- -------- -------- -------- -------- -------- --------
(DOLLARS IN MILLIONS) (DOLLARS IN
MILLIONS)
(UNAUDITED)

INCOME STATEMENT DATA:
Operating revenues................................... $ 843.6 $ 975.0 $ 893.8 $1,635.9 $3,241.0 $1,460.2 $1,585.8
Operating expenses:
Depreciation and amortization...................... 89.9 102.8 87.3 190.2 382.1 202.5 174.3
Other operating expenses........................... 386.6 478.3 456.0 1,019.3 2,028.1 1,004.7 1,105.3
------- ------- ------- -------- -------- -------- --------
Total operating expenses......................... 476.5 581.1 543.3 1,209.5 2,410.2 1,207.2 1,279.6
------- ------- ------- -------- -------- -------- --------
Operating income..................................... 367.1 393.9 350.5 426.4 830.8 253.0 306.2
Interest expense..................................... (164.2) (223.5) (196.1) (375.5) (721.5) (370.5) (328.9)
Interest and other income............................ 40.7 53.9 50.9 55.8 74.0 42.4 34.7
Minority interest.................................... (69.5) (38.8) (2.8) (3.0) (3.2) (1.4) (7.5)
------- ------- ------- -------- -------- -------- --------
Income (loss) before income taxes.................... 174.1 185.5 202.5 103.7 180.1 (76.5) 4.5
Provision (benefit) for income taxes................. 82.0 57.4 70.4 (40.4) 72.5 (27.8) 1.7
------- ------- ------- -------- -------- -------- --------
Income (loss) before accounting changes, and
extraordinary loss................................. 92.1 128.1 132.1 144.1 107.6 (48.7) 2.8
Cumulative effect on prior years of changes, in
accounting, net of tax............................. -- -- -- (13.8) 17.7 17.7 6.0
Extraordinary loss on early extinguishment of debt,
net of income tax benefit.......................... -- (13.1) -- -- -- -- --
------- ------- ------- -------- -------- -------- --------
Net income (loss).................................... $ 92.1 $ 115.0 $ 132.1 $ 130.3 $ 125.3 $ (31.0) $ 8.8
======= ======= ======= ======== ======== ======== ========
OTHER DATA:
Ratio of earnings to fixed charges(1)(2)............. 1.42 1.64 1.69 1.18 1.23 0.81 0.93

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

(1) For purposes of computing the ratio of earnings to fixed charges, earnings
are divided by fixed charges. "Earnings" represents the aggregate of our
income before income taxes (adjusted for the excess or shortfall of
dividends or other distributions over equity in earnings of less than
50%-owned entities), amortization of previously capitalized interest and
fixed charges (net of capitalized interest). "Fixed Charges" represents
interest (whether expressed or capitalized), the amortization of debt
discount and interest portion of rental expense.

(2) For the six month periods ended June 30, 2001 and 2000, there was a fixed
charge deficiency of $25.4 million and $76.6 million, respectively.

AS OF DECEMBER 31, AS OF
------------------------------------------------------ JUNE 30,
1996 1997 1998 1999 2000 2001
-------- -------- -------- --------- --------- -------------
(IN MILLIONS) (IN MILLIONS)
(UNAUDITED)

BALANCE SHEET DATA:
Assets................................................... $5,152.5 $4,985.1 $5,158.1 $15,534.2 $15,017.1 $15,257.3
Current liabilities...................................... 270.9 339.8 358.7 1,772.8 3,911.0 3,031.2
Long-term obligations, less current portion.............. 2,419.9 2,532.1 2,396.4 7,439.3 5,334.8 6,349.3
Preferred securities of subsidiaries..................... 150.0 150.0 150.0 476.9 326.8 325.7
Shareholder's equity..................................... 1,019.9 826.6 957.6 3,068.5 2,948.2 2,672.6

RISK FACTORS

In addition to the information contained elsewhere in this prospectus, the
following risk factors should be carefully considered in evaluating the exchange
offer and an investment in the notes. The following risk factors, other than
"--You may have difficulty selling the notes that you do not exchange,"
generally apply to the original notes as well as the exchange notes.

WE HAVE A SUBSTANTIAL AMOUNT OF INDEBTEDNESS.

As of June 30, 2001, we had $2.5 billion of debt which is recourse to Edison
Mission Energy and $6.1 billion of debt which is non-recourse to Edison Mission
Energy but is recourse to our subsidiaries appearing on our consolidated balance
sheet. The indenture governing the notes will not impose limitations on our
ability or the ability of our subsidiaries to incur additional indebtedness.

A failure to repay, extend or refinance our existing debt as required by
their terms could result in an event of default under the credit facilities. An
event of default under the credit facilities would trigger cross-defaults under
agreements to which our subsidiaries are party. This would have the effect of
not permitting distributions from our subsidiaries, which would have a negative
impact on our liquidity and on our ability to make debt service payments on the
notes.

Our substantial amount of debt and financial obligations presents the risk
that we might not have sufficient cash to service our indebtedness, including
the notes, and that our existing corporate and project debt could limit our
ability to grow our business, to compete effectively or to operate successfully
under adverse economic conditions. See "Prospectus Summary--Our Strategy."

RESTRICTIONS IN OUR ARTICLES OF INCORPORATION, OUR CREDIT FACILITIES AND THE
MISSION ENERGY HOLDING FINANCING DOCUMENTS LIMIT OR PROHIBIT US FROM ENTERING
INTO SPECIFIED TRANSACTIONS THAT WE OTHERWISE MAY ENTER INTO.

The financing documents entered into by Mission Energy Holding contain
financial and investment covenants restricting us and our subsidiaries. Our
articles of incorporation bind us to the provisions in the Mission Energy
Holding financing documents by restricting our ability to enter into specified
transactions and engage in specified business activities, as contemplated by the
Mission Energy Holding financing documents, without shareholder approval. The
instruments governing our indebtedness also contain financial and investment
covenants. Restrictions contained in the documents described in the preceding
sentences could affect, and in some cases significantly limit or prohibit, our
and our subsidiaries' ability to, among other things, incur and prepay debt,
make capital expenditures, pay dividends and make other distributions, make
investments, create liens, sell assets, enter into sale and leaseback
transactions, issue equity interests, enter into transactions with affiliates,
create restrictions on the ability to pay dividends or make other distributions
and engage in mergers and consolidations.

IN A BANKRUPTCY OF MISSION ENERGY HOLDING, CREDITORS OF MISSION ENERGY HOLDING
MAY PETITION TO HAVE OUR ASSETS AND LIABILITIES CONSOLIDATED WITH THOSE OF
MISSION ENERGY HOLDING.

Although we operate independently of Mission Energy Holding, our articles of
incorporation bind us to the restrictions in the Mission Energy Holding
financing documents by restricting our ability to enter into specified
transactions or engage in specified business activities, as set forth in the
Mission Energy Holding financing documents, without shareholder approval. For
more information on the restrictions in the Mission Energy Holding financing
documents, see "--Restrictions in our articles of incorporation, our credit
facilities and the Mission Energy Holding financing documents limit or prohibit
us from entering into specified transactions that we otherwise may enter into."
In the event of a bankruptcy of Mission Energy Holding, creditors of Mission
Energy Holding might seek to have a bankruptcy court substantively consolidate
our assets and liabilities with those of Mission Energy Holding. In the event
that a bankruptcy court were to require substantive consolidation, our assets
and

those of Mission Energy Holding would be treated as if they were held by, and
our liabilities and those of Mission Energy Holding would be treated as if they
were incurred by, a single entity, and we may be financially unable to pay
amounts due on the notes.

RATINGS OF THE NOTES AND OUR CREDIT RATINGS ARE SUBJECT TO CHANGE, AND A
DOWNGRADE OF OUR CREDIT RATING BELOW INVESTMENT GRADE COULD HAVE AN ADVERSE
IMPACT ON US.

In January 2001, Standard & Poor's and Moody's downgraded our senior
unsecured credit ratings to "BBB-" from "A-" and to "Baa3" from "Baa1,"
respectively. Our credit ratings remain "investment grade." However, we cannot
assure you that Standard & Poor's and/or Moody's will not downgrade us below
investment grade, whether as a result of the California power crisis or
otherwise. If we are downgraded below investment grade, 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 (see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Other Commitments--Credit Support for Trading and Price Risk
Management Activities"); and

- 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 project owned by CBK Power
Co. Ltd. in the Philippines, which equity contribution would otherwise be
payable as currently scheduled in 2003.

A further 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, adversely affect our trading operations, and have an
adverse impact on us and our subsidiaries, particularly in light of the capital
intensive nature of our business. Furthermore, a downgrade in our credit rating
could adversely affect our ability to make debt service payments on the notes.

Standard & Poor's and Moody's have assigned ratings to the notes of "BBB-"
and "Baa3," respectively. A rating is not a recommendation to purchase, hold or
sell notes, because a rating does not address market price or suitability for a
particular investor. We cannot assure you that a rating will remain for any
given period of time or that a rating will not be lowered or withdrawn entirely
by a rating agency if, in its judgment, circumstances in the future so warrant.

THE ONGOING CALIFORNIA POWER CRISIS HAS HAD, AND IS LIKELY TO CONTINUE TO HAVE,
AN ADVERSE IMPACT ON US.

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 California utilities, Southern California Edison and Pacific
Gas and Electric, 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, including us, and others. Given these and other
payment defaults, Southern California Edison could face bankruptcy at any time.
Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001.
Edison International, our ultimate parent company, is also the corporate parent
of Southern California Edison.

Southern California Edison's current financial condition has had, and may
continue to have, an adverse impact on Edison International's credit quality.
Both Standard & Poor's and Moody's have

lowered the credit ratings of Edison International and Southern California
Edison to substantially below investment grade levels.

Through the enactment of ring-fencing provisions in our articles of
incorporation and bylaws and other measures, (1) we have taken steps to preserve
our investment grade credit ratings and (2) we have attempted to isolate
ourselves from potential bankruptcies of Edison International, Southern
California Edison and their subsidiaries by preserving us as a stand-alone
entity, despite the current credit difficulties of Edison International,
Southern California Edison and their subsidiaries. These measures are discussed
under "Management's Discussion and Analysis of Financial Condition and Results
of Operations--The California Power Crisis and Our Response." 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 or any of their subsidiaries. A downgrade in our credit ratings could
increase our cost of capital, increase our credit support obligations, make
efforts to raise capital more difficult and have an adverse impact on our
business and operations.

In addition, we have partnership interests in eight partnerships which own
power plants in California and 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. As a
result of Southern California Edison's and Pacific Gas and Electric's current
liquidity crises, each of these utilities has failed to make full payment under
these contracts. As of June 30, 2001, our share of amounts owed to these
partnerships under the power purchase contracts with Southern California Edison
was approximately $301 million. In addition, our share of amounts owed to these
partnerships under the power purchase contracts with Pacific Gas and Electric
was approximately $23 million at the petition date. We have not established any
reserves for these amounts. 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 June 30, 2001 was $607 million.
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 to June 30, 2001, subsidiaries of ours have made equity contributions
totaling approximately $134 million to meet capital calls by the partnerships.
Although Southern California Edison has been paying the partnerships for power
delivered after March 27, 2001 and Pacific Gas and Electric has paid for power
delivered after April 6, 2001 and four partnerships have entered into settlement
agreements with Southern California Edison with respect to past due payments,
our subsidiaries and the other partners may be required to make additional
capital contributions to the partnerships if the utilities fail to make future
payments. Given the severity of the California power crisis and the uncertainty
surrounding any potential legislative or other solution to the crisis, it is
impossible at this time to determine whether we will receive any or all amounts
owed to us under the power purchase contracts or the settlement agreements,
whether the utilities will continue to operate under the contracts and to what
extent our investment in the affected partnerships will be impaired.

For a more complete discussion, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations--The California Power Crisis and
Our Response." In addition, we cannot assure you that future developments with
respect to the California power crisis will not have a material impact on our
business and operations and our ability to meet our obligations under the notes.

WE CANNOT PREDICT THE OUTCOME OF THE ONGOING CALIFORNIA PUBLIC UTILITIES
COMMISSION INVESTIGATION.

On April 3, 2001, the California Public Utilities Commission adopted an
order instituting an investigation. The order reopens past Commission decisions
authorizing the California investor-owned utilities to form holding companies
and initiates an investigation into:

- whether the holding companies violated requirements to give "first
priority" to the capital needs of their respective utility subsidiaries in
the recent energy crisis;

- whether ring-fencing actions by Edison International and PG&E Corporation
and their respective non-utility affiliates (including us) were an
asset-shielding action that also violated requirements to give "first
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 later-discovered violations of laws or Commission rules and
decisions; and

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

On June 6, 2001, in response to motions filed by the three holding companies
(including Edison International) to dismiss the investigation for lack of
subject matter jurisdiction, the Commission issued for comment a draft decision,
which concluded, among other matters, that applicable law permits the
Commission, even if the normal common law prerequisites for piercing the
corporate structures are absent, to disregard the corporate forms within the
holding company system "to reach the assets of or challenge the behaviors of
entities within the holding company system" in order to protect ratepayers.
Commissioner Henry Duque has issued a draft alternate decision that would grant
the three holding companies' motions to dismiss the order as to themselves,
finding lack of subject matter jurisdiction over them, and would direct the
Commission's general counsel to file an action in state court to enforce the
holding company conditions, if necessary. The alternate, as well as the draft
decision that would deny the motions to dismiss, are presently on the
Commission's agenda for its October 11 meeting. Either would require a vote of 3
out of 5 commissioners in order to be adopted. We are not a party to this
investigatory proceeding. We cannot predict whether, when or in what form this
order will be adopted, or what direct or indirect effects any subsequent action
taken by the Commission in such proceeding or in any other action or proceeding,
in reliance on the principles articulated in this order and in other applicable
authority, may have on Edison International or on us.

OUR ABILITY TO MEET CASH REQUIREMENTS DEPENDS UPON THE PERFORMANCE OF OUR
SUBSIDIARIES.

The original notes are, and the exchange notes will be, exclusively our
obligations and will not be the obligations of any of our subsidiaries. Because
substantially all our operations are conducted by our subsidiaries and other
investments, our cash flow and ability to service our indebtedness or otherwise
meet our financial obligations, including our ability to pay the interest on,
and principal of, the notes when due, are dependent upon the ability of our
subsidiaries and other investments to generate earnings and have available cash
sufficient to allow such entities to pay dividends and make distributions to us.
In general, the ability of our subsidiaries and other investments to generate
earnings and have available cash is subject to a number of risks, many of which
are beyond our control, including changes in the regulatory environment,
increased competition, fuel and energy commodity prices, natural disaster,
foreign operating risk, financial environment and a downturn in the economy. In
particular, as discussed above, the California power crisis has had, and is
likely to continue to have, an adverse impact on our California partnership
investments and may adversely affect the ability of these partnerships to make
distributions to us. See "--The ongoing California power crisis has had, and is
likely to continue to have, an adverse impact on us."

In addition, financing agreements of our subsidiaries and other investments
generally place limitations on the ability of those subsidiaries and other
investments 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 or the applicable subsidiary's or other investment's 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 less than all the equity interests 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 outside the United States. We have a general policy of not
repatriating funds from our foreign projects and instead reinvest those funds in
the foreign projects. Therefore, any distributions from foreign operations could
be subject to additional taxes in the United States upon repatriation. These
taxes could materially affect the amount of cash realized by us from dividends
from our foreign projects. Accordingly, we cannot assure you that we will
receive sufficient distributions from our subsidiaries to pay debt service on
the notes when due.

Any right of ours to receive any assets of any of our subsidiaries upon any
liquidation or reorganization of a subsidiary, and the consequent right of
holders of the notes to participate in distributions of, or to realize proceeds
from, those assets, 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, is not in compliance with a
required financial ratio under the financing documents related to the
acquisition of the Fiddler's Ferry and Ferrybridge plants located in the United
Kingdom. In July, Edison First Power received a waiver for its breach of the
required financial ratios under the financing documents. We cannot assure you
that Edison First Power's creditors will continue to waive its non-compliance
with requirements under the financing documents or that Edison First Power will
satisfy the financial ratios in the future. The financing documents stipulate
that a breach of the financial ratio covenant constitutes an immediate event of
default. If the event of default is not waived, the financing parties are
entitled to enforce their security interest over Edison First Power's assets,
including the Fiddler's Ferry and Ferrybridge plants. We are currently offering
for sale through a competitive bidding process the Fiddler's Ferry and
Ferrybridge plants. If we are successful at selling the Ferrybridge and
Fiddler's Ferry plants, it is likely that we will not recover any of our
investment in the subsidiary that owns these assets. At June 30, 2001, that
investment was $974 million. We plan to use the proceeds from the sale, if it
occurs, to repay a portion or all of the indebtedness of the project. If we
retain these plants, it is likely that we will not satisfy the interest coverage
requirement set forth in the financing documents. See "Management Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Subsidiary Financing Plans--Status of Edison First Power Loan."

Our subsidiary, Doga Enerji, owns 80% of the Doga project in Turkey. Doga
Enerji has experienced delays in receiving payments from its power purchaser
Turkiye Elektrik, A.S., also referred to as TEAS. Doga Enerji is in the process
of determining whether these delays will materially adversely affect the future
cash flow projections for the project. Until such determination is made, Doga
Enerji will not make a distribution for 2001. While such payment obligations are
guaranteed by the Turkish Treasury, we cannot assure you that TEAS will make its
payments on a timely basis.

SOME OF OUR PROJECTS OPERATE WITHOUT LONG-TERM POWER PURCHASE AGREEMENTS AND ARE
OR WILL BE SUBJECT TO MARKET FORCES THAT AFFECT THE PRICE OF POWER.

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.

A SUBSTANTIAL AMOUNT OF OUR REVENUES ARE DERIVED UNDER POWER PURCHASE AGREEMENTS
WITH A SINGLE CUSTOMER, AND WE MAY BE ADVERSELY AFFECTED IF THAT CUSTOMER FAILS
TO FULFILL ITS OBLIGATIONS UNDER THOSE POWER PURCHASE AGREEMENTS.

For the first six months of 2001, 27% of our consolidated operating
revenues, and in 2000, 33% of our consolidated operating revenues, were derived
under three power purchase agreements between our subsidiary, Midwest
Generation, LLC, and Exelon Generation Company, a subsidiary of Exelon
Corporation. These agreements were entered into in connection with our
December 1999 acquisition of fossil fuel power generating plants in Illinois,
which we refer to as 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
Generation are earned from capacity and energy provided by the Illinois Plants
under three five-year power purchase agreements expiring in 2004. Exelon
Generation has the option to terminate two of these agreements in their entirety
or with respect to any generating unit or units in each of 2002, 2003 and 2004.
In June 2001, Exelon Generation provided our subsidiary with notice to continue
the agreement related to the coal units for 2002. If Exelon Generation were to
fail or become unable to fulfill or choose to terminate some of 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 RISKS OF DOING BUSINESS IN FOREIGN
COUNTRIES.

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 or that these hedges will be available
throughout the term of the notes.

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 Financial Condition and Results of Operations--
Contingencies--Paiton."

COMPETITION COULD ADVERSELY AFFECT OUR BUSINESS.

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.

WE ARE SUBJECT TO EXTENSIVE GOVERNMENT REGULATION.

Our operations are subject to extensive regulation by governmental agencies
in each of the countries in which we conduct operations. See
"Business--Regulatory Matters." 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
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
"Business--Regulatory Matters--U.S. Federal Energy Regulation."

GENERAL OPERATING RISKS AND CATASTROPHIC EVENTS MAY ADVERSELY AFFECT OUR
PROJECTS.

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 and,
as a result, our ability to make payments under the notes. 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 entity could
cause us to lose our interest in the project.

OUR FUTURE ACQUISITIONS AND DEVELOPMENT PROJECTS MAY NOT BE SUCCESSFUL.

Our long-term 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 and Southern
California Edison, 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.

YOU MAY HAVE DIFFICULTY SELLING THE NOTES THAT YOU DO NOT EXCHANGE.

If you do not exchange your original notes for exchange notes in the
exchange offer, you will continue to be subject to the restrictions on transfer
of your original notes described in the legend on your original notes. The
restrictions on transfer of your original notes arise because we issued the
original notes under exemptions from, or in transactions not subject to, the
registration requirements of the Securities Act and applicable state securities
laws. In general, you may only offer or sell the original notes if they are
registered under the Securities Act and applicable state securities laws, or
offered and sold under an exemption from these requirements. We do not intend to
register the original notes under the Securities Act. To the extent original
notes are tendered and accepted in the exchange offer, the trading market, if
any, for the original notes would be adversely affected. See "The Exchange
Offer--Consequences of Exchanging or Failing to Exchange Original Notes."

YOU MAY FIND IT DIFFICULT TO SELL YOUR NOTES BECAUSE THERE IS NO EXISTING
TRADING MARKET FOR THE EXCHANGE NOTES.

You may find it difficult to sell your notes because an active trading
market for the notes may not develop. The exchange notes are being offered to
the holders of the original notes. The original notes were issued on August 10,
2001, primarily to a small number of institutional investors. After the exchange
offer, the trading market for the remaining untendered original notes could be
adversely affected.

There is no existing trading market for the exchange notes. We do not intend
to apply for listing or quotation of the exchange notes on any exchange, and so
we do not know the extent to which investor interest will lead to the
development of a trading market or how liquid that market might be. Although
Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith
Barney Inc., SGC Owen Securities Corporation, TD Securities (USA) Inc., and
Westdeutsche Landesbank Girozentrale (Dusseldorf), the initial purchasers in the
private offering of the original notes, have informed us that they intend to
make a market in the exchange notes, they are not obligated to do so, and any
market-making may be discontinued at any time without notice. As a result, the
market price of the exchange notes could be adversely affected.

BROKER-DEALERS OR NOTEHOLDERS MAY BECOME SUBJECT TO THE REGISTRATION AND
PROSPECTUS DELIVERY REQUIREMENTS OF THE SECURITIES ACT.

Any broker-dealer that:

- exchanges its original notes in the exchange offer for the purpose of
participating in a distribution of the exchange notes; or

- resells exchange notes that were received by it for its own account in the
exchange offer,

may be deemed to have received restricted securities and may be required to
comply with the registration and prospectus delivery requirements of the
Securities Act in connection with any resale transaction by that broker-dealer.
Any profit on the resale of the exchange notes and any commission

or concessions received by a broker-dealer may be deemed to be underwriting
compensation under the Securities Act.

In addition to broker-dealers, any noteholder that exchanges its original
notes in the exchange offer for the purpose of participating in a distribution
of the exchange notes may be deemed to have received restricted securities and
may be required to comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any resale transaction by
that noteholder.

USE OF PROCEEDS

We will not receive any proceeds from the exchange offer. In consideration
for issuing the exchange notes, we will receive in exchange original notes of
like principal amount, the terms of which are identical in all material respects
to the exchange notes. The original notes surrendered in exchange for exchange
notes will be retired and canceled and cannot be reissued. Accordingly, issuance
of the exchange notes will not result in any increase in our indebtedness. We
have agreed to bear the expenses of the exchange offer. No underwriter is being
used in connection with the exchange offer.

On August 10, 2001, we issued and sold the original notes in an offering
exempt from registration under the Securities Act. We used the proceeds of that
offering, which were $400 million, to repay indebtedness under our corporate
credit facilities.

The interest rates on the credit facilities that we repaid averaged
approximately 5.84% per annum as of the dates they were repaid. All of these
credit facilities are scheduled to expire in October 2001. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources--Corporate Financing Plans."

CAPITALIZATION

The following table sets forth our consolidated capitalization as of
June 30, 2001 and as adjusted to reflect the issuance of the original notes and
application of the proceeds from the issuance of the original notes as discussed
in "Use of Proceeds." The information in the table is qualified in its entirety
by the more detailed information included in the documents incorporated by
reference in this prospectus. See "Incorporation of Documents by Reference."

CAPITALIZATION AS OF JUNE 30, 2001

AS
ACTUAL ADJUSTED(1)
--------- -----------
(IN MILLIONS)

Short-Term Indebtedness................................ $ 819.8 $ 419.8
Long-Term Indebtedness(2).............................. 7,763.1 8,163.1
Preferred Securities................................... 325.7 325.7
--------- ---------
Total Indebtedness................................. 8,908.6 8,908.6
Shareholder's Equity................................... 2,672.6 2,672.6
--------- ---------
Total Capitalization............................... $11,581.2 $11,581.2
========= =========

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

(1) Represents the capitalization at June 30, 2001, as adjusted for the net
proceeds from the issuance of the original notes.

(2) Includes current maturities of long-term indebtedness.

SELECTED CONSOLIDATED FINANCIAL DATA

INCOME STATEMENT DATA:
Operating revenues................................... $ 843.6 $ 975.0 $ 893.8 $1,635.9 $3,241.0 $1,460.2 $1,585.8
Operating expenses:
Depreciation and amortization...................... 89.9 102.8 87.3 190.2 382.1 202.5 174.3
Other operating expenses........................... 386.6 478.3 456.0 1,019.3 2,028.1 1,004.7 1,105.3
------- ------- ------- -------- -------- -------- --------
Total operating expenses......................... 476.5 581.1 543.3 1,209.5 2,410.2 1,207.2 1,279.6
------- ------- ------- -------- -------- -------- --------
Operating income..................................... 367.1 393.9 350.5 426.4 830.8 253.0 306.2
Interest expense..................................... (164.2) (223.5) (196.1) (375.5) (721.5) (370.5) (328.9)
Interest and other income............................ 40.7 53.9 50.9 55.8 74.0 42.4 34.7
Minority interest.................................... (69.5) (38.8) (2.8) (3.0) (3.2) (1.4) (7.5)
------- ------- ------- -------- -------- -------- --------
Income (loss) before income taxes.................... 174.1 185.5 202.5 103.7 180.1 (76.5) 4.5
Provision (benefit) for income taxes................. 82.0 57.4 70.4 (40.4) 72.5 (27.8) 1.7
------- ------- ------- -------- -------- -------- --------
Income (loss) before accounting changes, and
extraordinary
loss............................................... 92.1 128.1 132.1 144.1 107.6 (48.7) 2.8
Cumulative effect on prior years of changes, in
accounting, net of tax............................. -- -- -- (13.8) 17.7 17.7 6.0
Extraordinary loss on early extinguishment of debt,
net of income tax benefit.......................... -- (13.1) -- -- -- -- --
------- ------- ------- -------- -------- -------- --------
Net income (loss).................................... $ 92.1 $ 115.0 $ 132.1 $ 130.3 $ 125.3 $ (31.0) $ 8.8
======= ======= ======= ======== ======== ======== ========
OTHER DATA:
Ratio of earnings to fixed charges(1)(2)............. 1.42 1.64 1.69 1.18 1.23 0.81 0.93

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

(2) For the six month periods ended June 30, 2001 and 2000, there was a fixed
charge deficiency of $25.4 million and $76.6 million, respectively.

BALANCE SHEET DATA:
Assets............................................... $5,152.5 $4,985.1 $5,158.1 $15,534.2 $15,017.1 $15,257.3
Current liabilities.................................. 270.9 339.8 358.7 1,772.8 3,911.0 3,031.2
Long-term obligations, less current portion.......... 2,419.9 2,532.1 2,396.4 7,439.3 5,334.8 6,349.3
Preferred securities of subsidiaries................. 150.0 150.0 150.0 476.9 326.8 325.7
Shareholder's equity................................. 1,019.9 826.6 957.6 3,068.5 2,948.2 2,672.6

THE EXCHANGE OFFER

TERMS OF THE EXCHANGE OFFER

Upon the terms and conditions described in this prospectus and in the
accompanying letter of transmittal, which together constitute the exchange
offer, we will accept for exchange original notes which are properly tendered on
or before the expiration date and not withdrawn as permitted below. As used in
this prospectus, the term "expiration date" means 5:00 p.m., New York City time,
on November 2, 2001. However, if we, in our sole discretion, have extended the
period of time for which the exchange offer is open, the term "expiration date"
means the latest time and date to which we extend the exchange offer. The
exchange offer, however, will not be in effect any longer than 45 business days
from the date of this prospectus.

As of the date of this prospectus, $400 million aggregate principal amount
of the original notes is outstanding. This prospectus, together with the letter
of transmittal, is first being sent on or about October 3, 2001 to all holders
of original notes known to us. Our obligation to accept original notes for
exchange in the exchange offer is subject to the conditions described below
under "--Conditions to the Exchange Offer."

We reserve the right to extend the period of time during which the exchange
offer is open. We would then delay acceptance for exchange of any original notes
by giving oral or written notice of an extension to the holders of original
notes as described below. During any extension period, all original notes
previously tendered will remain subject to the exchange offer and may be
accepted for exchange by us. Any original notes not accepted for exchange will
be returned to the tendering holder after the expiration or termination of the
exchange offer.

Original notes tendered in the exchange offer must be in denominations of
principal amounts of $1,000 and any integral multiple of $1,000.

We reserve the right to amend or terminate the exchange offer, and not to
accept for exchange any original notes not previously accepted for exchange,
upon the occurrence of any of the conditions of the exchange offer specified
below under "--Conditions to the Exchange Offer." We will give oral or written
notice of any extension, amendment, non-acceptance or termination to the holders
of the original notes as promptly as practicable. If we materially change the
terms of the exchange offer, we will resolicit tenders of the original notes,
file a post-effective amendment to the registration statement of which this
prospectus constitutes a part and provide notice to the noteholders. If the
change is made less than five business days before the expiration of the
exchange offer, we will extend the offer so that the noteholders have at least
five business days to tender or withdraw. We will notify you of any extension by
means of a press release or other public announcement no later than 9:00 a.m.,
New York City time on that date.

Our acceptance of the tender of original notes by a tendering holder will
form a binding agreement upon the terms and subject to the conditions provided
in this prospectus and in the accompanying letter of transmittal.

PROCEDURES FOR TENDERING

Except as described below, a tendering holder must, on or prior to the
expiration date:

- transmit a properly completed and duly executed letter of transmittal,
including all other documents required by the letter of transmittal, to
The Bank of New York at the address listed below under the heading
"--Exchange Agent"; or

- if notes are tendered in accordance with the book-entry procedures listed
below, the tendering holder must transmit an agent's message to the
exchange agent at the address listed below under the heading "--Exchange
Agent."

In addition:

- the exchange agent must receive, on or before the expiration date,
certificates for the original notes; or

- a timely confirmation of book-entry transfer of the original notes into
the exchange agent's account at the Depository Trust Company, the
book-entry transfer facility, along with the letter of transmittal or an
agent's message; or

- the holder must comply with the guaranteed delivery procedures described
below.

The Depository Trust Company will be referred to as DTC in this prospectus.

The term "agent's message" means a message, transmitted to DTC and received
by the exchange agent and forming a part of a book-entry transfer, that states
that DTC has received an express acknowledgment that the tendering holder agrees
to be bound by the letter of transmittal and that we may enforce the letter of
transmittal against this holder.

The method of delivery of original notes, letters of transmittal and all
other required documents is at your election and risk. If the delivery is by
mail, we recommend that you use registered mail, properly insured, with return
receipt requested. In all cases, you should allow sufficient time to assure
timely delivery. You should not send letters of transmittal or original notes to
us.

If you are a beneficial owner whose original notes are registered in the
name of a broker, dealer, commercial bank, trust company or other nominee, and
wish to tender, you should promptly instruct the registered holder to tender on
your behalf. Any registered holder that is a participant in DTC's book-entry
transfer facility system may make book-entry delivery of the original notes by
causing DTC to transfer the original notes into the exchange agent's account.

Signatures on a letter of transmittal or a notice of withdrawal must be
guaranteed unless the original notes surrendered for exchange are tendered:

- by a registered holder of the original notes who has not completed the box
entitled "Special Issuance Instructions" or "Special Delivery
Instructions" on the letter of transmittal, or

- for the account of an "eligible institution."

If signatures on a letter of transmittal or a notice of withdrawal are
required to be guaranteed, the guarantees must be by an "eligible institution."
An "eligible institution" is a financial institution--including most banks,
savings and loan associations and brokerage houses--that is a participant in the
Securities Transfer Agents Medallion Program, the New York Stock Exchange
Medallion Signature Program or the Stock Exchanges Medallion Program.

We will determine in our sole discretion all questions as to the validity,
form and eligibility of original notes tendered for exchange. This discretion
extends to the determination of all questions concerning the timing of receipts
and acceptance of tenders. These determinations will be final and binding.

We reserve the right to reject any particular original note not properly
tendered or any which acceptance might, in our judgment or our counsel's
judgment, be unlawful. We also reserve the right to waive any defects or
irregularities or conditions of the exchange offer as to any particular original
note either before or after the expiration date, including the right to waive
the ineligibility of any tendering holder. Our interpretation of the terms and
conditions of the exchange offer as to any particular original note either
before or after the expiration date, including the letter of transmittal and the
instructions to the letter of transmittal, shall be final and binding on all
parties. Unless waived, any defects or irregularities in connection with tenders
of original notes must be cured within a reasonable period of time. Neither we,
the exchange agent nor any other person will be under any duty to give

notification of any defect or irregularity in any tender of original notes. Nor
will we, the exchange agent or any other person incur any liability for failing
to give notification of any defect or irregularity.

If the letter of transmittal is signed by a person other than the registered
holder of original notes, the letter of transmittal must be accompanied by a
written instrument of transfer or exchange in satisfactory form duly executed by
the registered holder with the signature guaranteed by an eligible institution.
The original notes must be endorsed or accompanied by appropriate powers of
attorney. In either case, the original notes must be signed exactly as the name
of any registered holder appears on the original notes.

If the letter of transmittal or any original notes or powers of attorney are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, these persons should so indicate when signing. Unless waived by us,
proper evidence satisfactory to us of their authority to so act must be
submitted.

By tendering, each holder will represent to us that, among other things,

- the exchange notes are being acquired in the ordinary course of business
of the person receiving the exchange notes, whether or not that person is
the holder and

- neither the holder nor the other person has any arrangement or
understanding with any person to participate in the distribution of the
exchange notes.

In the case of a holder that is not a broker-dealer, that holder, by
tendering, will also represent to us that the holder is not engaged in and does
not intend to engage in a distribution of the exchange notes.

If any holder or other person is an "affiliate" of ours, as defined under
Rule 405 of the Securities Act, or is engaged in, or intends to engage in, or
has an arrangement or understanding with any person to participate in, a
distribution of the exchange notes, that holder or other person can not rely on
the applicable interpretations of the staff of the SEC and must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with any resale transaction.

Each broker-dealer that receives exchange notes for its own account in
exchange for original notes, where the original notes were acquired by it as a
result of market-making activities or other trading activities, must acknowledge
that it will deliver a prospectus that meets the requirements of the Securities
Act in connection with any resale of the exchange notes. The letter of
transmittal states that by so acknowledging and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it is an "underwriter" within the
meaning of the Securities Act. See "Plan of Distribution."

ACCEPTANCE OF ORIGINAL NOTES FOR EXCHANGE; DELIVERY OF EXCHANGE NOTES

Upon satisfaction or waiver of all of the conditions to the exchange offer,
we will accept, promptly after the expiration date, all original notes properly
tendered. We will issue the exchange notes promptly after acceptance of the
original notes. See "--Conditions to the Exchange Offer" below. For purposes of
the exchange offer, we will be deemed to have accepted properly tendered
original notes for exchange when, as and if we have given oral or written notice
to the exchange agent, with prompt written confirmation of any oral notice.

For each original note accepted for exchange, the holder of the original
note will receive an exchange note having a principal amount equal to that of
the surrendered original note. The exchange notes will bear interest from the
most recent date to which interest has been paid on the original notes.
Accordingly, registered holders of exchange notes on the relevant record date
for the first interest payment date following the completion of the exchange
offer will receive interest accruing from the most recent date to which interest
has been paid. Original notes accepted for exchange will cease to accrue
interest from and after the date of completion of the exchange offer. Holders of
original notes

whose original notes are accepted for exchange will not receive any payment for
accrued interest on the original notes otherwise payable on any interest payment
date the record date for which occurs on or after completion of the exchange
offer and will be deemed to have waived their rights to receive the accrued
interest on the original notes.

In all cases, issuance of exchange notes for original notes will be made
only after timely receipt by the exchange agent of:

- certificates for the original notes, or a timely book-entry confirmation
of the original notes, into the exchange agent's account at the book-entry
transfer facility;

- a properly completed and duly executed letter of transmittal; and

- all other required documents.

Unaccepted or non-exchanged original notes will be returned without expense
to the tendering holder of the original notes. In the case of original notes
tendered by book-entry transfer in accordance with the book-entry procedures
described below, the non-exchanged original notes will be credited to an account
maintained with the book-entry transfer facility, as promptly as practicable
after the expiration or termination of the exchange offer.

BOOK-ENTRY TRANSFER

The exchange agent will make a request to establish an account for the
original notes at DTC for purposes of the exchange offer within two business
days after the date of this prospectus. Any financial institution that is a
participant in DTC's systems must make book-entry delivery of original notes by
causing DTC to transfer those original notes into the exchange agent's account
at DTC in accordance with DTC's procedure for transfer. This participant should
transmit its acceptance to DTC on or prior to the expiration date or comply with
the guaranteed delivery procedures described below. DTC will verify this
acceptance, execute a book-entry transfer of the tendered original notes into
the exchange agent's account at DTC and then send to the exchange agent
confirmation of this book-entry transfer. The confirmation of this book-entry
transfer will include an agent's message confirming that DTC has received an
express acknowledgment from this participant that this participant has received
and agrees to be bound by the letter of transmittal and that we may enforce the
letter of transmittal against this participant. Delivery of exchange notes
issued in the exchange offer may be effected through book-entry transfer at DTC.
However, the letter of transmittal or facsimile of it or an agent's message,
with any required signature guarantees and any other required documents, must:

(1) be transmitted to and received by the exchange agent at the address
listed below under "--Exchange Agent" on or prior to the expiration date;
or

(2) comply with the guaranteed delivery procedures described below.

GUARANTEED DELIVERY PROCEDURES

If a registered holder of original notes desires to tender the original
notes, and the original notes are not immediately available, or time will not
permit the holder's original notes or other required documents to reach the
exchange agent before the expiration date, or the procedure for book-entry
transfer described above cannot be completed on a timely basis, a tender may
nonetheless be made if:

- the tender is made through an eligible institution;

- prior to the expiration date, the exchange agent received from an eligible
institution a properly completed and duly executed letter of transmittal,
or a facsimile of the letter of transmittal, and notice of guaranteed
delivery, substantially in the form provided by us, by facsimile
transmission, mail or hand delivery,

(1) stating the name and address of the holder of original notes and the
amount of original notes tendered,

(2) stating that the tender is being made and

(3) guaranteeing that within three New York Stock Exchange trading days
after the expiration date, the certificates for all physically
tendered original notes, in proper form for transfer, or a book-entry
confirmation, as the case may be, and any other documents required by
the letter of transmittal will be deposited by the eligible
institution with the exchange agent; and

- the certificates for all physically tendered original notes, in proper
form for transfer, or a book-entry confirmation, as the case may be, and
all other documents required by the letter of transmittal, are received by
the exchange agent within three New York Stock Exchange trading days after
the expiration date.

WITHDRAWAL RIGHTS

Tenders of original notes may be withdrawn at any time before 5:00 p.m., New
York City time, on the expiration date.

For a withdrawal to be effective, the exchange agent must receive a written
notice of withdrawal at the address or, in the case of eligible institutions, at
the facsimile number, indicated below under "--Exchange Agent" before
5:00 p.m., New York City time, on the expiration date. Any notice of withdrawal
must:

- specify the name of the person, referred to as the depositor, having
tendered the original notes to be withdrawn;

- identify the notes to be withdrawn, including the certificate number or
numbers and principal amount of the original notes;

- contain a statement that the holder is withdrawing his election to have
the original notes exchanged;

- be signed by the holder in the same manner as the original signature on
the letter of transmittal by which the original notes were tendered,
including any required signature guarantees, or be accompanied by
documents of transfer to have the trustee with respect to the original
notes register the transfer of the original notes in the name of the
person withdrawing the tender; and

- specify the name in which the original notes are registered, if different
from that of the depositor.

If certificates for original notes have been delivered or otherwise
identified to the exchange agent, then, prior to the release of these
certificates the withdrawing holder must also submit the serial numbers of the
particular certificates to be withdrawn and signed notice of withdrawal with
signatures guaranteed by an eligible institution unless this holder is an
eligible institution. If original notes have been tendered in accordance with
the procedure for book-entry transfer described above, any notice of withdrawal
must specify the name and number of the account at the book-entry transfer
facility to be credited with the withdrawn original notes. We will determine all
questions as to the validity, form and eligibility, including time of receipt,
of notices of withdrawal. Any original notes so withdrawn will be deemed not to
have been validly tendered for exchange. No exchange notes will be issued unless
the original notes so withdrawn are validly re-tendered. Any original notes that
have been tendered for exchange, but which are not exchanged for any reason,
will be returned to the tendering holder without cost to the holder. In the case
of original notes tendered by book-entry transfer, the original notes will be
credited to an account maintained with the book-entry transfer facility for the
original notes.

Properly withdrawn original notes may be re-tendered by following the procedures
described under "--Procedures for Tendering" above at any time on or before
5:00 p.m., New York City time, on the expiration date.

CONDITIONS TO THE EXCHANGE OFFER

Notwithstanding any other provision of the exchange offer, we shall not be
required to accept for exchange, or to issue exchange notes in exchange for, any
original notes, and may terminate or amend the exchange offer, if at any time
before the acceptance of the original notes for exchange or the exchange of the
exchange notes for the original notes, any of the following events shall occur:

- there shall be threatened, instituted or pending any action or proceeding
before, or any injunction, order or decree shall have been issued by, any
court or governmental agency or other governmental regulatory or
administrative agency or commission:

(1) seeking to restrain or prohibit the making or completion of the
exchange offer or any other transaction contemplated by the exchange
offer, or assessing or seeking any damages as a result of this
transaction,

(2) resulting in a material delay in our ability to accept for exchange
or exchange some or all of the original notes in the exchange offer;
or any statute, rule, regulation, order or injunction shall be
sought, proposed, introduced, enacted, promulgated or deemed
applicable to the exchange offer or any of the transactions
contemplated by the exchange offer by any governmental authority,
domestic or foreign; or

- any action shall have been taken, proposed or threatened, by any
governmental authority, domestic or foreign, that in our sole judgment
might directly or indirectly result in any of the consequences referred to
in clauses (1) or (2) above or, in our sole judgment, might result in the
holders of exchange notes having obligations with respect to resales and
transfers of exchange notes which are greater than those described in the
interpretation of the SEC referred to above, or would otherwise make it
inadvisable to proceed with the exchange offer; or

- there shall have occurred:

(1) any general suspension of or general limitation on prices for, or
trading in, securities on any national securities exchange or in the
over-the-counter market; or

(2) any limitation by a governmental authority which may adversely affect
our ability to complete the transactions contemplated by the exchange
offer; or

(3) a declaration of a banking moratorium or any suspension of payments
in respect of banks in the United States or any limitation by any
governmental agency or authority which adversely affects the
extension of credit; or

(4) a commencement of a war, armed hostilities or other similar
international calamity directly or indirectly involving the United
States, or, in the case of any of the preceding events existing at
the time of the commencement of the exchange offer, a material
acceleration or worsening of these calamities; or

- any change, or any development involving a prospective change, shall have
occurred or be threatened in our business, financial condition, operations
or prospects and those of our subsidiaries taken as a whole that is or may
be adverse to us, or we shall have become aware of facts that have or may
have an adverse impact on the value of the original notes or the exchange
notes; which in our sole judgment in any case makes it inadvisable to
proceed with the exchange offer and/or with such acceptance for exchange
or with such exchange.

These conditions to the exchange offer are to our sole benefit and we may
assert them regardless of the circumstances giving rise to any of these
conditions, or we may waive them in whole or in part in our sole discretion. If
we do so, the exchange offer will remain open for at least 5 business days
following any waiver of the preceding conditions. Our failure at any time to
exercise any of the foregoing rights will not be deemed a waiver of any right.

In addition, we will not accept for exchange any original notes tendered,
and no exchange notes will be issued in exchange for any original notes, if at
this time any stop order is threatened or in effect relating to the registration
statement of which this prospectus constitutes a part or the qualification of
the indenture under the Trust Indenture Act of 1939.

EXCHANGE AGENT

We have appointed The Bank of New York as the exchange agent for the
exchange offer. You should direct all executed letters of transmittal to the
exchange agent at the address indicated below. You should direct questions and
requests for assistance, requests for additional copies of this prospectus or of
the letter of transmittal and requests for notices of guaranteed delivery to the
exchange agent addressed as follows:

DELIVERY TO: The Bank of New York, EXCHANGE AGENT

BY HAND BEFORE 4:30 P.M.: BY REGISTERED OR CERTIFIED MAIL:
The Bank of New York The Bank of New York
20 Broad Street 20 Broad Street
Lower Level Lower Level
New York, NY 10005 New York, NY 10005
Attention: Frank Driscoll Attention: Frank Driscoll

BY HAND OR OVERNIGHT DELIVERY AFTER
4:30 P.M. ON THE EXPIRATION DATE:
The Bank of New York
20 Broad Street
Lower Level
New York, NY 10005
Attention: Frank Driscoll
FOR INFORMATION CALL:
Carolle Montreuil
(914) 773-5735

BY FACSIMILE TRANSMISSION
(FOR ELIGIBLE INSTITUTIONS ONLY):
(914) 773-5015 or
(914) 773-5040
Attention: Customer Service
CONFIRM BY TELEPHONE:
Carolle Montreuil
(914) 773-5735

If you deliver the letter of transmittal to an address other than any
address indicated above or transmit instructions via facsimile other than any
facsimile number indicated, then your delivery or transmission will not
constitute a valid delivery of the letter of transmittal.

FEES AND EXPENSES

We will not make any payment to brokers, dealers, or others soliciting
acceptances of the exchange offer. The estimated cash expenses to be incurred in
connection with the exchange offer will be paid by us. We estimate these
expenses in the aggregate to be approximately $500,000.

ACCOUNTING TREATMENT

We will not recognize any gain or loss for accounting purposes upon the
consummation of the exchange offer. We will amortize the expense of the exchange
offer over the term of the exchange notes under generally accepted accounting
principles.

TRANSFER TAXES

Holders who tender their original notes for exchange will not be obligated
to pay any related transfer taxes, except that holders who instruct us to
register exchange notes in the name of, or request that original notes not
tendered or not accepted in the exchange offer be returned to, a person other
than the registered tendering holder will be responsible for the payment of any
applicable transfer taxes.

CONSEQUENCES OF EXCHANGING OR FAILING TO EXCHANGE ORIGINAL NOTES

Holders of original notes who do not exchange their original notes for
exchange notes in the exchange offer will continue to be subject to the
provisions in the indenture regarding transfer and exchange of the original
notes and the restrictions on transfer of the original notes as described in the
legend on the notes as a consequence of the issuance of the original notes under
exemptions from, or in transactions not subject to, the registration
requirements of the Securities Act and applicable state securities laws. In
general, the original notes may not be offered or sold, unless registered under
the Securities Act, except under an exemption from, or in a transaction not
subject to, the Securities Act and applicable state securities laws. As
discussed in "Exchange Offer; Registration Rights," we do not currently
anticipate that we will register original notes under the Securities Act.

Based on interpretations by the staff of the SEC, as described in no-action
letters issued to third parties, we believe that exchange notes issued in the
exchange offer in exchange for original notes may be offered for resale, resold
or otherwise transferred by holders of the original notes, other than any holder
which is an "affiliate" of ours within the meaning of Rule 405 under the
Securities Act, without compliance with the registration and prospectus delivery
provisions of the Securities Act, if the exchange notes are acquired in the
ordinary course of the holders' business and the holders have no arrangement or
understanding with any person to participate in the distribution of the exchange
notes. However, the SEC has not considered the exchange offer in the context of
a no-action letter. We cannot assure you that the staff of the SEC would make a
similar determination with respect to the exchange offer as in the other
circumstances. Each holder, other than a broker-dealer, must acknowledge that it
is not engaged in, and does not intend to engage in, a distribution of exchange
notes and has no arrangement or understanding to participate in a distribution
of exchange notes. If any holder is an affiliate of ours, is engaged in or
intends to engage in or has any arrangement or understanding with any person to
participate in the distribution of the exchange notes to be acquired in the
exchange offer, that holder:

(1) could not rely on the applicable interpretations of the staff of the
SEC; and

(2) must comply with the registration and prospectus delivery requirements
of the Securities Act in connection with any resale transaction.

Each broker-dealer that receives exchange notes for its own account in
exchange for original notes must acknowledge that the original notes were
acquired by the broker-dealer as a result of

market-making activities or other trading activities and that it will comply
with the registration and prospectus delivery requirements of the Securities Act
in connection with any resale of the exchange notes. Furthermore, any
broker-dealer that acquired any of its original notes directly from us:

- may not rely on the applicable interpretation of the staff of the SEC's
position contained in Exxon Capital Holdings Corp., SEC no-action letter
(April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter
(June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2,
1983) and

- must also be named as a selling noteholder in connection with the
registration and prospectus delivery requirements of the Securities Act
relating to any resale transaction.

See "Plan of Distribution."

In addition, to comply with state securities laws, the exchange notes may
not be offered or sold in any state unless they have been registered or
qualified for sale in such state or an exemption from registration or
qualification, with which there has been compliance, is available. The offer and
sale of the exchange notes to "qualified institutional buyers," as defined under
Rule 144A of the Securities Act, is generally exempt from registration or
qualification under the state securities laws. We currently do not intend to
register or qualify the sale of exchange notes in any state where an exemption
from registration or qualification is required and not available.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING
EDISON MISSION ENERGY. 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
PRESENTED IN THE FORWARD-LOOKING STATEMENTS. IMPORTANT FACTORS THAT COULD CAUSE
ACTUAL RESULTS TO DIFFER INCLUDE RISKS LISTED IN "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, one
of the largest electric utilities in the United States. We were formed in 1986
with two domestic operating projects. As of June 30, 2001, we owned interests in
33 domestic and 39 international operating power projects with an aggregate
generating capacity of 27,798 megawatts (MW), of which our share was 22,923 MW.
At that date, one domestic and five international projects, totaling 1,551 MW of
generating capacity, of which our anticipated share will be approximately 926
MW, were in construction. At June 30, 2001, we had consolidated assets of
$15.3 billion and total shareholder's equity of $2.7 billion.

ACQUISITIONS, DISPOSITIONS AND SALE-LEASEBACK TRANSACTIONS

Set forth below is a description of our acquisitions, dispositions and
sale-leaseback transactions since January 1, 1998.

ACQUISITION OF CBK POWER CO. LTD.

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 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric
project located in the Philippines. Financing for this $460 million project
comprises equity commitments of $117 million (our 50% share of which is
$58.5 million) required to be made upon completion of the rehabilitation and
expansion, currently scheduled for 2003, and debt financing which is in place
for the remainder of the cost for this project.

ACQUISITION OF SUNRISE PROJECT

On November 17, 2000, we completed a transaction with Texaco Power &
Gasification Holdings 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 had an option to repurchase at
cost a 50% interest in the project prior to its commercial operation which
commenced on June 27, 2001. On June 25, 2001, Texaco exercised its option and
repurchased a 50% interest for $84 million. As part of our acquisition of the
Sunrise project, we also: (i) acquired from Texaco two gas turbines for the
project and (ii) granted Texaco an option to acquire a 50% interest in 1,000 MW
of future power plant projects we designate. The Sunrise project consists of two
phases, with Phase I, a single-cycle gas-fired facility (320 MW), completed on
June 27, 2001, and Phase II, conversion to a combined-cycle gas-fired facility
(560 MW), currently scheduled to be completed in July 2003. We entered into a
long-term power purchase agreement with the California Department of Water
Resources on June 25, 2001.

The total purchase price of the Sunrise project from Texaco was
$27.0 million. We funded the purchase with cash. The total estimated
construction cost of this project through 2003 is approximately $455.0 million.
The project intends to obtain project financing for a portion of the capital
costs.

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. These plants 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 terms of up to five years expiring in
2004, 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. Exelon Generation has the option to terminate
two of the three agreements in their entirety or with respect to any generating
unit or units in each of 2002, 2003 and 2004. In June 2001, Exelon Generation
provided us notice to continue the agreement related to the coal units for 2002.

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 MW 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 our 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 have 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 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 (L830 million at the time of the
acquisition) under a term loan facility due 2012 to finance the purchase. For a
description of the status of the loan and related matters, see "--Liquidity and
Capital Resources--Subsidiary Financing Plans--Status of Edison First Power
Loan."

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 a New Zealand and 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 42.6%. 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 2,247 MW. Consideration for our interest in
Contact Energy consisted of a cash payment of approximately $635 million
(NZ $1.2 billion), which was financed by $120 million of preferred securities, a
$214 million (NZ $400 million 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.

During the second quarter of 2001, we completed the purchase of additional
shares of Contact Energy for NZ$152 million, thereby increasing our ownership
interest from 42.6% to 51.2%. Accordingly, we began accounting for Contact
Energy on a consolidated basis effective June 1, 2001, upon acquisition of a
controlling interest. Prior to June 1, 2001, we used the equity method of
accounting for Contact Energy. In order to finance this purchase, we obtained a
NZ$135 million, 364-day bridge loan from an investment bank under a credit
facility which is to be syndicated by the bank. In addition to other security
arrangements, a security interest over all Contact Energy shares held has been
provided as collateral. In June and July 2001, we issued through one of our
subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001,
we redeemed NZ$400 million EME Taupo preferred securities from the existing
holders. Funding for the redemption of the existing preferred securities was
provided by a NZ$400 million credit facility scheduled to mature in July 2005.
The financing documents governing the credit facility provide that the credit
facility may be funded under either, or a combination of, a letter of credit
facility or a revolving credit facility. The NZ$400 million was originally
funded as a revolving credit facility.

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. For information about
the disposition of the EcoElectrica facility, see "--Dispositions."

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. We began accounting for Contact Energy on a consolidated basis effective
June 1, 2001, upon acquisition of a controlling interest.

DISPOSITIONS

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 $17.0 million ($10.5 million
after tax).

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 25, 2001, we completed the sale of a 50% interest in the Sunrise
project to Texaco Power & Gasification Holdings Inc. Proceeds from the sale were
$84 million.

On June 29, 2001, we completed the sale of our 25% interest in the Hopewell
project to the existing partner. Proceeds from the sale were $26.5 million. We
recorded a gain on the sale of $5.4 million ($2.8 million after tax).

offering for sale our interest in the Brooklyn Navy Yard project. We expect the
proceeds from the sale of our interests in the above projects, if completed,
will be in excess of their book value with respect to those projects, which was
$482 million at June 30, 2001. We are also offering for sale the Ferrybridge and
Fiddler's Ferry plants in the United Kingdom. See "--Liquidity and Capital
Resources--Subsidiary Financing Plans--Status of Edison First Power Loan."

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, which began January 2,
2001. We guarantee our 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 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 guaranteed 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 2005. The gain on the sale of equipment has
been deferred and is being amortized over the term of the operating lease.

MISSION ENERGY HOLDING COMPANY

On June 8, 2001, Edison International created Mission Energy Holding Company
as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset
is our common stock. In July 2001, Mission Energy Holding issued $800 million of
13.50% senior secured notes due 2008. Concurrently with the consummation of the
offering of its senior secured notes, Mission Energy Holding borrowed
$385 million under a new term loan. The senior secured notes and the term loan
are secured by a first priority security interest in our common stock. The
respective rights, remedies and priorities of the holders of the senior secured
notes and the lenders with respect to our stock are governed by intercreditor
arrangements. Both the senior secured notes and the term loan also have security
interest in interest reserve accounts, covering the interest payable on those
obligations for the first two years. The net proceeds of the offering and the
term loan not deposited into the respective interest escrow accounts were used
to pay a dividend to Mission Energy Holding's parent, The Mission Group, which
in turn loaned the net proceeds to its parent, Edison International. Edison
International used the funds to repay a portion of its indebtedness that matures
in 2001. The Mission Energy Holding financing documents contain restrictions on
our ability and the ability of our subsidiaries to enter into specified
transactions or engage in specified business activities and require in some
instances that we obtain the approval of the Mission Energy Holding board of
directors. Our articles of incorporation bind us to the restrictions in the
Mission Energy Holding financing documents by restricting our ability to enter
into specified transactions or engage in specified business activities, as set
forth in the Mission Energy Holding financing documents, without shareholder
approval. See "Risk Factors--Restrictions in our articles of incorporation, our
credit facilities and the Mission Energy Holding financing documents limit or
prohibit us from entering into specified transactions that we otherwise may
enter into."

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.

AMERICAS

YEARS ENDED SIX MONTHS THREE MONTHS
DECEMBER 31, ENDED JUNE 30, ENDED, JUNE 30,
------------------------------ ------------------- -------------------
1998 1999 2000 2000 2001 2000 2001
-------- -------- -------- -------- -------- -------- --------
(IN MILLIONS) (IN MILLIONS) (IN MILLIONS)
(UNAUDITED) (UNAUDITED)

Operating revenues................. $ 29.9 $378.6 $1,571.0 $637.1 $687.2 $390.8 $379.7
Net gains (losses) from energy
trading and price risk
management....................... -- (6.4) (17.3) (33.8) 32.5 (32.1) 13.6
Equity in income from
investments...................... 184.6 224.8 257.2 94.3 192.3 61.0 110.0
------ ------ -------- ------ ------ ------ ------
Total operating revenues....... 214.5 597.0 1,810.9 697.6 912.0 419.7 503.3

Fuel and plant operations.......... 22.2 237.7 1,131.6 516.1 593.0 286.6 305.8
Depreciation and amortization...... 9.8 52.5 191.2 100.4 79.5 50.3 40.1
Administrative and general......... -- -- 21.1 -- 10.9 -- 5.1
------ ------ -------- ------ ------ ------ ------
Operating income................... $182.5 $306.8 $ 467.0 $ 81.1 $228.6 $ 82.8 $152.3
====== ====== ======== ====== ====== ====== ======

INTERIM RESULTS

OPERATING REVENUES

Operating revenues decreased $11.1 million for the second quarter ended
June 30, 2001, compared to the corresponding period of 2000. The decrease was
primarily due to lower dispatch from the coal units at the Illinois Plants as a
result of lower market prices during the second quarter of 2001. Operating
revenues increased $50.1 million for the six months ended June 30, 2001,
compared to the same prior year period. The increase resulted from higher
electric revenues from the Homer City plant due to higher energy prices and from
the Illinois Plants due to increased generation from the coal units as a result
of higher market prices, as compared to the same prior year period.

Net gains from energy trading activities were $6.5 million and $2.4 million
for the second quarter and six months ended June 30, 2001, respectively. There
were no comparable gains or losses for the same prior year periods. Total gains
and losses from price risk management activities increased $39.2 million and
$63.9 million for the second quarter and six months ended June 30, 2001,
respectively, compared to the corresponding periods of 2000. The increase in
gains was primarily due to realized and unrealized gains for a gas swap
purchased to hedge 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
gain in the second quarter and six months ended June 30, 2001 was a

loss resulting from the change in market value of future contracts with respect
to fuel purchases at the Illinois Plants that did not qualify for hedge
accounting under SFAS No. 133.

Equity in income from investments increased $49 million and $98 million
during the second quarter and six months ended June 30, 2001, respectively,
compared to the same prior year periods. The increase was primarily the result
of higher revenues from cogeneration projects due to higher energy pricing
during the six-month period ended June 30, 2001, and higher revenues from oil
and gas investments due to higher oil and gas prices in the first quarter of
2001.

OPERATING EXPENSES

Fuel and plant operations increased $19.2 million and $76.9 million for the
second quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods of the prior year. The increase in plant operations
resulted from lease costs related to the sale-leaseback commitments for the
Powerton-Joliet power facilities and the Collins gas and oil-fired power plant.
There were no comparable lease costs for the Powerton-Joliet power facilities
during the six months ended June 30, 2000. In addition, plant operations
increased due to higher major maintenance costs at the Illinois Plants during
the six-month period ended June 30, 2001. The increase in fuel expense for the
six months ended June 30, 2001, as compared to the same period last year,
resulted from higher fuel costs at the Illinois Plants primarily due to higher
natural gas and fuel oil prices.

Depreciation and amortization expense decreased $10.2 million and
$20.9 million for the second quarter and six months ended June 30, 2001,
respectively, compared to the same periods last year. The decrease resulted from
lower depreciation expense at the Illinois Plants related to the sale-leaseback
transaction for the Powerton-Joliet power facilities to third-party lessors in
August 2000.

Administrative and general expenses for the quarter ended and six months
ended June 30, 2001 consist of administrative and general expenses incurred at
our trading operations in Boston, Massachusetts. Prior to September 1, 2000, the
acquisition date of Citizens Power, administrative and general expenses incurred
by our own marketing operations were reflected in Corporate/Other administrative
and general expenses.

OPERATING INCOME

Operating income increased $69.5 million and $147.5 million during the
second quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods of the prior year. The increase was primarily due to
operating income from the Homer City plant, equity in income from investments in
energy projects and gains from price risk management activities discussed above.

ANNUAL RESULTS

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.

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 the acquisition of trading operations of Citizens Power LLC through
December 31, 2001 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).

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 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 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 or were 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 "--Contingencies--The California Power Crisis."

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. Prior to September 1, 2000, the acquisition date of
Citizens Power, 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 resulted
from operating income from the Homer City plant and equity in income from
investments in energy projects.

ASIA PACIFIC

YEARS ENDED SIX MONTHS THREE MONTHS
DECEMBER 31, ENDED JUNE 30, ENDED JUNE 30,
------------------------------ ------------------- -------------------
1998 1999 2000 2000 2001 2000 2001
-------- -------- -------- -------- -------- -------- --------
(IN MILLIONS) (IN MILLIONS) (IN MILLIONS)
(UNAUDITED) (UNAUDITED)

Operating revenues..................... $205.1 $213.6 $184.2 $93.1 $138.6 $40.8 $92.4
Net gains from energy trading and price
risk management...................... -- -- -- -- 0.1 -- 0.6
Equity in income from investments...... 1.3 18.1 14.6 4.4 7.0 1.7 3.9
------ ------ ------ ----- ------ ----- -----
Total operating revenues........... 206.4 231.7 198.8 97.5 145.7 42.5 96.9

Fuel and plant operations.............. 69.6 73.8 61.5 32.5 58.2 15.7 43.2
Depreciation and amortization.......... 31.6 40.5 35.0 18.0 16.5 7.4 8.3
------ ------ ------ ----- ------ ----- -----
Operating income....................... $105.2 $117.4 $102.3 $47.0 $ 71.0 $19.4 $45.4
====== ====== ====== ===== ====== ===== =====

INTERIM RESULTS

OPERATING REVENUES

Operating revenues increased $51.6 million and $45.5 million for the second
quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods of 2000. The increase was primarily due to consolidating
Contact Energy operating revenues due to acquiring a controlling interest in the
project, effective June 1, 2001. The increase was partially offset by lower
electric revenues from the Loy Yang B plant in Australia due to a 14.4% decrease
in the average

exchange rate of the Australian dollar compared to the U.S. dollar at the
six-month period ended June 30, 2001, compared to the same prior year period.

Net gains from price risk management activities were $0.6 million and
$0.1 million for the second quarter and six months ended June 30, 2001,
respectively. There were no comparable gains or losses for the same prior year
periods. The gains primarily represent the ineffective portion of a long-term
contract with the State Electricity Commission of Victoria and interest rate
swaps entered into by Loy Yang B plant, which are derivatives that qualified as
cash flow hedges under SFAS No. 133.

Equity in income from investments increased $2.2 million and $2.6 million
during the second quarter and six months ended June 30, 2001, respectively,
compared to the same prior year periods. The increase primarily reflects gains
from Contact Energy through May 31, 2001 due to higher wholesale electricity
prices in the current year.

OPERATING EXPENSES

Fuel and plant operations increased $27.5 million and $25.7 million for the
second quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods of 2000. The increase was primarily due to consolidating
Contact Energy operating expenses, effective June 1, 2001.

OPERATING INCOME

Operating income increased $26 million and $24 million during the second
quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods of 2000. The increase was primarily due to consolidating
Contact Energy results of operations, effective June 1, 2001. Prior to June 1,
2001, we used the equity method of accounting for Contact Energy.

ANNUAL RESULTS

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.

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

Operating revenues......................... $469.4 $805.8 $1,236.3 $668.7 $540.6 $265.8 $217.9
Net losses from energy trading and price
risk management.......................... -- -- -- -- (14.1) -- (3.9)
Equity in income (loss) from investments... 3.5 1.4 (5.0) (3.7) 0.3 (4.8) 1.1
------ ------ -------- ------ ------ ------ ------
Total operating revenues............... 472.9 807.2 1,231.3 665.0 526.8 261.0 215.1

Fuel and plant operations.................. 241.3 456.6 730.1 382.3 381.0 156.4 181.9
Depreciation and amortization.............. 40.3 88.3 144.8 74.6 72.9 36.9 37.7
------ ------ -------- ------ ------ ------ ------
Operating income (loss).................... $191.3 $262.3 $ 356.4 $208.1 $ 72.9 $ 67.7 $ (4.5)
====== ====== ======== ====== ====== ====== ======

INTERIM RESULTS

OPERATING REVENUES

Operating revenues decreased $47.9 million and $128.1 million for the second
quarter and six months ended June 30, 2001, respectively, compared to the
corresponding periods of the prior year. The decrease resulted primarily from
lower electric revenues from the Ferrybridge and Fiddler's Ferry plants and the
First Hydro plant due to lower energy prices and an 8.2% decrease in the average
exchange rate of the pound sterling compared to the U.S. dollar at the six-month
period ended June 30, 2001, compared to the same prior year period. The time
weighted average System Marginal Price decreased from L21.3/MWh during the
quarter ended March 31, 2000 to L18.6/MWh during the quarter ended March 31,
2001. On March 27, 2001, the United Kingdom pool pricing system was replaced
with a bilateral physical trading system referred to as the new electricity
trading arrangements, therefore eliminating the System Marginal Price. The new
electricity trading arrangements are described in further detail under "--Market
Risk Exposures--United Kingdom." These new electricity

trading arrangements have resulted in lower forward contract prices for the
quarter ended June 30, 2001, compared to the quarter ended June 30, 2000. The
First Hydro plant, Ferrybridge and Fiddler's Ferry plants and the Iberian
Hy-Power plants generally provide higher electric revenues during the winter
months.

Net losses from price risk management activities were $3.9 million and
$14.1 million for the second quarter and six months ended June 30, 2001,
respectively. There were no comparable gains or losses for the same prior year
periods. The losses primarily represent the change in market value of
electricity rate swap agreements that were recorded at fair value under SFAS
No. 133 with changes in fair value recorded through the income statement.

Equity in income from investments increased $5.9 million and $4 million
during the second quarter and six months ended June 30, 2001, respectively,
compared to the same prior year periods. The increase reflects lower losses
during the second quarter ended June 30, 2001, compared to the corresponding
period in 2000 from the ISAB project, which commenced operations in April 2000.
We had no comparable results for the ISAB project in the first quarter of 2000.

OPERATING EXPENSES

Fuel and plant operations increased $25.5 million for the quarter ended
June 30, 2001, compared to the corresponding period in 2000. The increase in
fuel expense resulted from higher fuel costs at the Doga plant due to increased
production in the second quarter of 2001, compared to the same prior year
quarter, when the plant experienced more unplanned outages. In addition, fuel
costs increased at the First Hydro plant due to higher overnight prices and
imbalance charges. The increase in plant operations resulted primarily from
higher overhaul costs at the Ferrybridge and Fiddler's Ferry plants during the
quarter ended June 30, 2001, compared to the corresponding period in 2000.

Fuel and plant operations decreased $1.3 million for the six months ended
June 30, 2001, compared to the same prior year period. The decrease in fuel
expense and plant operations resulted primarily from a decrease in the average
exchange rate of the pound sterling compared to the U.S. dollar. In addition,
plant operations decreased from lower production at the Ferrybridge and
Fiddler's Ferry plants during the first six months of 2001. Partially offsetting
these decreases were higher fuel costs and plant operation expenses for the Doga
plant due to increased production in the first six months of 2001, compared to
the same prior year period.

OPERATING INCOME

Operating income decreased $72.2 million and $135.2 million during the
second quarter and six months ended June 30, 2001, respectively, compared to the
same prior year periods. The decrease was due to lower operating income from the
Ferrybridge and Fiddler's Ferry plants, the First Hydro plant and the Doga
plant.

ANNUAL RESULTS

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, milder winter weather and uncertainty surrounding planned
changes in electricity trading arrangements described below 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 continued 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.

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 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

Net gains from energy trading and price risk
management................................ $ -- $ -- $ -- $ -- $ 1.3 $ -- $ 0.4
Depreciation and amortization............... 5.6 8.9 11.1 9.4 5.4 4.8 2.6
Long-term incentive compensation............ 39.0 136.3 (56.0) -- (2.9) -- 0.8
Administrative and general.................. 83.9 114.9 139.8 73.8 65.1 39.7 33.4
------- ------- ------ ------ ------ ------ ------
Operating loss.............................. $(128.5) $(260.1) $(94.9) $(83.2) $(66.3) $(44.5) $(36.4)
======= ======= ====== ====== ====== ====== ======

INTERIM RESULTS

Net gains from price risk management activities were $0.4 million and
$1.3 million for the second quarter and six months ended June 30, 2001,
respectively. There were no comparable gains or losses for the same prior year
periods. The gains primarily resulted from the change in market value of our
interest rate swaps with respect to our $100 million senior notes that did not
qualify for hedge accounting under SFAS No. 133

Long-term incentive compensation expense consists of charges related to our
terminated phantom option plan. We recorded an adjustment to our long-term
incentive compensation accrual during the six months ended June 30, 2001 for
changes in the market value of stock equivalent units.

Administrative and general expenses decreased $6.3 million and $8.7 million
for the second quarter and six months ended June 30, 2001, respectively,
compared to the corresponding periods of 2000. The decrease was the result of
lower administrative and general operating costs.

ANNUAL RESULTS

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 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.

OTHER INCOME (EXPENSE)

INTERIM RESULTS

Interest and other income increased $5.5 million for the six months ended
June 30, 2001, compared to the same prior year period. The increase was
primarily due to higher interest income and foreign exchange gains on
intercompany loans. Higher interest income resulted from the $255 million of
notes purchased in connection with the sale-leaseback of the Illinois peaker
power units in July 2000.

Interest expense decreased $18.5 million and $37.7 million for the second
quarter and six months ended June 30, 2001, respectively, compared to the same
prior year periods. The decrease was

primarily the result of payment on our $500 million floating rate notes issued
in December 1999 and subsequently paid in September 2000, lower interest rates
on debt financing associated with the Illinois Plants and favorable changes in
foreign exchange rates.

Minority interest expense increased $6.5 million and $6.1 million for the
second quarter and six months ended June 30, 2001, respectively, compared to the
same prior year periods. The increase was due to accounting for Contact Energy
on a consolidated basis, effective June 1, 2001, due to the purchase of
additional shares of Contact Energy that resulted in our ownership interest
increasing from 42.6% to 51.2%.

ANNUAL RESULTS

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).

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

INTERIM RESULTS

During the six months ended June 30, 2001, we recorded an effective tax
provision rate of 39% based on projected income for the year and benefits under
our tax sharing agreement, compared to the annual effective tax benefit rate for
the first six months of 2000 of 36%.

ANNUAL RESULTS

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

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE

Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The Statement establishes accounting and reporting standards
requiring that derivative instruments be recorded in the balance sheet as either
assets or liabilities measured at their fair value unless they meet an
exception. 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.

Our primary market risk exposures arise from changes in electricity and fuel
prices, interest rates, 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. Effective January 1, 2001,
we record all derivatives at fair value unless the derivatives qualify for the
normal sales and purchases exception. This exception applies to physical sales
and purchases of power or fuel where it is probable that physical delivery will
occur, the pricing provisions are clearly and closely related to the contracted
prices and the documentation requirements of SFAS No. 133, as amended, are met.
The majority of our physical long-term power and fuel contracts, and the similar
business activities of our affiliates, qualify under this exception.

The majority of our remaining risk management activities, including forward
sales contracts from our Homer City plant, qualify for treatment under SFAS
No. 133 as cash flow hedges with appropriate adjustments made to other
comprehensive income. The hedge agreement we have with the State Electricity
Commission of Victoria for electricity prices from our Loy Yang B project in
Australia qualifies as a cash flow hedge. This contract could not qualify under
the normal sales and purchases exception because financial settlement of the
contract occurs without physical delivery. Some of our derivatives did not
qualify for either the normal sales and purchases exception or as cash flow
hedges. These derivatives are recorded at fair value with subsequent changes in
fair value recorded through the income statement. The majority of our activities
related to the Ferrybridge and Fiddler's Ferry power plants in the United
Kingdom and fuel contracts related to the Collins Station in Illinois do not
qualify for either the normal purchases and sales exception or as cash flow
hedges. In both these situations, we could not conclude, based on information
available at June 30, 2001, that the timing of generation from these power
plants met the probable requirement for a specific forecasted transaction under
SFAS No. 133. Accordingly, the majority of these contracts are recorded at fair
value, with subsequent

changes in fair value reflected in net gains (losses) from energy trading and
price risk management in the consolidated 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. We recorded a $6 million, after tax, increase to net income as the
cumulative change in the accounting for derivatives during the quarter ended
March 31, 2001. In addition, we recorded a $230 million, after tax, unrealized
holding loss upon adoption of a change in accounting principle reflected in
accumulated other comprehensive loss in the consolidated balance sheet. During
the quarter ended June 30, 2001, we recorded a $120 million, after tax,
unrealized holding gain reflected in accumulated other comprehensive loss in the
consolidated balance sheet. We recorded a loss of $0.3 million, after tax, and
$7.4 million, after tax, for the quarter ended and six months ended June 30,
2001, respectively, as the change in the fair value of derivatives required
under SFAS No. 133 that previously qualified for hedge accounting. We also
recorded a net gain of $1.5 million and $1.6 million for the quarter ended and
six months ended June 30, 2001, respectively, representing the amount of cash
flow hedges ineffectiveness, reflected in net gains (losses) from energy trading
and price risk management in the consolidated income statement.

The Derivative Implementation Group of the Financial Accounting Standards
Board has recently provided guidance on the normal sales and purchases exception
that affects classification on commodity contracts. We did not use the normal
sales and purchases exception for forward sales contracts from our Homer City
plant due to our net settlement procedures with counterparties for the period
between January 1, 2001 through June 30, 2001. Effective July 1, 2001, the
Derivative Implementaton Group of the Financial Accounting Standards Board
extended the normal sales and purchases exception to include forward sales
contracts subject to net settlement procedures with counterparties. Accordingly,
we intend to use the normal sales and purchases exception for our Homer City
forward sales contracts commencing July 1, 2001 and plan to record a cumulative
change in the accounting for derivatives during the quarter ended September 30,
2001. We are currently evaluating the impact of the implementation guidance on
our remaining commodity contracts, which would be accounted for on a prospective
basis.

Through December 31, 1999, we accrued for major maintenance costs incurred
during the period between turnarounds (referred to as "accrue in advance"
accounting method). In March 2000, we voluntarily decided to change our
accounting policy to record major maintenance costs as an expense as incurred.
This change in accounting policy is considered preferable based on guidance
provided by the Securities and Exchange Commission. In accordance with
Accounting Principles Board Opinion No. 20, "Accounting Changes," we 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 June 30, 2001, we had cash and cash equivalents of $573.4 million and had
available a total of $16 million of borrowing capacity under one of our three
revolving senior credit facilities. We had no borrowing capacity under our other
two credit facilities. 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. One of our credit
facilities was originally scheduled to mature in March 2001 but was extended
twice: first to May 2001 and then to October 2001. One of our other credit
facilities was originally scheduled to mature in May 2001 but was also extended
to October 2001.

In April 2001, we issued $600 million of 9.875% senior notes, due in 2011.
We used the proceeds of that offering to repay indebtedness, including mandatory
repayments of $225 million, which also permanently reduced the amount available
under our credit facilities. As a result of the mandatory repayments, the credit
facilities were reduced from $1.5 billion to $1.275 billion. In connection with
the sale of our 25% interest in the Hopewell project and a 50% interest in the
Sunrise project, our credit facilities were further reduced to $1.224 billion.
On August 10, 2001, we issued $400 million of 10% senior notes, due in 2008. We
used the proceeds to permanently repay indebtedness under our corporate credit
facilities, reducing the outstanding commitments under these facilities to
$823.3 million.

DISCUSSION OF HISTORICAL CASH FLOW

CASH FLOW FROM OPERATING ACTIVITIES

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 used in
operating activities totaled $372.1 million during the six months ended
June 30, 2001, compared to net cash provided by operating activities of
$68.4 million for the corresponding period of the prior year. The decrease is
primarily due to higher working capital requirements. 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.

Net working capital at June 30, 2001 was ($1,160.5) million compared to
($1,703.9) million at December 31, 2000. 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.

CASH FLOW FROM FINANCING ACTIVITIES

Net cash provided by financing activities decreased to $381.4 million for
the six months ended June 30, 2001, from $524.6 million for the six months ended
June 30, 2000. 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. In January 2000, one of our
foreign subsidiaries borrowed $242.7 million from Edison Capital, an indirect
affiliate. During the first quarter of 2001, the subordinated financing was
repaid with interest. In April 2001, we issued $600 million of 9.875% senior
notes due 2011, the proceeds of which were used to permanently repay
$225 million on our corporate credit facilities. In June 2001, an additional
$51 million was permanently repaid on our corporate credit facilities. In
addition, dividends totaling $65 million were paid to The Mission Group and
ultimately to Edison International, our ultimate parent company, during the
six-month period ended June 30, 2001, compared to $44 million during the same
prior year period. As of June 30, 2001, we had recourse debt of $2.5 billion,
with an additional $6.1 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. 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. We 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 The
Mission Group and ultimately 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 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 $2.0 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.

CASH FLOW FROM INVESTMENT ACTIVITIES

Net cash used in investing activities increased to $347.5 million for the
six months ended June 30, 2001 from $307.6 million for the six months ended
June 30, 2000 and 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. The increase
is primarily due to the equity contributions 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 during the
six-month period ended June 30, 2001. See "--The California Power Crisis and Our
Response" for further discussion. Through June 30, 2001, $3.8 million was paid
towards the purchase price and $1.5 million in equity contributions for the
Italian Wind Projects, $20 million was paid for the purchase of the 50% interest
in the CBK project and $59.5 million was paid for the purchase of additional
shares in Contact Energy. Through June 30, 2000, $27 million was paid towards
the purchase price and $13 million in equity contributions for the Italian Wind
Projects and $33.5 million was made in equity contributions for the EcoElectrica
project. In June 2001, we also competed the sale of a 50% interest in the
Sunrise project to Texaco for $84 million. We invested $113.2 million and
$178.5 million during the six-month periods ended June 30, 2001 and 2000,
respectively, in new plant equipment principally related to the Homer City plant
and Illinois Plants. 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, we also paid
$44.9 million for the Citizens trading operations and structured transaction
investments, and $27 million for the acquisition of the Sunrise project. In
addition, $21.2 million and $20 million were made in equity contributions for
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.

CORPORATE FINANCING PLANS

As discussed above, we have three corporate credit facilities scheduled to
expire on October 10, 2001 with an aggregate amount of commitments of
$1.224 billion thereunder as of June 30, 2001, which we had committed to reduce
to $1 billion in the aggregate by August 15, 2001. Our corporate cash
requirements in 2001 are expected to exceed cash distributions from our
subsidiaries. In addition to our commitment to pay down the corporate credit
facilities by $224 million, our expected corporate cash payments for the
remainder of 2001 include:

- debt service under senior notes and intercompany notes resulting from
sale-leaseback transactions which aggregate $123 million;

- equity and capital requirements for projects in development and under
construction of $67 million;

- dividends payable to Mission Energy Holding of $65 million; and

- general and administrative expenses.

We used the proceeds from the offering of the original notes to pay down a
portion of our existing corporate credit facilities. In addition, we have
entered into a new $750 million corporate credit facility. We used this new
credit facility, together with other corporate funds, to replace our existing
corporate credit facilities and repay all outstanding borrowings thereunder. The
new credit facility includes a one-year $538.3 million component that expires on
September 16, 2002 and a three-year $211.7 million component that expires on
September 17, 2004. The interest rate on borrowings under the new credit
facility are at LIBOR plus 2.375%. In addition to the interest payments, we pay
a facility fee of 0.625%.

In addition, we:

- have sold our 50% interest in the Saguaro project for $67 million which
was received in September 2001;

- have agreed to sell our interests in the Commonwealth Atlantic,
EcoElectrica, Gordonsville, James River and Nevada Sun-Peak projects
subject to obtaining consents from third parties and other conditions
precedent to closing;

- have undertaken a competitive bidding process through an investment bank
for the sale of our ownership interest in the Brooklyn Navy Yard project;
and

- are planning on obtaining project financing for the Sunrise project based
on a power purchase agreement, including construction financing for Phase
II of the project (See "--Acquisitions, Dispositions and Sale-Leaseback
Transactions--Acquisition of Sunrise Project").

We may incur additional federal and state income taxes from the proceeds of
the sale of one of our foreign projects if the sale of this project is completed
and we are required to repatriate funds to reduce senior bank indebtedness.
There is no assurance that we will be able to sell projects on favorable terms
or that the sale of individual projects will not result in a loss. We are also
considering sale-leaseback transactions of several projects, the proceeds of
which would be used to repay short-term indebtedness or to meet other capital
requirements.

SUBSIDIARY FINANCING PLANS

The estimated capital expenditures of our subsidiaries for the second half
of 2001 are $117 million, including environmental expenditures disclosed under
"Business--Regulatory Matters--Environmental Regulation." These capital
expenditures are planned to be financed by existing subsidiary credit agreements
and cash generated from their operations. Other than as described below under
"--Commitments and Contingencies," we do not plan to make additional capital
contributions to our subsidiaries.

PURCHASE OF ADDITIONAL SHARES IN CONTACT ENERGY

During the second quarter of 2001, we completed the purchase of additional
shares of Contact Energy for NZ$152 million, thereby increasing our ownership
interest from 42.6% to 51.2%. In order to finance this purchase, we obtained a
NZ$135 million, 364-day bridge loan from an investment bank under a credit
facility which is to be syndicated by the bank. In addition to other security
arrangements, a security interest over all Contact Energy shares held has been
provided as collateral. In June and July 2001, we issued through one of our
subsidiaries new preferred securities to repay the bridge loan. On July 2, 2001,
we redeemed NZ$400 million EME Taupo preferred securities from the existing
holders. Funding for the redemption of the existing preferred securities was
provided by a NZ$400 million credit facility scheduled to mature in July 2005.
The financing documents governing the credit facility provide that the credit
facility may be funded under either, or a combination, of a letter of credit
facility or a revolving credit facility. The NZ$400 million was originally
funded as a revolving credit facility.

STATUS OF EDISON FIRST POWER LOAN

The financial performance of the Fiddler's Ferry and Ferrybridge power
plants has not met our expectations, largely due to lower power prices resulting
primarily from increased competition, milder winter weather and uncertainty
surrounding the new electricity trading arrangements. See "--Market Risk
Exposures--United Kingdom."

As a result, Edison First Power has defaulted on its financing documents
related to the acquisition of the power plants. As a result of the reduced
financial performance, Edison First Power deferred some environmental capital
expenditure milestone requirements in the original capital expenditure program
set forth in the financing documents. The original capital expenditure program
has been revised, and this revision has been agreed to by the financing parties.
In addition, in July 2001, the financing parties waived technical defaults under
the financing documents and a default under the financing documents resulting
from the fact that, 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. There is no assurance that Edison First
Power's creditors will continue to waive its non-compliance with the
requirements under the financing documents or that Edison First Power will
satisfy its financial ratios in the future.

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. In
March 2001, L61 million was paid by Edison First Power to meet its semi-annual
debt service requirements.

and Ferrybridge power plants. At June 30, 2001, 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 Edison Mission Energy's guarantee remains in
force notwithstanding any breaches under Edison First Power's acquisition
financing documents.

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 offering for sale through a competitive bidding process the
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. If we are
successful at selling the Ferrybridge and Fiddler's Ferry plants, it is likely
that we will not recover any of our investment in the subsidiary that owns these
assets. At June 30, 2001, that investment was $974 million. We plan to use the
proceeds from the sale, if it occurs, to repay a portion or all of the
indebtedness of the project. We cannot provide assurance that acceptable bids
will be obtained or, if such bids are acceptable, that completion of the sale
will occur. In this regard, there is no assurance that we will be able to
negotiate acceptable terms and conditions with a potential buyer or that if an
agreement was reached, that we will be able to satisfy the conditions needed for
closing, which will include, among other things, a regulatory review in the
United Kingdom.

LIMITATIONS ON DIVIDENDS FROM THE DOGA PROJECT

Our subsidiary, Doga Enerji, owns 80% of the Doga project in Turkey. Doga
Enerji has experienced delays in receiving payments from its power purchaser
Turkiye Elektrik, A.S., also referred to as TEAS. Doga Enerji is in the process
of determining whether these delays will materially adversely affect the future
cash flow projections for the project. Until the determination is made, Doga
Enerji will not make a distribution for 2001. While such payment obligations are
guaranteed by the Turkish Treasury, we cannot assure you that TEAS will make its
payments on a timely basis.

INTERCOMPANY TAX SHARING PAYMENTS

We participate in a tax sharing agreement with The Mission Group, which in
turn participates in a tax sharing agreement with Edison International. We have
historically received tax payments under the tax sharing agreement related to
domestic net operating losses incurred by us. However, we will be required to
pay Edison International $51 million during 2001 as a result of changes in
estimated taxable income for 2000. At June 30, 2001, we have recorded
$142.5 million as an income tax receivable under the tax sharing agreement.
However, we are not eligible to receive tax sharing payments for those losses
until such time as Edison International and its subsidiaries generate sufficient
taxable income in order to be able to monetize our tax losses in the
consolidated income tax returns for Edison International and its subsidiaries.

CREDIT RATINGS

In January 2001, Standard & Poor's and Moody's downgraded our senior
unsecured credit ratings to "BBB-" from "A-" and to "Baa3" from "Baa1",
respectively. Our credit ratings remain "investment

grade." Maintaining our investment grade credit ratings is part of our current
operational focus and our long term strategy. However, we cannot assure you that
Standard & Poor's and Moody's will not downgrade our credit rating below
investment grade, whether as a result of the California power crisis or
otherwise. If our credit ratings are downgraded below investment grade, 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; and

- post a letter of credit or cash collateral to support its $58.5 million
equity contribution obligation in connection with our acquisition in
February 2001 of a 50% interest in the CBK Power Co. Ltd. project in the
Philippines, which equity contribution would otherwise be payable as
currently scheduled in 2003.

A downgrade of our credit ratings could result in a downgrade of the credit
rating of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the
event of a downgrade of Edison Mission Midwest Holdings below its current credit
ratings, 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 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.

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.

COMMITMENTS AND CONTINGENCIES

CAPITAL COMMITMENTS

The following table summarizes our consolidated capital commitments as of
June 30, 2001. 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.......... 986(1) 2001-2004 Edison Mission Energy Master
Turbine Lease

Environmental Improvements at our
Project Subsidiaries.............. 494 2001-2005 Environmental Matters and
Regulations

Project Acquisition for the
Italian Wind Projects............. 8 2001-2002 Firm Commitment for Asset Purchase

Equity Contribution for the
Sunrise Project................... 123 2001-2003 Firm Commitments to Contribute
Project Equity

Equity Contribution for the
Italian Wind Projects............. 1 2001-2002 Firm Commitments to Contribute
Project Equity

Equity Contribution for the CBK
Project........................... 59 2003 Firm Commitments to Contribute
Project Equity

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

(1) 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."

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, we committed to install one or more gas-fired power
plants having an additional gross

dependable capacity of 500 MWs at an 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.

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.

FIRM COMMITMENT FOR ASSET PURCHASE

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

Italian Wind Projects(1).................................. 18 billion Italian Lira $7.9

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

(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 ours
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)................................... 3 billion Italian Lira $ 1.4
CBK Project(2)............................................. -- 58.5
Sunrise Project(3)......................................... -- 122.9

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

(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 ours
owns a 50% interest. Equity will be contributed depending on the number of
projects that are ultimately developed.

(2) Caliraya-Botocan-Kalayaan is a 728 MW hydroelectric power project under
construction in the Philippines. A wholly-owned subsidiary of ours owns a
50% interest. Equity will be contributed upon completion of the
rehabilitation and expansion, which is currently scheduled for 2003. This
equity commitment could be accelerated if our credit rating were to fall
below investment grade.

(3) The Sunrise Project consists of two phases, with Phase I, a single-cycle
gas-fired facility (320MW) that commenced commercial operation in
June 2001, and Phase II, conversion to a combined-cycle gas-fired facility
(560 MW) currently scheduled to be completed in July 2003. A wholly-owned

subsidiary of ours owns a 50% interest. Equity will be contributed to fund
the construction of Phase II. The project intends to obtain project
financing for a portion of the capital costs.

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.

OTHER COMMITMENTS

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.

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; and 2005--$241 million.

HOMER CITY

We have 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. bank
financing to have a debt service reserve account balance in an amount equal to
six months' debt service, Edison Mission Energy provides a guarantee of Edison
Mission Holdings' obligations in the amount of $9 million to the lenders
involved in the bank financing.

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. As part of obtaining an
investment grade rating for this subsidiary, Edison Mission Energy has entered
into a support agreement, which commits it 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.

SUBSIDIARY INDEMNIFICATION AGREEMENTS

Some of our subsidiaries have entered into indemnification agreements, under
which the subsidiaries have 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
June 30, 2001, if payment were required, would be $246 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.

CONTINGENCIES

THE CALIFORNIA POWER CRISIS

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 California utilities, Southern California Edison and Pacific
Gas and Electric, 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, including us, and others. Given these and other
payment defaults, Southern California Edison could face bankruptcy at any time.
Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001.
Edison International, our ultimate parent company, is also the corporate parent
of Southern California Edison. For a description of this contingency and the
California power crisis, see "--The California Power Crisis and Our Response."

PAITON

Our wholly-owned subsidiary owns a 40% interest in PT Paiton Energy, which
owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia,
which is referred to as the Paiton project. Our investment in the Paiton project
was $503 million at June 30, 2001. Under the terms of a long-term power purchase
agreement between Paiton Energy and PT PLN, the state-owned electric utility
company, PT PLN is required to pay for capacity and fixed operating costs once
each unit and the plant achieve 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.

Paiton Energy is in continuing negotiations on a long-term restructuring of
the tariff under the power purchase agreement. Paiton Energy and PT PLN agreed
on an interim agreement for the period through December 31, 2000 and on a Phase
I Agreement for the period from January 1, 2001 through June 30, 2001. The
Phase I 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. PT PLN made all fixed and energy payments due
under the interim agreement and has made all fixed payments due under the Phase
I Agreement totaling $108 million as scheduled. Paiton Energy received lender
approval of the Phase I Agreement, and Paiton Energy has also entered into a
lender interim agreement under which lenders have effectively agreed to
interest-only payments and to deferral of principal repayments while Paiton
Energy and PT PLN seek a long-term restructuring of the tariff. The lenders have
agreed to extend that agreement through December 31, 2001. Paiton Energy and PT
PLN intended to complete the negotiations of the future phases of a new
long-term tariff during the six-month duration of the Phase I Agreement.
Although Paiton Energy and PT PLN did not complete negotiations on a long-term
restructuring of the tariff by June 30, 2001, Paiton Energy and PT PLN have
signed an agreement providing for an extension of the Phase I Agreement from
July 1, 2001 to September 30, 2001. Paiton Energy is continuing to generate
electricity to meet the power demand in the region and believes that PT PLN will
continue to agree to make payments for electricity on an interim basis beyond
June 30, 2001 while negotiations regarding long-term restructuring of the tariff
continue. Although completion of negotiations may be delayed, Paiton Energy
continues to believe that negotiations on the long-term restructuring of the
tariff will be successful.

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 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.

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. We believe that the outcome of this litigation will
not have a material adverse effect on our consolidated financial position or
results of operations.

CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY

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

Paiton(i)................................................. -- $ 5.3
ISAB(ii).................................................. 84 billion Italian Lira 36.5

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

(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 $136 million has been contributed as of June 30, 2001.

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

(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 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 "--The California Power
Crisis and Our Response" for further discussion.

THE CALIFORNIA POWER CRISIS AND OUR RESPONSE

THE CALIFORNIA POWER CRISIS

We have partnership interests in eight partnerships that own power plants in
California and 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
June 30, 2001 was $607 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 that are owned by partnerships in which we have a
partnership interest. Southern California Edison did not pay the partnerships
for power delivered between November 1, 2000 and March 26, 2001; however, in
response to the March 27, 2001 California Public Utilities Commission order
discussed below, Southern California Edison has been paying the partnerships for
power delivered after March 27, 2001. Also, following the execution of the
standstill agreements, discussed below, Southern California Edison has paid the
partnerships 10% of the past due amounts (for power delivered between
November 2000 and March 2001) and has also begun making monthly interest
payments on the past due amounts. It is possible that Southern California Edison
may miss future payments. At June 30, 2001, accounts receivable due to these
partnerships from Southern California Edison were $606 million. Our share of
these receivables was $301 million.

On April 6, 2001, Pacific Gas and Electric filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court.
Pacific Gas and Electric made its January payment in full and has paid for power
delivered after April 6, 2001, but paid only a small portion of the amounts due
to the partnerships in February and March and, as discussed below, may not pay
all or a portion of its future payments. Although Pacific Gas and Electric has
thus far paid for post-petition deliveries, future payments by Pacific Gas and
Electric to the qualifying facilities, including those owned by partnerships in
which we have a partnership interest, may be subject to significant delays
associated with the bankruptcy court process and may not be paid in full.
Furthermore, Pacific Gas and Electric's power purchase agreements with the
qualifying facilities will be subject to review by the bankruptcy court. At the
petition date, accounts receivable to these partnerships from Pacific Gas and
Electric were $47 million. Our share of these receivables was $23 million. We
cannot assure you that the partnerships with long-term contracts with Pacific
Gas and Electric will not be adversely affected by the bankruptcy proceeding.

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. During the period in which Southern California Edison failed to
make payments, some of the partnerships sought to minimize their exposure to
Southern California Edison by reducing deliveries under their power purchase
agreements. Four of the partnerships have filed complaints against Southern
California Edison with respect to the payment defaults.

All of those partnerships have entered into agreements with Southern
California Edison, under which the partnerships and Southern California Edison
will suspend the current litigation for a specified "standstill period" and
provisionally stipulate as to the amount of past due payments, and Southern
California Edison will make partial payments with respect to past due amounts.
The partial payments are to be made on the following schedule: 10% of the past
due amount to be paid within three business days after signing the agreements, a
second 10% to be paid upon the effective date of legislation that restores
Southern California Edison to creditworthiness and enables it to pay its debts
in a timely manner, and the final 80% on the fifth business day after the first
day on which Southern California Edison receives proceeds from the first
financing of the "net undercollected amount" resulting from such legislation.
The agreements also require Southern California Edison to make monthly interest
payments on past due amounts. Southern California Edison has already paid the
first 10% of the past due amounts.

It is unclear at this time what additional actions, if any, the partnerships
will take in regard to any future suspension of payments due to the qualifying
facilities by the utilities or in the event that the settlement agreements cease
to be in effect. 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 to June 30, 2001, subsidiaries of ours have made
equity contributions totaling approximately $134 million to meet capital calls
by the partnerships. Although Southern California Edison has been paying the
partnerships for power delivered after March 27, 2001 and Pacific Gas and
Electric has paid for power delivered after April 6, 2001, our subsidiaries and
the other partners may be required to make additional capital contributions to
the partnerships if the utilities fail to make future payments.

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. However, it is possible that
Southern California Edison will not pay all its obligations in full. In
addition, it is possible that creditors of Southern California Edison could file
an involuntary bankruptcy petition against Southern California Edison. 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. 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 those owned by partnerships in which we have a partnership
interest, is needed to meet California's power needs, we cannot assure you that
these settlement agreements will continue to be effective during the standstill
period, or that the power purchase agreements will not be adversely affected by
a bankruptcy or any further contract renegotiation as a result of the current
power crisis.

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. As a result
of this decision, Southern California Edison paid in full for power delivered
after March 27, 2001, and Pacific Gas and Electric paid for power delivered
after April 6, 2001 (the date it filed its bankruptcy petition). This decision
did not address payment to the qualifying facilities for amounts due prior to
March 27, 2001. In addition, the decision modified the pricing formula for
determining short-run avoided costs for qualifying facilities subject to these
provisions. Depending on the utilities' continued reaction to this order, the
impact of this decision may be that the qualifying facilities subject to this
pricing adjustment will be paid at significantly reduced prices for their power.
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
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.

On April 9, 2001, Edison International and Southern California Edison signed
a Memorandum of Understanding with the California Department of Water Resources.
The Memorandum calls for legislation, regulatory action and definitive
agreements to resolve important aspects of the energy crisis, and which the
parties expect will help restore Southern California Edison's creditworthiness
and liquidity. Edison International filed a Form 8-K on April 10, 2001, which
describes key elements of the Memorandum. Among other things, the Memorandum
provides that we will execute a contract with the Department of Water Resources
or another state agency for the provision of power from the Sunrise project to
the State at cost-based rates for ten years. We executed this contract on
June 25, 2001, and the first phase became operational on June 27, 2001.

Edison International and Southern California Edison believe that execution
of the Memorandum was an important step toward an acceptable resolution of the
major issues affecting Edison International and Southern California Edison as a
result of the California energy crisis, but this result is not assured. The
parties agreed in the Memorandum that each of its elements is part of an
integrated package, and effectuation of each element will depend upon
effectuation of the others. To implement the Memorandum, numerous actions must
be taken by the parties and by other agencies of the State of California.
Southern California Edison, Edison International and the Department of Water
Resources committed to proceed in good faith to sponsor and support the required
legislation and to negotiate in good faith the necessary definitive agreements.
However, the California Legislature, the California Public Utilities Commission,
the Federal Energy Regulatory Commission, and other

governmental entities on whose part action will be necessary to implement the
Memorandum are not parties to the Memorandum. Furthermore, the Memorandum may be
terminated by either Southern California Edison or the California Department of
Water Resources at any time because required regulatory and legislative actions
were not taken before the applicable deadlines; however, neither party has
terminated the Memorandum. The California Legislature completed its regular
session business on September 14, 2001 without passing legislation to implement
the Memorandum or otherwise restore the creditworthiness of Southern California
Edison. However, the Governor of California has stated that he will call a
special session of the Legislature to address such legislation around
October 1, 2001. Whether any legislation will be enacted is unknown. In
addition, a California voter initiative or referendum has been threatened
against any measures that would raise consumer rates or aid California's
investor-owned utilities. Finally, the enactment of legislation would not
eliminate the possibility that some of Southern California Edison's creditors
could take steps to force Southern California Edison into bankruptcy
proceedings.

On April 3, 2001, the California Public Utilities Commission adopted an
order instituting investigation. The order reopens past Commission decisions
authorizing the California investor-owned utilities to form holding companies
and initiates an investigation into: whether the holding companies violated
requirements to give priority to the capital needs of their respective utility
subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective non-utility affiliates (including us) also
violated 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. The
Memorandum calls for the Commission to adopt a decision clarifying that the
first priority condition in Southern California Edison's holding company
decision refers to equity investment, not working capital for operating costs.
On June 6, 2001, in response to motions filed by the three holding companies
(including Edison International) to dismiss the investigation for lack of
subject matter jurisdiction, the Commission issued for comment a draft decision,
which concludes, among other matters, that applicable law permits the
Commission, even if the normal common law prerequisites for piercing the
corporate structures are absent, to disregard the corporate forms within the
holding company system "to reach the assets of or challenge the behaviors of
entities within the holding company system" in order to protect ratepayers.
Commissioner Henry Duque has issued a draft alternate decision that would grant
the three holding companies' motions to dismiss the order as to themselves,
finding lack of subject matter jurisdiction over them, and would direct the
Commission's general counsel to file an action in state court to enforce the
holding company conditions, if necessary. The alternate, as well as the draft
decision that would deny the motions to dismiss, are presently on the
Commission's agenda for its October 11 meeting. Either would require a vote of
three out of five commissioners in order to be adopted. We are not a party to
this investigatory proceeding. We cannot predict whether, when or in what form
this order will be adopted, or what direct or indirect effects any subsequent
action taken by the Commission in such proceeding or in any other action or
proceeding, in reliance on the principles articulated in this order and in other
applicable authority, may have on Edison International or on us and our
subsidiaries.

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. For example, on March 27, 2001, the California Public
Utilities Commission made permanent the interim surcharge on customers' bills
that it authorized on January 4, 2001 and authorized a rate increase of three
cents per kilowatt-hour; neither this interim surcharge nor the rate increase
affected the retail rate freeze which has been in effect since deregulation
began in 1998. On April 26, 2001, the Federal Energy Regulatory Commission
ordered price mitigation measures, or price

caps, for power sales in the California spot market during emergency periods
only; on June 19, 2001, the price mitigation measures were expanded to apply
during all periods and to cover the entire eleven-state Western region. After
extensive settlement negotiations failed to produce a global settlement, on
July 25, 2001, the Federal Energy Regulatory Commission ordered that refunds may
be due from sellers who engaged in transactions in these markets from
October 2, 2000 through June 20, 2001, at levels in excess of the requirements
in the April 26 and July 19 orders (with certain modifications), and ordered an
evidentiary hearing to determine the required refunds. A separate proceeding was
also instituted to evaluate the potential for refunds in the Pacific Northwest.
The price mitigation measures end on September 30, 2002. The federal and state,
legislative and regulatory initiatives may result in a restructuring of the
California power market. At this time, it is not possible to estimate the likely
ultimate outcome of these activities.

OUR RESPONSE

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 our 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 in spite of the current credit difficulties of
Edison International, Southern California Edison and their subsidiaries. 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 either of the following
are true: 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;

- 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,
Southern California Edison or any of their subsidiaries. In January 2001, after
we implemented the ring-fencing amendments, 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. However, as a
result of the downgrades, our cost of capital has increased. Future downgrades
could further 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. The measures described above are
intended to insure that we are considered a stand-alone entity. However, in the
event of a bankruptcy of Mission Energy Holding, creditors of Mission Energy
Holding might seek to have a bankruptcy court substantially consolidate the
assets and liabilities of us with those of Mission Energy Holding.

MARKET RISK EXPOSURES

Our primary market risk exposures arise from changes in electricity and fuel
prices, interest rates 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.

COMMODITY PRICE RISK

Electric power generated at our merchant 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 Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York
Independent System Operator (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. Our Risk Management Committee grants exceptions to the policy only
after thorough review and scrutiny. 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 our risk management policies. Policies are in place that limit the amount
of total net exposure we may enter into at any point in time. Procedures exist
that 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.

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 three power
purchase agreements with Exelon Generation Company, in which Exelon Generation
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 capacity and energy payments. Exelon
Generation is obligated to make a capacity payment for the plants under contract
and an energy payment for the electricity produced by these plants and taken by
Exelon Generation. The capacity payments provide the Illinois Plants revenue for
fixed charges, and the energy payments compensate the Illinois Plants for
variable costs of production. Exelon Generation has the option to terminate two
of the three agreements in their entirety or with respect to any generating unit
or units in each of 2002, 2003 and 2004. In June 2001, Exelon Generation
provided us notice to continue the agreement related to the coal units for 2002.
If Exelon Generation 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

Since 1989, our plants in the U.K. have sold their electrical energy and
capacity through a centralized electricity pool, which established a half-hourly
clearing price, also referred to as the pool price, for electrical energy. On
March 27, 2001, this system was replaced with a bilateral physical trading
system referred to as the new electricity trading arrangements.

The new electricity trading arrangements provide for, among other things,
the establishment of a spot market or voluntary short-term power exchanges
operating from a year or more in advance to 3 1/2-hours before a trading period
of 1/2 hour; 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 is not directly
affected by the proposals. Physical bilateral contracts have replaced the prior
financial contracts for differences, but function in a similar manner. However,
it remains difficult to evaluate the future impact of the new electricity
trading arrangement. A key feature of the new 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, provided for
the implementation of the new electricity trading arrangements and the necessary
amendments to generators' licenses.

The legislation providing for the implementation of the new arrangements,
the Utilities Act 2000, sets a principal objective for the Gas and Electric
Market Authority 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 Secretary of State to issue guidance to the Gas and Electric
Market Authority on social and environmental matters, changes to the procedures
for modifying licenses and a new power for the Gas and Electric Market Authority
to impose financial penalties on companies for breach of license conditions. We
will be monitoring the operation of these new provisions. See
"Business--Regulatory Matters--Recent Foreign Regulatory Matters--United
Kingdom."

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 either in 2001 or 2002, which expire on
various dates through December 31, 2002, 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 that 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 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.

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 $9.3 million and
$9.6 million of additional interest expense for the six months ended June 30,
2001 and 2000, respectively, and $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 $819.8 million consisting of commercial
paper and bank borrowings at June 30, 2001. The fair values of these obligations
approximated their carrying values at June 30, 2001, 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 $7.7 billion at June 30, 2001. A 10% increase in market interest
rates at December 31, 2000 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.

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 6%, 8% and 9%, respectively (determined by the
change in the exchange rates from December 31, 2000 to June 30, 2001). The
decrease in value of these currencies was the primary reason for the foreign
currency translation loss of $101.2 million during the first six months of 2001
and a

$157.3 million loss 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. 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 pounds sterling. A 10% fluctuation in exchange rates would
change the fair value of the contracts at December 31, 2000 by approximately
$6 million. At June 30, 2001, the outstanding notional amount of the contracts
totaled $73 million, consisting of contracts to exchange U.S. dollars to pound
sterling with varying maturities ranging from July 2001 to July 2002. During the
first six months of 2001, we recognized a foreign exchange gain of approximately
$36,000 related to the fuel purchases underlying the contracts that matured
during the first six months of 2001.

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
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.

RECENT DEVELOPMENTS

We are considering a possible reincorporation in the State of Delaware. The
reincorporation would be accomplished through a merger with Edison Mission
Energy, a Delaware corporation and wholly-owned subsidiary of ours, in which the
Delaware corporation would be the surviving corporation. The Order Authorizing
Disposition of Jurisdiction Facilities issued by the Federal Energy Regulatory
Commission on August 24, 2001 found that our proposed transaction was consistent
with the public interest and granted our request for authority to complete the
reincorporation, subject to certain conditions. We cannot assure you that a
rehearing of the August 24, 2001 order will not be requested, and cannot provide
any assurances as to the outcome of such hearing or as to the consummation of
the reincorporation.

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, one
of the largest electric utilities in the United States. As of June 30, 2001, we
owned interests in 33 domestic and 39 international operating power projects
with aggregate generation capacity of 27,798 MW, of which our share was 22,923
MW. One domestic and five international projects totaling 1,551 MW of generating
capacity, of which our anticipated share is approximately 926 MW, are in the
construction stage. At June 30, 2001, we had consolidated assets of
$15.3 billion and total shareholder's equity of $2.7 billion.

ELECTRIC POWER INDUSTRY

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 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" below.

STRATEGIC OVERVIEW

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 our merchant plants, sell
power into markets without the certainty of long-term contracts, we conduct
power marketing, trading, and risk 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 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.

COMPETITIVE STRENGTHS

- DIVERSIFIED ASSET PORTFOLIO. In addition to owning interests in power
generation facilities in 10 countries worldwide, our portfolio is also
diversified by fuel type. As of June 30, 2001, fuel type for our portfolio
of power projects was comprised of 57% coal, 30% natural gas, 11%
hydroelectric and 2% oil and geothermal, as a percentage of our share of
aggregate generation capacity. The fuel type diversification of our
portfolio of power projects reduces our exposure to shortages or other
disruptions in the market for any particular fuel source. The geographic
diversification of our portfolio of power projects spreads our operations
across different regions and market segments, thereby allowing us to
participate in multiple segments of the domestic and international power
markets and reducing the level of risk presented by any particular market.

- BALANCED CONTRACT POSITION. The contract status of our generation
facilities reflects a blend of long-term contracts and sales from our
merchant plants. As of June 30, 2001, the majority of our MW were
generated subject to long-term power purchase contracts, which provide us
with contracted revenue streams on some portion of the output or capacity
from those generation facilities. Our remaining MW were generated by our
merchant plants which sell power into wholesale power markets. This blend
of contracted and merchant generation provides for a stream of contract
revenue while allowing us the flexibility to sell energy into wholesale
markets.

BUSINESS DESCRIPTION

OPERATION OF GENERATION FACILITIES

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 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 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.

CONTRACTED FACILITIES

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.

The majority of electric power generated at the Illinois Plants is sold
under power purchase agreements with Exelon Generation Company in which Exelon
Generation 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 to make a capacity
payment for the plants under contract and an energy payment for the electricity
produced by these plants. Exelon Generation has the option to terminate two of
the three agreements in their entirety or with respect to any generating unit or
units in each of 2002, 2003 and 2004. 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 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.

MERCHANT PLANTS

During 1999, we acquired the Homer City, Fiddler's Ferry and Ferrybridge
plants producing approximately 5,868 MW, 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
transmission lines serving both the PJM and NYISO markets. The Homer City plant
can also transmit power to the Midwestern United States.

Power from the Fiddler's Ferry and Ferrybridge and First Hydro projects is
sold into the United Kingdom electricity market. The electricity trading
mechanism in the U.K. that provided for the sale of energy to a pool has
recently been replaced with trading arrangements using bilateral contracts. See
discussion of the new electricity trading arrangement in "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Market
Risk Exposures--United Kingdom." Under the new trading arrangements, our
indirect 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 assessment of energy imbalance charges by the

systems operator. 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. 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. Edison Mission Energy is
currently considering the sale of the Ferrybridge and Fiddler's Ferry plants.

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 our 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 expiring on various dates through December 31, 2002, and which will
further mitigate against the price volatility of the electricity pool.

PROJECT DEVELOPMENT AND FINANCING

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.

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.

In the past we have relied on acquisitions to expand our portfolio of power
projects. As a result of the California power crisis, our current focus is on
operating our existing portfolio and focusing our development activities on
expanding our generation capacity at existing sites rather than pursuing
acquisition and development opportunities at our historical level. Upon
resolution of the California power crisis, we plan to focus to a greater extent
on the development of new projects.

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 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.

MARKETING AND RISK MANAGEMENT

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 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, 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.

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.

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 MANAGEMENT

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.

REGIONAL OVERVIEW OF BUSINESS SEGMENTS

As of June 30, 2001, we have ownership or leasehold interests in the
following domestic operating projects:

PRIMARY ELECTRIC NET ELECTRIC
ELECTRIC OWNERSHIP CAPACITY CAPACITY
LOCATION PURCHASER(4) TYPE OF FACILITY(5) INTEREST (IN MW) (IN MW)
------------- ------------ ------------------- ---------- -------- ------------

AMERICAS:
American Bituminous(1).......... West Virginia MPC Waste Coal 50% 80 40
Brooklyn Navy Yard(2)........... New York CE Cogeneration/EWG 50% 286 143
Coalinga(1)..................... California PG&E Cogeneration 50% 38 19
Commonwealth Atlantic(3)........ Virginia VEPCO EWG 50% 340 170
EcoElectrica(1)(3).............. Puerto Rico PREPA Cogeneration 50% 540 270
Gordonsville(1)(3).............. Virginia VEPCO Cogeneration/EWG 50% 240 120
Harbor(1)....................... California Pool EWG 30% 80 24
Homer City(1)................... Pennsylvania Pool EWG 100% 1,884 1,884
Illinois Plants Illinois EG EWG 100% 9,539 9,539
(12 projects)(1)..............
James River(3).................. Virginia VEPCO Cogeneration 50% 110 55
Kern River(1)................... California SCE Cogeneration 50% 300 150
March Point I................... Washington PSE Cogeneration 50% 80 40
March Point II.................. Washington PSE Cogeneration 50% 60 30
Mid-Set(1)...................... California PG&E Cogeneration 50% 38 19
Midway-Sunset(1)................ California SCE Cogeneration 50% 225 112
Nevada Sun-Peak(3).............. Nevada SPR EWG 50% 210 105
Saguaro(1)(3)................... Nevada SPR Cogeneration 50% 90 45
Salinas River(1)................ California PG&E Cogeneration 50% 38 19
Sargent Canyon(1)............... California PG&E Cogeneration 50% 38 19
Sunrise(1)...................... California CDWR EWG 50% 320 160
Sycamore(1)..................... California SCE Cogeneration 50% 300 150
Watson.......................... California SCE Cogeneration 49% 385 189
------ ------
Total Americas.............. 15,221 13,302
====== ======

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

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

(2) Currently offered for sale.

(3) Subsequent to June 30, 2001, an agreement to sell our project interest was
executed, with completion subject to satisfaction of closing conditions.

(4) Electric purchaser abbreviations are as follows:

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

(5) 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.

As of June 30, 2001, we have ownership or leasehold interests in the
following international operating projects:

NET
ELECTRIC ELECTRIC
PRIMARY ELECTRIC OWNERSHIP CAPACITY CAPACITY
LOCATION PURCHASER(3) INTEREST (IN MW) (IN MW)
------------ ---------------- ---------- -------- --------

EUROPE:
Derwent(1)....................................... England SE(4) 33% 214 71
Doga(1).......................................... Turkey TEAS 80% 180 144
Ferrybridge(2)................................... England Various 100% 1,989 1,989
Fiddler's Ferry(2)............................... England Various 100% 1,995 1,995
First Hydro (2 projects)......................... Wales Various 100% 2,088 2,088
Iberian Hy-Power I (5 projects).................. Spain FECSA 100%(7) 43 39
Iberian Hy-Power II (13 projects)................ Spain FECSA 100% 43 43
ISAB............................................. Italy GRTN 49% 512 251
Roosecote........................................ England NORWEB(5) 100% 220 220
------ ------
Total Europe................................... 7,284 6,840
====== ======
ASIA PACIFIC:
Contact (9 projects)............................. New Zealand Pool 51%(8) 2,247 1,033
Kwinana(1)....................................... Australia WP 70% 116 81
Loy Yang B....................................... Australia Pool(6) 100% 1,000 1,000
Paiton(1)........................................ Indonesia PLN 40% 1,230 492
TriEnergy........................................ Thailand EGAT 25% 700 175
------ ------
Total Asia Pacific............................. 5,293 2,781
------ ------
Total International............................ 27,798 22,923
====== ======

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

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

(2) Currently offered for sale.

(3) Electric purchaser abbreviations are as follows:

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

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

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

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

(7) Minority interest in three projects.

(8) Minority interest in one project.

AMERICAS

As of June 30, 2001, we had 33 operating projects in this region, all of
which are presently located in the United States and its territories. Our
Americas region is headquartered in Irvine, California with additional offices
located in Chicago, Illinois; Boston, Massachusetts; and Washington, D.C. The
region-specific strategy for the Americas region is: (i) to pursue the
acquisition and development of existing generating assets from utilities,
industrial companies and other independent power producers throughout the
region, though to a lesser extent than we had in the past and (ii) to market
energy and conduct risk management activities centered around our merchant
plants.

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.

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 MW either purchased or leased
as a result of these transactions is 9,539 MW. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--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.

On November 17, 2000, we completed a transaction with Texaco Power &
Gasification Holdings 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 had an option to repurchase at
cost a 50% interest in the project prior to its commercial operation which
commenced on June 27, 2001. On June 25, 2001, Texaco exercised its option and
repurchased a 50% interest for $84 million. As part of our acquisition of the
Sunrise project, we also: (i) acquired from Texaco two gas turbines for the
project and (ii) granted Texaco an option to acquire a 50% interest in 1,000 MW
of future power plant projects we designate. The Sunrise project consists of two
phases, with Phase I, a single-cycle gas-fired facility (320 MW), completed on
June 27, 2001, and Phase II, conversion to a combined-cycle gas-fired facility
(560 MW), currently scheduled to be completed in June 2003. On June 25, 2001, we
entered into a long-term power purchase agreement with the California Department
of Water Resources.

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 Oil & Gas Company, 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%.

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 a spot or short-term market price.

EUROPE, CENTRAL ASIA, MIDDLE EAST AND AFRICA

As of June 30, 2001, we had 26 operating projects in this region that are
located in the U.K., Turkey, Spain and Italy. 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.

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 financial performance of the Fiddler's Ferry and Ferrybridge power
plants has not met 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. As a result,
Edison First Power deferred some environmental capital expenditure milestone
requirements in the original capital expenditure program set forth in the
financing documents. The original capital expenditure program has been revised,
and this revision has been agreed to by the financing parties. In addition, in
July 2001, the financing parties waived technical defaults under the financing
documents and a default under the financing documents resulting from the fact
that 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. We cannot assure you that Edison First Power's creditors
will continue to waive its non-compliance with the requirements under the
financing documents or that Edison First Power will satisfy the financial ratios
in the future. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Liquidity and Capital Resources--Subsidiary Financing
Plans--Status of Edison First Power Loan."

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. In
March 2001 L61 million was paid by Edison First Power to meet its semi-annual
debt service requirements.

Another of our indirect 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 June 30, 2001 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.

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.

ASIA PACIFIC

As of June 30, 2001, we had 13 operating projects in this region that are
located in Australia, Indonesia, Thailand and New Zealand. Our Asia Pacific
region is headquartered in Singapore with additional offices located in
Australia, Indonesia and the Philippines.

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 728 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.

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. Since the date of acquisition, we have increased our share of
ownership in Contact Energy to 51.2%. 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 2,247 MW,
of which our share is 1,033 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--New Zealand."

over its six-month duration and for the payment for energy delivered to PT PLN
from the plant during this period. PT PLN made all fixed and energy payments due
under the interim agreement and has made all fixed payments due under the Phase
I Agreement totaling $108 million as scheduled. Paiton Energy received lender
approval of the Phase I Agreement, and Paiton Energy has also entered into a
lender interim agreement under which lenders have effectively agreed to
interest-only payments and to deferral of principal repayments while Paiton
Energy and PT PLN seek a long-term restructuring of the tariff. The lenders have
agreed to extend that agreement through December 31, 2001. Paiton Energy and PT
PLN intended to complete the negotiations of the future phases of a new
long-term tariff during the six-month duration of the Phase I Agreement.
Although Paiton Energy and PT PLN did not complete negotiations on a long-term
restructuring of the tariff by June 30, 2001, Paiton Energy and PT PLN have
signed an agreement providing for an extension of the Phase I Agreement from
July 1, 2001 to September 30, 2001. Paiton Energy is continuing to generate
electricity to meet the power demand in the region and believes that PT PLN will
continue to agree to make payments for electricity on an interim basis beyond
June 30, 2001 while negotiations regarding long-term restructuring of the tariff
continue. Although completion of negotiations may be delayed, Paiton Energy
continues to believe that negotiations on the long-term restructuring of the
tariff will be successful.

MARKETING AND RISK MANAGEMENT ACTIVITIES

We use a disciplined approach to energy marketing and risk management that
is centered around our merchant generation assets and is designed primarily to
stabilize and enhance the financial performance of those facilities. We
generally attempt to balance forward sales and purchase contracts to mitigate
market risk and secure cash flow streams. These activities enhance the
operational and financial performance of our facilities and reduce our exposure
to energy price fluctuations.

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.

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."

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 operating
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.

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
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 ultimate 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 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 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
or be licensed to sell electricity 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. Various states that have adopted electric restructuring plans
have enacted caps on the rates that may be charged to retail customers. The
duration of those caps vary from state to state. A state's public utility
commission also has the authority to determine avoided costs for qualifying
facilities and may have the authority 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. Independent power projects under certain
circumstances also may be consumers of electric power and energy under tariff
rates subject to state commission jurisdiction. The actual scope of jurisdiction
over independent power projects by state public utility commissions varies from
state to state.

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 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 CALIFORNIA POWER CRISIS--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 April 26, 2001, the
Federal Energy Regulatory Commission ordered price mitigation measures, or price
caps, for power sales in the California spot market during emergency periods
only; on June 19, 2001, the price mitigation measures were expanded to apply
during all periods and to cover the entire eleven-state Western region. The
price mitigation measures end on September 30, 2002. On January 4, 2001, the
California Public Utilities Commission authorized an interim surcharge on
customers' bills, subject to refund, which was to be applied only to ongoing
power procurement costs and was to result in rate increases of 7-15% during a
90-day period. On March 27, 2001, the California Public Utilities Commission
made the interim surcharge permanent and authorized a rate increase of three
cents per kilowatt-hour. Neither the interim surcharge nor the rate increase
affected the retail rate freeze which has been in effect since deregulation
began in 1998.

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 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. After
extensive settlement negotiations failed to produce a global settlement, on
July 25, 2001 the Federal Energy Regulatory Commission ordered that refunds may
be due from sellers who engaged in transactions in these markets from
October 2, 2000 through June 20, 2001, at levels in excess of the requirements
in the April 26 and July 19 orders (with certain modifications), and ordered an
evidentiary hearing to determine the required refunds. A separate proceeding was
also instituted to evaluate the potential for refunds in the Pacific Northwest.
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 April 3, 2001, the California Public Utilities Commission adopted an
order instituting an investigation. The order reopens past Commission decisions
authorizing California investor-owned utilities to form holding companies and
initiates an investigation into:

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

- whether ring-fencing actions by Edison International and PG&E Corporation
and their respective non-utility affiliates (including us) also violated
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.

The Memorandum signed by Edison International and Southern California Edison
with the California Department of Water Resources calls for the Commission to
adopt a decision clarifying that the first priority condition in Southern
California Edison's holding company decision refers to equity investment, not
working capital for operating costs. On June 6, 2001, in response to motions
filed by the three holding companies (including Edison International) to dismiss
the investigation for lack of subject matter jurisdiction, the Commission issued
for comment a draft decision, which concludes, among other matters, that
applicable law permits the Commission, even if the normal common law
prerequisites for piercing the corporate structures are absent, to disregard the
corporate forms within the holding company system "to reach the assets of or
challenge the behaviors of entities within the holding company system" in order
to protect ratepayers. Commissioner Henry Duque has issued a draft alternate
decision that would grant the three holding companies' motions to dismiss the
order as to themselves, finding lack of subject matter jurisdiction over them,
and would direct the Commission's general counsel to file an action in state
court to enforce the holding company conditions, if necessary. The alternate, as
well as the draft decision that would deny the motions to dismiss, are presently
on the Commission's agenda for its October 11 meeting. Either would require a
vote of 3 out of 5 commissioners in order to be adopted. We are not a party to
this investigatory proceeding. We cannot predict whether, when or in what form
this order will be adopted, or what direct or indirect effects any subsequent
action taken by the Commission in such proceeding or in any other action or
proceeding, in reliance on the principles articulated in this order and in other
applicable authority, may have on Edison International or us and our
subsidiaries.

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. As a result
of this decision, Southern California Edison paid in full for power delivered
after March 27, 2001, and Pacific Gas and Electric paid for power delivered
after April 6, 2001, the date of its bankruptcy petition. This decision did not
address payment to the qualifying facilities for amounts due prior to March 27,
2001. In addition, the decision modified the pricing formula for determining
short run avoided costs for qualifying facilities subject to these provisions.
Depending on the utilities' continued reaction to this order, the impact of this
decision may be that the qualifying facilities subject to this pricing
adjustment will be paid at significantly reduced prices for their power.
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.

RECENT FOREIGN REGULATORY MATTERS

UNITED KINGDOM--The new electricity trading arrangements provide for, among
other things, the establishment of a spot market or voluntary short-term power
exchanges operating from a year or more in advance to 3 1/2-hours before a
trading period of 1/2 hour; 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 is not directly
affected by the proposals. Physical bilateral contracts have replaced the prior
financial contracts for differences, but function in a similar manner. However,
it remains difficult to evaluate the future impact of the new electricity
trading arrangement. A key feature of the 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, provided for
the implementation of the new electricity trading arrangements and the necessary
amendments to generators' licenses.

The legislation providing for implementation of the new arrangements, the
Utilities Act 2000, sets a principal objective for the Gas and Electric Market
Authority 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 Secretary of State to issue guidance to the Gas and Electric Market
Authority on social and environmental matters, changes to the procedures for
modifying licenses and a new power for the Gas and Electric Market Authority 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 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.

When the entity providing transmission service is not a jurisdictional
public utility under the Federal Power Act, it will be required by the Federal
Energy Regulatory Commission's pro forma tariff adopted in Order No. 888 et seq.
to submit an open access transmission tariff to the Federal Energy Regulatory
Commission as a condition to taking service under a public utility's open access
transmission tariff. Nevertheless, the Federal Energy Regulatory Commission's
authority over such non-jurisdictional transmission providers, including those
from whom we purchase transmission service, and its ability to enforce the open
access requirements is limited. Accordingly, we and other transmission customers
of such non-jurisdictional entities do not have the same assurances of open
access as we would with regard to jurisdictional entities. In this regard, we
note that both Southern California Edison and another California investor-owned
utility, San Diego Gas & Electric Company, have agreed to sell their respective
electric transmission facilities to an agency of the State of California, and
that such an agency would not be subject to the Federal Energy Regulatory
Commission's jurisdiction.

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
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 that 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 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. We
expect to spend approximately $34 million for the final two quarters of 2001 and
$12 million in 2002 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 $22 million for the final two quarters of 2001 and $386 million
for the 2002--2005 period. In addition, at the Ferrybridge and Fiddler's Ferry
plants we anticipate environmental costs arising from plant modification of
approximately $18 million for the final two quarters of 2001 and $21 million for
the 2002--2005 period.

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, including the prior owners of the Homer City plant, 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 to 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. In May 2001, President Bush issued a
directive for a 90-day review of new source review "interpretation and
implementation" by the Administrator of the Environmental Protection Agency and
the Secretary of the U.S. Department of Energy. President Bush also directed the
Attorney General to review ongoing new source review legal actions to "ensure"
they are "consistent with the Clean Air Act and its

regulations." Both actions were recommendations detailed within the Bush
Administration's "National Energy Policy Task Force Report."

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.

In June 2001, Illinois passed legislation mandating the Illinois
Environmental Protection Agency to evaluate and issue a report to the Illinois
legislature addressing the need for further emissions controls on fossil
fuel-fired electric generating stations, including the potential need for
additional controls on nitrogen oxides, sulfur dioxide and mercury. The study,
which is to be submitted between September 30, 2003 and September 30, 2004, also
requires an evaluation of incentives to promote renewable energy and the
establishment of a banking system for certifying credits from voluntary
reductions of greenhouse gases. The law allows the Illinois Environmental
Protection Agency to propose regulations based on its findings no sooner than
ninety days after the issuance of its findings, and requires the Illinois
Pollution Control Board to act within one year on such proposed regulations.
Until the Illinois Environmental Protection Agency issues its findings and
proposes regulations in accordance with the findings, if such regulations are
proposed, we cannot evaluate the potential impact of this legislation on the
operations of our facilities.

Since the adoption of the United Nations Framework Convention 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.

The Kyoto Protocol has yet to be submitted to the U.S. Senate for
ratification. In March 2001, the Bush Administration announced that the United
States would not ratify the Kyoto Protocol, but would

instead offer an alternative. Various bills have been, and are expected to be,
introduced in Congress to address some of these implementing guidelines and
other aspects of climate change. Apart from the Kyoto Protocol, we may be
impacted by future federal or state legislation relating to controlling
greenhouse gas emissions.

Notwithstanding the Bush Administration position, in July 2001, environment
ministers from around the world met in Bonn, Germany and reached a compromise
agreement on the mechanics and rules of the Kyoto Protocol. The compromise
agreement is believed to clear the way for countries to begin the treaty
ratification process. The United States was the sole country not to embrace the
agreement.

We either have an equity interest in or own and operate generating plants in
the following countries:

- Australia - Spain
- Indonesia - Thailand
- Italy - Turkey
- New Zealand - The United Kingdom
- Philippines - The United States

With the exception of Turkey, all of the countries identified have ratified
the UN Framework Convention on Climate Change, as well as signed the Kyoto
Protocol. None of the countries have ratified the Kyoto Protocol, but, with the
exception of the United States, all are expected to do so by the end of 2002.
For the treaty to come into effect, it must be ratified by approximately 55
countries, representing at least 55% of the greenhouse gas emissions of the
developed world.

All of the countries, with the exception of Indonesia, the Philippines and
Thailand, are classified as Annex 1 or "developed" countries and are subject to
national greenhouse gas emission reduction targets during the period of
2008--2012 (e.g., Phase 1). Each nation is actively developing policies and
measures meant to assist it with meeting the individual national emission
targets as set out within the Kyoto Protocol.

If we do become subject to limitations on emissions of carbon dioxide from
our fossil fuel-fired electric generating plants, these requirements could have
a significant economic impact on their operations.

The Environmental Protection Agency proposed rules establishing standards
for the location, design, construction and capacity of cooling water intake
structures at new facilities, including steam electric power plants. Under the
terms of a consent decree entered into by the U.S. District Court for the
Southern District of New York in RIVERKEEPER, INC. V. WHITMAN, these regulations
must be adopted by November 9, 2001. The consent decree also requires the agency
to propose similar regulations for existing facilities by February 28, 2002, and
finalize those regulations by August 28, 2003. Until the final standards are
promulgated, we cannot determine their impact on our facilities or estimate the
potential cost of compliance.

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. As of the date of this prospectus, we are unaware of any material
liabilities under CERCLA or similar state statutes; however, we cannot assure
you that we will not incur CERCLA liability or similar state law liability in
the future.

EMPLOYEES

At June 30, 2001, Edison Mission Energy employed 3,493 people, all of whom
were full time employees and approximately 537, 147 and 1,347 of whom were
covered by collective bargaining

agreements in the United Kingdom, Australia and the United States, respectively.
We believe we have good relations with our employees. However, our subsidiary,
Midwest Generation and the union which represents the employees at the Illinois
Plants are currently in negotiations to replace the now expired collective
bargaining agreement, covering wages and working conditions. Although we cannot
predict the outcome of these negotiations, the union authorized a strike, which
began on June 28, 2001. Midwest Generation has contingency plans in place and is
operating the Illinois Plants during the strike. We believe that the impact of
the strike on the operations of the Illinois Plants will not be material.

Furthermore, Paiton Energy was sued in the Central Jakarta District Court by
the PLN Labor Union in April 2001. PT PLN, the Indonesian Minister of Mines and
Energy and the former President Director of PT PLN are also named as defendants
in the suit. The union seeks to set aside the power purchase agreement between
Paiton Energy and PT PLN and the interim agreement between Paiton Energy and its
lenders, as well as damages and other relief. The initial preliminary hearing
was held on April 30, 2001 in Jakarta. Paiton Energy and the other defendants
filed challenges to jurisdiction and moved for a dismissal of the suit, but such
actions were denied by an order dated July 23, 2001. Paiton Energy has filed a
notice of appeal. Paiton Energy believes, based upon discussions with its
Indonesian counsel, that the suit is without merit.

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 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 three Brooklyn Navy Yard
bank accounts totaling approximately $0.5 million. On the same day, the court
stayed all proceedings in the California action pending the New York action.
Brooklyn Navy Yard appealed the attachment order, and on August 24, 2001, the
California Court of Appeal heard arguments in the appeal by Brooklyn Navy Yard
and Mission Energy New York from the attachment order. In August 2001 PMNC filed
a motion to lift the stay of the California action in order to amend the
California action to add Edison Mission Energy as a defendant and as a party to
the attachment previously granted against Brooklyn Navy Yard. The motion is
scheduled to be heard in October 2001. The court took the matter under
submission and a ruling is expected within the next few months. 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. The court has recommended and the parties have agreed
to pursue mediation in the fall of 2001. 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 liquefied 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 June 30, 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. For information regarding the disposition of
EcoElectrica, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Acquisitions, Dispositions and Sale-Leaseback
Transactions--Dispositions."

OUR RELATIONSHIP WITH AFFECTED AFFILIATES

Edison Mission Energy is an indirect subsidiary of Edison International.
Edison International is a holding company. Edison International is also the
corporate parent of Southern California Edison, an electric utility that buys
and sells power in California. Both Edison International and Southern California
Edison have faced and continue to face material operating disruptions as a
result of the California power crisis. For a description of the California power
crisis, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations--The California Power Crisis and Our Response."

We are also 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.

MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

Our directors are elected by, and serve until their successors are elected
by, our sole stockholder. Our officers are elected from time to time by the
board of directors and hold office at the discretion of the board of directors.
Set forth below are our current directors and executive officers and their ages
and positions with us as of August 27, 2001.

NAME AGE POSITION
---- -------- --------------------------------------------------------

John E. Bryson....................... 58 Director, Chairman of the Board
Dean A. Christiansen................. 42 Director
Theodore F. Craver, Jr............... 49 Director
Bryant C. Danner..................... 63 Director
Alan J. Fohrer....................... 50 Director, President and Chief Executive Officer
Robert M. Edgell..................... 54 Executive Vice President and Division President of
Edison Mission Energy, Asia Pacific
William J. Heller.................... 44 Senior Vice President and Division President of Edison
Mission Energy, Europe, Central Asia, Middle East and
Africa
Ronald L. Litzinger.................. 42 Senior Vice President Worldwide Operations
Georgia R. Nelson.................... 51 Senior Vice President and President of Midwest
Generation EME, LLC
Kevin M. Smith....................... 43 Senior Vice President and Chief Financial Officer
Raymond W. Vickers................... 58 Senior Vice President and General Counsel

Described below are the principal occupations and business activities of our
directors and executive officers for the past five years, in addition to their
positions indicated above.

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 Director and Chairman of the
Board of Mission Energy Holding since its formation on June 8, 2001. 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 Boeing Company, The Times Mirror Company, and Pacific American
Income Shares, Inc. and LM Institutional Fund Advisors I, Inc.

MR. CHRISTIANSEN has been Director of Edison Mission Energy since
January 15, 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, MI since
May 1995.

MR. CRAVER has been Director of Edison Mission Energy since January 15,
2001. Mr. Craver has been Director and Chief Executive Officer of Mission Energy
Holding since its formation on June 8, 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 Director of Mission Energy Holding since its formation on
June 8, 2001. 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. Mr. Fohrer has been Director of
Mission Energy Holding since its formation on June 8, 2001. From 1998 to 2000,
Mr. Fohrer served as Chairman of the Board of Edison Mission Energy. From 1993
to 1998, Mr. Fohrer served as Vice Chairman of the Board of Edison Mission
Energy. 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, Worldwide Operations, of
Edison Mission Energy since June 1999. Mr. Litzinger served as Vice
President-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, O&M Business Development and Manager, 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.

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, 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 has also been Senior Vice
President and Chief Financial Officer of Mission

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Energy Holding since its formation on June 8, 2001. 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, Americas region.

MR. VICKERS has been Senior Vice President and General Counsel of Edison
Mission Energy since March 1999. Mr. Vickers has been Senior Vice President and
General Counsel of Mission Energy Holding since its formation on June 8, 2001.
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. Mr. Vickers originally joined
Skadden, Arps, Slate, Meagher & Flom LLP in 1989 as resident partner in the Hong
Kong office.

COMPENSATION OF DIRECTORS

Our directors do not receive any compensation for serving on our board of
directors or attending meetings thereof, except that our independent director
receives customary compensation.

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CERTAIN TRANSACTIONS AND RELATIONS WITH AFFILIATES

Specified administrative services such as payroll and employee benefit
programs, all performed by Edison International or Southern California Edison
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 have entered into a tax sharing agreement with The Mission Group, which
in turn has entered into a tax sharing agreement with Edison International. For
a further discussion of this agreement, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Intercompany Tax
Sharing Payments."

We hold interests in eight partnerships that own power plants in California.
Four of these partnerships are parties to power purchase agreements with
Southern California Edison.

Edison Mission Operation & Maintenance, Inc., our indirect, wholly-owned
subsidiary, has entered into operation and maintenance agreements with
partnerships in which we have a 50% or less ownership interest. Pursuant to the
negotiated agreements, Edison Mission Operation & Maintenance performs 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 pays for all costs incurred
with operating and maintaining the facilities and may also earn an incentive
compensation as set forth in the agreements.

In July 1999, we made an interest-free loan to Georgia R. Nelson, Senior
Vice President of Edison Mission Energy 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 Edison Mission Energy 365 days following the conclusion of her
assignment in Chicago, Illinois.

In October 2000, we made a loan to Gregory C. Hoppe who at that time was
Vice President and Director, Australia, in the amount of $350,000 in exchange
for a secured promissory note executed by Mr. Hoppe and payable to Edison
Mission Energy at simple interest of 6.37%. The entire note, together with
accrued interest, is due January 2002. Mr. Hoppe is no longer an employee of
Edison Mission Energy.

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DESCRIPTION OF THE NOTES

IN THIS "DESCRIPTION OF THE NOTES," REFERENCES TO "WE," "OUR," "OURS" AND
"US" REFER ONLY TO EDISON MISSION ENERGY, AND NOT TO ANY OF OUR DIRECT OR
INDIRECT SUBSIDIARIES OR AFFILIATES. THE FOLLOWING DESCRIPTION IS A SUMMARY OF
PROVISIONS OF THE INDENTURE AND THE NOTES. IT IS NOT A COMPLETE DESCRIPTION OF
THE NOTES AND IS SUBJECT TO, AND QUALIFIED IN ITS ENTIRETY BY, REFERENCE TO THE
NOTES AND THE INDENTURE. WE URGE YOU TO READ THE INDENTURE AND THE NOTES BECAUSE
THEY, AND NOT THIS DESCRIPTION, DEFINE YOUR RIGHTS AS A HOLDER OF THESE NOTES.
YOU MAY OBTAIN A COPY OF THE INDENTURE AND THE NOTES FROM US BY WRITING TO US AT
18101 VON KARMAN AVENUE, SUITE 1700, IRVINE, CALIFORNIA 92612.

GENERAL

We issued the original notes and will issue the exchange notes under the
indenture, dated as of August 10, 2001, between us and The Bank of New York, as
trustee. Reference to the notes includes the exchange notes unless the context
otherwise requires. The notes are our unsecured senior obligations and rank
equally in right of payment with all of our other unsubordinated indebtedness.
Because we conduct substantially all of our business through numerous
subsidiaries, all existing and future liabilities of our direct and indirect
subsidiaries are and will be effectively senior to the notes with respect to the
assets and cash flows of those subsidiaries. The notes are not guaranteed by,
and are not otherwise obligations of, our project subsidiaries and project
affiliates, or our other direct and indirect subsidiaries and affiliates.

We issued the original notes in an offering exempt from registration, in
aggregate principal amount of $400,000,000. We may, without the consent of the
holders, increase such principal amount in the future on the same terms and
conditions and with the same CUSIP number as the notes being offered in this
exchange offer. The notes will mature on August 15, 2008 and will bear interest
at the rate of 10% per annum. We will pay interest on the notes on each
February 15 and August 15, beginning on February 15, 2002, to the holders of
record on the immediately preceding February 1 and August 1. Interest on the
notes will accrue from the most recent date to which interest has been paid or,
if no interest has been paid, from August 10, 2001. Interest will be computed on
the basis of a 360-day year consisting of twelve 30-day months.

The original notes are in denominations of $100,000 and any integral
multiple of $1,000 in excess thereof.

REDEMPTION

We may redeem the notes at any time, in whole or in part, at a redemption
price equal to:

- the greater of:

(1) 100% of the principal amount of the notes being redeemed;

(2) the sum of the present values of the Remaining Scheduled Payments on
the notes being redeemed discounted to the date of redemption on a
semiannual basis (assuming a 360-day year consisting of twelve 30-day
months) at a rate equal to the Treasury Rate plus 75 basis points,

- plus, in either case, accrued and unpaid interest, if any, on the
principal amount of notes being redeemed to the redemption date.

"Remaining Scheduled Payments" means, with respect to each note that we are
redeeming, the remaining scheduled payments of the principal and interest on
that note that would be due after the related redemption date if we were not
redeeming that note. However, if the redemption date is not a

103

scheduled interest payment date with respect to that note, the amount of the
next succeeding scheduled interest payment on that note will be reduced by the
amount of interest accrued on that note to the redemption date.

"Treasury Rate" means, with respect to any redemption date, an annual rate
equal to the semiannual equivalent yield to maturity of the Comparable Treasury
Issue, assuming a price for the Comparable Treasury Issue (expressed as a
percentage of its principal amount) equal to the Comparable Treasury Price for
the redemption date. The semiannual equivalent yield to maturity will be
computed as of the third business day immediately preceding the redemption date.

"Comparable Treasury Issue" means the United States Treasury security
selected by Credit Suisse First Boston Corporation or an affiliate as having a
maturity comparable to the remaining term of the notes that would be utilized,
at the time of selection and in accordance with customary financial practice, in
pricing new issues of corporate debt securities of comparable maturity to the
remaining term of the notes.

"Comparable Treasury Price" means the average of three Reference Treasury
Dealer Quotations provided to the trustee in respect of the notes to be redeemed
on the applicable redemption date.

"Reference Treasury Dealer Quotation" means, with respect to each Reference
Treasury Dealer and any redemption date, the average, as determined by us, of
the bid and asked prices for the Comparable Treasury Issue (expressed in each
case as a percentage of its principal amount) quoted in writing to us by a
Reference Treasury Dealer at 3:30 p.m., New York City time, on the third
business day preceding the redemption date.

"Reference Treasury Dealers" means Credit Suisse First Boston Corporation
(so long as it continues to be a primary U.S. Government securities dealer) and
any two other primary U.S. Government securities dealers chosen by us. If Credit
Suisse First Boston Corporation ceases to be a primary U.S. Government
securities dealer, we will appoint in its place another nationally recognized
investment banking firm that is a primary U.S. Government securities dealer.

We will give notice to The Depository Trust Company ("DTC") and holders of
definitive notes at least 30 days (but not more than 60 days) before we redeem
the notes. If we redeem only some of the notes, DTC's practice is to choose by
lot the amount to be redeemed from the notes held by each of its participating
institutions. DTC will give notice to these participants, and these participants
will give notice to any "Street Name" holders of any indirect interests in the
notes according to arrangements among them. These notices may be subject to
statutory or regulatory requirements. We will not be responsible for giving
notice of a redemption of the notes to anyone other than DTC and holders of
definitive notes.

CERTAIN COVENANTS

RESTRICTIONS ON LIENS

We will agree not to:

(X) pledge, mortgage, hypothecate or permit to exist any mortgage, pledge or
other lien upon any property at any time directly owned by us to secure any
indebtedness for money borrowed which is incurred, issued, assumed or guaranteed
by us ("Indebtedness"), or

(Y) cause or permit any of our subsidiaries to pledge, mortgage, hypothecate
or permit to exist any mortgage, pledge or other lien upon any property at any
time directly owned by them to secure any Indebtedness of ours,

without, in each such case, providing for the notes to be equally and
ratably secured with any and all such Indebtedness and with any other
Indebtedness similarly entitled to be equally and ratably

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secured; PROVIDED, HOWEVER, that the restrictions set forth in clauses (X) and
(Y) above will not apply to, or prevent the creation or existence of:

(1) liens existing at the original date of issuance of the notes;

(2) purchase money liens which do not exceed the cost or value of the
purchased property;

(3) other liens not to exceed 10% of our Consolidated Net Tangible
Assets, PROVIDED that:

(A) neither we nor our subsidiaries will be permitted to create or to
permit to exist any liens to secure our Indebtedness in reliance upon
this item (3) until the earlier to occur of:

(x) the first date on or after the second anniversary of the
consummation of the offering of the notes on which the notes are
rated at least BBB- by Standard & Poor's and Baa3 by Moody's, and

(y) the date on which Standard & Poor's rates the notes BBB or
higher and Moody's rates the notes Baa2 or higher; and

(B) notwithstanding the restriction in clause (A) above, we and our
subsidiaries will be permitted to create and permit to exist liens in
reliance upon this item (3) to secure Indebtedness not to exceed
$100 million in the aggregate;

(4) liens granted in connection with extending, renewing, replacing or
refinancing in whole or in part the Indebtedness (including, without
limitation, increasing the principal amount of such Indebtedness, other than
the Indebtedness referred to in item (3)(B)) secured by liens described in
clauses (1) through (3) above; and

(5) liens granted by any of our subsidiaries on the capital stock or
assets of any project subsidiary in order to secure any Indebtedness that we
incur (other than Indebtedness the proceeds of which are used to finance the
equity contributed by us, or loans made by us, to a project) in order to
finance or refinance any acquisition, development, construction, expansion,
operation or maintenance of such project subsidiary.

"Consolidated Net Tangible Assets" means, as of any date of determination,
the total amount of all our assets, determined on a consolidated basis in
accordance with generally accepted accounting principles as of such date, less
the sum of:

(a) our consolidated current liabilities, determined in accordance with
generally accepted accounting principles, and

(b) our assets that are properly classified as intangible assets in
accordance with generally accepted accounting principles, except for any
intangible assets which are distribution or related contracts with an
assignable value.

If we propose to pledge, mortgage or hypothecate any property at any time
directly owned by us to secure any Indebtedness, other than as permitted by
clauses (1) through (5) of the second previous paragraph, we will agree to give
prior written notice thereof to the trustee, who will give notice to the holders
of notes, and we will further agree, prior to or simultaneously with such
pledge, mortgage or hypothecation, effectively to secure all the notes equally
and ratably with such Indebtedness.

Except as set forth above, this covenant will not restrict the ability of
our subsidiaries and affiliates to pledge, mortgage, hypothecate or permit to
exist any mortgage, pledge or lien upon their assets, in connection with project
financings, sale-leasebacks or otherwise.

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MERGER, CONSOLIDATION, SALE, LEASE OR CONVEYANCE

We will agree not to merge or consolidate with or into any other person and
we will agree not to sell, lease or convey all or substantially all our assets
to any person, unless (1) we are the continuing corporation, or the successor
corporation or the person that acquires all or substantially all our assets is a
corporation organized and existing under the laws of the United States or a
State thereof or the District of Columbia and expressly assumes all our
obligations under the notes and the indenture, (2) immediately after such
merger, consolidation, sale, lease or conveyance, there is no default or Event
of Default (as defined below) under the indenture, (3) if, as a result of the
merger, consolidation, sale, lease or conveyance, any or all of our property
would become the subject of a lien that would not be permitted by the indenture,
we secure the notes equally and ratably with the obligations secured by that
lien and (4) we deliver or cause to be delivered to the trustee an officers'
certificate and opinion of counsel each stating that the merger, consolidation,
sale, lease or conveyance comply with the indenture.

The meaning of the term "all or substantially all the assets" has not been
definitely established and is likely to be interpreted by reference to
applicable state law if and at the time the issue arises and will be dependent
on the facts and circumstances existing at the time.

Except for a sale of all or substantially all our assets as provided above,
and other than assets we are required to sell to conform with governmental
regulations, we may not sell or otherwise dispose of any assets (other than
short-term, readily marketable investments purchased for cash management
purposes with funds not representing the proceeds of other asset sales) if, on a
pro forma basis, the aggregate net book value of all such sales during the most
recent 12-month period would exceed 10% of our Consolidated Net Tangible Assets
(as defined above) computed as of the end of the most recent quarter preceding
such sale; provided, however, that any such sales shall be disregarded for
purposes of this 10% limitation if the proceeds are invested in assets in
similar or related lines of our business; and, provided further, that we may
sell or otherwise dispose of assets in excess of this 10% limitation if we
retain the proceeds from such sales or dispositions, which are not reinvested as
provided above, as cash or cash equivalents or if we use the proceeds from such
sales to purchase and retire notes or to reduce or retire Indebtedness ranking
equal in right of payment to the notes or indebtedness of our subsidiaries.

REPORTING OBLIGATIONS

We will agree to furnish or cause to be furnished to holders of notes copies
of our annual reports and of the information, documents and other reports that
we are required to file with the Securities and Exchange Commission pursuant to
Section 13 or 15(d) of the Exchange Act within 15 days after we file them with
the Securities and Exchange Commission.

ADDITIONAL COVENANTS

Subject to certain exceptions and qualifications, we will agree in the
indenture to do, among other things, the following:

(1) deliver to the trustee copies of all reports that we file with the
Securities and Exchange Commission;

(2) deliver to the trustee annual officers' certificates with respect to
our compliance with our obligations under the indenture;

(3) maintain our corporate existence, subject to the provisions
described above relating to mergers and consolidations;

(4) pay our taxes when due, except when we are contesting such taxes in
good faith; and

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(5) following the effectiveness of any registration statement filed by
us pursuant to the registration rights agreement, we will maintain our
status as a reporting company under the Exchange Act whether or not the
Securities and Exchange Commission rules and regulations require us to
maintain that status and file copies of all such information and reports
with the Securities and Exchange Commission within the time periods
specified in the rules and regulations (unless the Securities and Exchange
Commission will not accept the filing of the applicable reports) or pay an
additional interest rate on the notes in the amount of one half of one
percent (50 basis points) per annum.

MODIFICATION OF THE INDENTURE

The indenture will contain provisions permitting us and the trustee, with
the consent of the holders of at least a majority in aggregate principal amount
of notes then outstanding, to modify or amend the indenture or the rights of the
holders of notes. However, no such modification or amendment may, without the
consent of the holder of each outstanding note affected thereby:

(a) change the stated maturity of the principal of, or extend the time
of payment of interest on, any note;

(b) reduce the principal amount of, or interest on, any note;

(d) reduce any amount payable upon the redemption of any note; or

(e) impair the right to institute suit for the enforcement of any
payment on or with respect to any note.

In addition, without the consent of the holders of all notes then
outstanding, no such modification or amendment may:

(x) reduce the percentage in principal amount of outstanding notes the
consent of whose holders is required for modification or amendment of the
indenture;

(y) reduce the percentage in principal amount of outstanding notes
necessary for waiver of compliance with certain provisions of the indenture
or for waiver of certain defaults; or

(z) modify such provisions with respect to modification and waiver.

The holders of at least a majority in principal amount of the outstanding
notes may waive our compliance with certain restrictive provisions of the
indenture. The holders of a majority in principal amount of the outstanding
notes may waive any past default under the indenture, except a default in the
payment of principal or interest and certain covenants and provisions of the
indenture which cannot be amended without the consent of the holder of each
outstanding note affected.

We and the trustee may, without the consent of any holder of notes, amend
the indenture and the notes for the purpose of curing any ambiguity, or of
curing, correcting or supplementing any defective provision thereof, or in any
manner that we and the trustee may determine is not inconsistent with the
indenture and the notes and will not adversely affect the interest of any holder
of notes.

EVENTS OF DEFAULT

Each of the following will be an "Event of Default" under the indenture:

(a) our failure to pay any interest on any note when due, which failure
continues for 30 days; or

(b) our failure to pay principal or premium when due; or

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(c) our failure to perform any other covenant in the notes or the
indenture for a period of 90 days after the trustee or the holders of at
least 25% in aggregate principal amount of the notes gives us written notice
of our failure to perform; or

(d) an event of default occurring under any of our instruments under
which there may be issued, or by which there may be secured or evidenced,
any Indebtedness for money borrowed that has resulted in the acceleration of
such Indebtedness, or any default occurring in payment of any such
Indebtedness at final maturity (and after the expiration of any applicable
grace periods), other than:

(i) Indebtedness which is payable solely out of the property or
assets of a partnership, joint venture or similar entity of which we or
any of our subsidiaries or affiliates is a participant, or which is
secured by a lien on the property or assets owned or held by such entity,
without further recourse to or liability of us; or

(ii) Indebtedness, excluding (i) above, not exceeding $20,000,000; or

(e) one or more nonappealable final judgments, decrees or orders of any
court, tribunal, arbitrator, administrative or other governmental body or
similar entity for the payment of money aggregating more than $20,000,000
shall be rendered against us (excluding the amount thereof covered by
insurance) and shall remain undischarged, unvacated and unstayed for more
than 90 days, except while being contested in good faith by appropriate
proceedings; or

(f) certain events of bankruptcy, insolvency or reorganization in
respect of us.

If any Event of Default (other than an Event of Default due to certain
events of bankruptcy, insolvency or reorganization) has occurred and is
continuing, either the trustee or the holders of not less than 25% in principal
amount of the notes outstanding under the indenture may declare the principal of
all notes under the indenture and interest accrued thereon to be due and payable
immediately.

The trustee will be entitled, subject to the duty of the trustee during a
default to act with the required standard of care, to be indemnified by the
holders of notes before proceeding to exercise any right or power under the
indenture at the request of such holders. Subject to such provisions in the
indenture for the indemnification of the trustee and certain other limitations,
the holders of a majority in principal amount of the notes then outstanding may
direct the time, method and place of conducting any proceeding for any remedy
available to the trustee or exercising any trust or power conferred on the
trustee.

No holder of notes may institute any action against us under the indenture
(except actions for payment of overdue principal or interest) unless:

(1) such holder previously has given the trustee written notice of the
default and continuance thereof;

(2) the holders of not less than 25% in principal amount of the notes
then outstanding have requested the trustee to institute such action and
offered the trustee reasonable indemnity;

(3) the trustee has not instituted such action within 60 days of the
request; and

(4) the trustee has not received direction inconsistent with such
written request from the holders of a majority in principal amount of the
notes then outstanding.

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DEFEASANCE AND COVENANT DEFEASANCE

DEFEASANCE

We will be deemed to have paid and will be discharged from any and all
obligations in respect of the notes on the 123rd day after we have made the
deposit referred to below, and the provisions of the indenture will cease to be
applicable with respect to the notes (except for, among other matters, certain
obligations to register the transfer of or exchange of the notes, to replace
stolen, lost or mutilated notes, to maintain paying agencies and to hold funds
for payment in trust) if:

(A) we have deposited with the trustee, in trust, money and/or certain
U.S. government obligations that, through the payment of interest and
principal in respect thereof in accordance with their terms, will provide
money in an amount sufficient to pay the principal of, premium, if any, and
accrued interest on the notes at the time such payments are due in
accordance with the terms of the indenture;

(B) we have delivered to the trustee:

(i) an opinion of counsel to the effect that note holders will not
recognize income, gain or loss for federal income tax purposes as a
result of the defeasance and will be subject to federal income tax on the
same amount and in the same manner and at the same times as would have
been the case if such deposit, defeasance and discharge had not occurred,
which opinion of counsel must be based upon a ruling of the Internal
Revenue Service to the same effect or a change in applicable federal
income tax law or related treasury regulations after the date of the
indenture; and

(ii) an opinion of counsel to the effect that the defeasance trust
does not constitute an "investment company" within the meaning of the
Investment Company Act of 1940 and after the passage of 123 days
following the deposit, the trust fund will not be subject to the effect
of Section 547 of the U.S. Bankruptcy Code or Section 15 of the New York
Debtor and Creditor Law;

(C) immediately after giving effect to such deposit, no Event of
Default, or event that after the giving of notice or lapse of time or both
would become an Event of Default, will have occurred and be continuing on
the date of such deposit or during the period ending on the 123rd day after
the date of such deposit, and such deposit shall not result in a breach or
violation of, or constitute a default under, any other agreement or
instrument to which we are a party or by which we are bound; and

(D) if at such time the notes are listed on a national securities
exchange, we have delivered to the trustee an opinion of counsel to the
effect that the notes will not be delisted as a result of such deposit and
discharge.

DEFEASANCE OF CERTAIN COVENANTS AND CERTAIN EVENTS OF DEFAULT

The provisions of the indenture will cease to be applicable with respect to:

(x) the covenants described in "--Certain Covenants" (other than those
with respect to the maintenance of our existence and those described under
the first paragraph of the caption "--Certain Covenants--Merger,
Consolidation, Sale, Lease or Conveyance" and other than those described in
clauses (2)-(5) under "--Certain Covenants--Additional Covenants");

(y) clause (c) in "--Events of Default" with respect to such covenants;
and

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(z) clauses (d) and (e) in "--Events of Default" upon

(1) the deposit with the trustee, in trust, of money and/or certain
U.S. government obligations that through the payment of interest and
principal in respect thereof in accordance with their terms will provide
money in an amount sufficient to pay the principal of, premium, if any,
and accrued interest on the notes,

(2) the satisfaction of the conditions described in clauses (B)(ii),
(C) and (D) of the preceding paragraph, and

(3) our delivery to the trustee of an opinion of counsel to the
effect that, among other things, the holders of the notes will not
recognize income, gain or loss for federal income tax purposes as a
result of such deposit and defeasance and will be subject to federal
income tax on the same amount and in the same manner and at the same
times as would have been the case if such deposit and defeasance had not
occurred.

DEFEASANCE AND CERTAIN OTHER EVENTS OF DEFAULT

If we exercise our option to omit compliance with certain covenants and
provisions of the indenture as described in the immediately preceding paragraph
and the notes are declared due and payable because of the occurrence of an Event
of Default that remains applicable, the amount of money and/or U.S. government
obligations on deposit with the trustee may not be sufficient to pay amounts due
on the notes at the time of acceleration resulting from such Event of Default.
In such event, we will remain liable for such payments.

BOOK-ENTRY; DELIVERY AND FORM

The certificates representing the exchange notes will be issued in fully
registered form. Except as described below, the exchange notes initially will be
represented by one or more global notes, in definitive, fully registered form
without interest coupons. The global notes will be deposited with the trustee as
custodian for DTC and registered in the name of Cede & Co. or another nominee as
DTC may designate.

DTC has advised us as follows:

- DTC is a limited purpose trust company organized under the laws of the
State of New York, a "banking organization" within the meaning of the New
York Banking Law, a member of the Federal Reserve System, a "clearing
corporation" within the meaning of the Uniform Commercial Code and a
"clearing agency" registered pursuant to the provision of Section 17A of
the Exchange Act.

- DTC was created to hold securities for its participants and to facilitate
the clearance and settlement of securities transactions between
participants through electronic book-entry changes in accounts of its
participants, thus eliminating the need for physical movement of
certificates. Participants include securities brokers and dealers, banks,
trust companies and clearing corporations and other organizations.
Indirect access to the DTC system is available to others, including banks,
brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a participant, either directly or indirectly.

- Upon the issuance of the global notes, DTC or its custodian will credit,
on its internal system, the respective principal amounts of the exchange
notes represented by the global notes to the accounts of persons who have
accounts with DTC. Ownership of beneficial interests in the global notes
will be limited to persons who have accounts with DTC or persons who hold
interests through the persons who have accounts with DTC. Persons who have
accounts with DTC are referred to as "participants." Ownership of
beneficial interests in the global notes will be shown

110

on, and the transfer of that ownership will be effected only through,
records maintained by DTC or its nominee, with respect to interests of
participants, and the records of participants, with respect to interests
of persons other than participants.

So long as DTC or its nominee is the registered owner or holder of the
global notes, DTC or the nominee, as the case may be, will be considered the
sole record owner or holder of the exchange notes represented by the global
notes for all purposes under the indenture and the exchange notes. No beneficial
owners of an interest in the global notes will be able to transfer that interest
except according to DTC's applicable procedures, in addition to those provided
for under the indenture. Owners of beneficial interests in the global notes will
not:

- be entitled to have the exchange notes represented by the global notes
registered in their names,

- receive or be entitled to receive physical delivery of certificated notes
in definitive form, and

- be considered to be the owners or holders of any exchange notes under the
global notes.

Accordingly, each person owning a beneficial interest in the global notes
must rely on the procedures of DTC and, if a person is not a participant, on the
procedures of the participant through which that person owns its interests, to
exercise any right of a holder of exchange notes under the global notes. We
understand that under existing industry practice, in the event an owner of a
beneficial interest in the global notes desires to take any action that DTC, as
the holder of the global notes, is entitled to take, DTC would authorize the
participants to take that action, and that the participants would authorize
beneficial owners owning through the participants to take that action or would
otherwise act upon the instructions of beneficial owners owning through them.

Payments of the principal of, premium, if any, and interest on the exchange
notes represented by the global notes will be made to DTC or its nominee, as the
case may be, as the registered owner of the global notes. Neither we, the
trustee, nor any paying agent will have any responsibility or liability for any
aspect of the records relating to or payments made on account of beneficial
ownership interests in the global notes or for maintaining, supervising or
reviewing any records relating to the beneficial ownership interests.

We expect that DTC or its nominee, upon receipt of any payment of principal
of, premium, if any, or interest on the global notes will credit participants'
accounts with payments in amounts proportionate to their respective beneficial
ownership interests in the principal amount of the global notes, as shown on the
records of DTC or its nominee. We also expect that payments by participants to
owners of beneficial interests in the global notes held through these
participants will be governed by standing instructions and customary practices,
as is now the case with securities held for the accounts of customers registered
in the names of nominees for these customers. These payments will be the
responsibility of these participants.

Transfer between participants in DTC will be effected in the ordinary way in
accordance with DTC rules. If a holder requires physical delivery of notes in
certificated form for any reason, including to sell notes to persons in states
which require the delivery of the notes or to pledge the notes, a holder must
transfer its interest in the global notes in accordance with the normal
procedures of DTC and the procedures described in the indenture.

Unless and until they are exchanged in whole or in part for certificated
exchange notes in definitive form, the global notes may not be transferred
except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or
another nominee of DTC.

Beneficial owners of exchange notes registered in the name of DTC or its
nominee will be entitled to be issued, upon request, exchange notes in
definitive certificated form.

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DTC has advised us that DTC will take any action permitted to be taken by a
holder of notes, including the presentation of notes for exchange as described
below, only at the direction of one or more participants to whose account the
DTC interests in the global notes are credited. Further, DTC will take any
action permitted to be taken by a holder of notes only in respect of that
portion of the aggregate principal amount of notes as to which the participant
or participants has or have given that direction.

Although DTC has agreed to these procedures in order to facilitate transfers
of interests in the global notes among participants of DTC, it is under no
obligation to perform these procedures, and may discontinue them at any time.
Neither we nor the trustee will have any responsibility for the performance by
DTC or its participants or indirect participants of their respective obligations
under the rules and procedures governing their operations.

Subject to specified conditions, any person having a beneficial interest in
the global notes may, upon request to the trustee, exchange the beneficial
interest for exchange notes in the form of certificated notes. Upon any issuance
of certificated notes, the trustee is required to register the certificated
notes in the name of, and cause the same to be delivered to, the person or
persons, or the nominee of these persons. In addition, if DTC is at any time
unwilling or unable to continue as a depositary for the global notes, and a
successor depositary is not appointed by us within 90 days, we will issue
certificated notes in exchange for the global notes.

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EXCHANGE OFFER; REGISTRATION RIGHTS

As part of the sale of the original notes, under a registration rights
agreement, dated as of August 10, 2001, we agreed with the initial purchasers in
the offering of the original notes, for the benefit of the holders of the notes,
to file with the SEC an exchange offer registration statement or, if applicable,
within a specified time period, a shelf registration statement unless we were to
determine in good faith that applicable SEC policy or applicable law did not
permit us to effect this exchange offer. Under the registration rights
agreement, we agreed to use our reasonable best efforts to cause to become
effective a registration statement with respect to a registered offer to
exchange the original notes for a like amount of the exchange notes that are
identical in all material respects to the restricted original notes. We agreed
to bear all expenses incurred in connection with our obligations under the
registration rights agreement. Once this registration statement is declared
effective, we will offer the exchange notes in return for surrender of the
original notes. This offer will remain open for no less than the shorter of
30 days after the date notice of the exchange offer is mailed to the original
note holders and the period ending when the last remaining original note is
tendered into the exchange offer. For each original note surrendered to us under
the exchange offer, the original note holder will receive exchange notes in an
equal principal amount. Interest on each exchange note will accrue from the last
date on which interest was paid on the original note so surrendered or, if no
interest has been paid, since August 10, 2001.

In the event that we reasonably determine in good faith that (1) the
exchange notes would not be tradeable, upon receipt in the exchange offer,
without restriction, (2) the SEC is unlikely to permit the exchange offer
registration statement to become effective prior to the 270th day after the date
of original issue of the notes or (3) the exchange offer may not be made in
compliance with applicable laws, we will use our reasonable best efforts,
subject to customary representations and agreements of the note holders, to have
a shelf registration statement covering the resale of the original notes
declared effective and kept effective until August 10, 2003, subject to
specified exceptions. We will, in the event of a shelf registration, provide to
each note holder copies of the prospectus, notify each note holder when a
registration statement for the notes has become effective and take other actions
as are appropriate to permit resale of the notes.

In the event that the exchange offer registration statement does not become
effective on or prior to the 270th day after the date of original issue of the
notes, the annual interest rates on the notes will be increased by 0.50% per
annum from and after that date to, but excluding, the date the registration
statement becomes effective and the exchange offer is commenced or a shelf
registration statement becomes effective. In the event that a registration
statement is required to be filed with the SEC and becomes effective and later
ceases to be effective at any time during the period specified by the
registration rights agreement, the annual interest rate on the notes will be
increased by 0.50% per annum from and after the date such registration statement
ceases to be effective to, but excluding, such date when the registration
statement again becomes effective and an exchange offer has commenced or a shelf
registration statement has become effective (or, if earlier, the end of such
period specified by the registration rights agreement). Such additional interest
will be paid to note holders on a regular distribution date. The interest rate
on the notes will be increased by 0.50% per annum if we cease to maintain our
status as a reporting company under the Exchange Act whether or not the SEC
rules and regulations require us to maintain that status (unless the SEC will
not accept the filing of the applicable reports). In the event that more than
one of the aforementioned events occurs at the same time, the maximum increase
in the interest rate applicable to the notes shall be 0.50% per annum.

Each note holder, other than specified holders, who wishes to exchange its
original notes for exchange notes in the exchange offer will be required to
represent that:

- it is not our affiliate;

- any exchange notes to be acquired by it will be acquired in the ordinary
course of business; and

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- that at the time of the completion of the exchange offer it will have no
arrangement with any person to participate in the distribution, within the
meaning of the Securities Act, of the exchange notes.

A note holder that sells its notes under a shelf registration generally:

- would be required to be named as a selling holder in the related
prospectus and to deliver a prospectus to purchasers;

- will be subject to certain of the civil liability provisions under the
Securities Act in connection with this sale; and

- will be required to agree in writing to be bound by the provisions of the
registration rights agreement which are applicable to the selling note
holder, including specified indemnification obligations.

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following summary describes certain material United States federal
income tax considerations of the acquisition, ownership and disposition of the
exchange notes. The summary is based on the Internal Revenue Code of 1986, as
amended (the "Code"), and regulations, rulings and judicial decisions as of the
date hereof, all of which may be repealed, revoked or modified with possible
retroactive effect. This discussion does not deal with holders that may be
subject to special tax rules (including, but not limited to, insurance
companies, tax-exempt organizations, financial institutions, dealers in
securities or currencies, holders whose functional currency is not the United
States dollar or holders who will hold the exchange notes as a hedge against
currency risks or as part of a straddle, synthetic security, conversion
transaction or other integrated investment comprised of the notes and one or
more other investments). The summary is applicable only to purchasers that
acquired the original notes pursuant to the offering at the initial offering
price and who will hold the exchange notes as capital assets within the meaning
of Section 1221 of the Code. This summary is for general information only and
does not address all aspects of United States federal income taxation that may
be relevant to holders of the exchange notes in light of their particular
circumstances, and it does not address any tax consequences arising under the
laws of any state, local or foreign taxing jurisdiction. Prospective holders
should consult their own tax advisors as to the particular tax consequences to
them of acquiring, holding or disposing of the exchange notes.

As used herein, the term "United States Holder" means a beneficial owner of
a note that is (i) a citizen or resident of the United States for United States
federal income tax purposes, (ii) a corporation or partnership (or any entity
treated as a corporation or partnership for United States federal income tax
purposes) created or organized under the laws of the United States, any state
thereof or the District of Columbia, (iii) an estate the income of which is
subject to United States federal income tax without regard to its source or
(iv) a trust if (x) a court within the United States is able to exercise primary
supervision over the administration of the trust and one or more United States
persons have the authority to control all substantial decisions of the trust or
(y) the trust has a valid election in effect under applicable United States
Treasury regulations to be treated as a United States Holder. If a partnership
(including any entity treated as a partnership for United States federal income
tax purposes) is a holder of the notes, the United States federal income tax
treatment of a partner in such a partnership will generally depend on the status
of the partner and the activities of the partnership. Partners in such a
partnership should consult their own tax advisors as to the particular federal
income tax consequences applicable to them.

A "Non-United States Holder" is any beneficial holder of a note that is not
a United States Holder.

For United States federal income tax purposes, a beneficial owner of an
original note will not recognize any taxable gain or loss on the exchange of the
original notes for exchange notes under the exchange offer, and a beneficial
owner's tax basis and holding period in the exchange notes will be the same as
in the original notes.

UNITED STATES HOLDERS

Stated interest on an exchange note generally will be taxable to a United
States Holder as ordinary income at the time it accrues or is received in
accordance with the United States Holder's method of accounting for United
States federal income tax purposes.

Upon the sale, exchange, redemption, retirement or other disposition of an
exchange note, a United States Holder generally will recognize gain or loss
equal to the difference between the amount realized upon the sale, exchange,
redemption, retirement or other disposition (not including amounts attributable
to accrued but unpaid interest, which will be taxable as ordinary income) and
such United States Holder's adjusted tax basis in the exchange note. A United
States Holder's adjusted tax basis in

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an exchange note will, in general, be the United States Holder's adjusted tax
basis in the original note exchanged for the exchange note, less any principal
payments received by such holder. Such gain or loss will generally be capital
gain or loss. Capital gain recognized by an individual investor upon a
disposition of an exchange note that has been held for more than 12 months will
generally be subject to a maximum tax rate of 20% or, in the case of an exchange
note that has been held for 12 months or less, will be subject to tax at
ordinary income tax rates. A United States Holder's holding period for an
exchange note will include the holding period of the original note exchanged for
the exchange note.

NON-UNITED STATES HOLDERS

Under present United States federal income tax law, subject to the
discussion of backup withholding and information reporting below:

(a) payments of interest on the exchange notes to any Non-United States
Holder will not be subject to United States federal income, branch profits
or withholding tax provided that (i) the Non-United States Holder does not
actually or constructively own 10% or more of the total combined voting
power of all classes of our stock entitled to vote, (ii) the Non-United
States Holder is not a bank receiving interest on an extension of credit
pursuant to a loan agreement entered into in the ordinary course of its
trade or business, (iii) the Non-United States Holder is not a controlled
foreign corporation that is related to us (directly or indirectly) through
stock ownership, (iv) such interest payments are not effectively connected
with a United States trade or business, (v) the Non-United States Holder is
not a foreign tax exempt organization or foreign private foundation for
United States federal income tax purposes and (vi) certain certification
requirements are met. Such certification will be satisfied if the beneficial
owner of the exchange note certifies on IRS Form W-8 BEN or a substantially
similar substitute form, under penalties of perjury, that it is not a United
States person and provides its name and address, and (x) such beneficial
owner files such form with the withholding agent or (y) in the case of an
exchange note held through a foreign partnership or intermediary, the
beneficial owner and the foreign partnership or intermediary satisfy
certification requirements of applicable United States Treasury regulations;
and

(b) a Non-United States Holder will not be subject to United States
federal income or branch profits tax on gain realized on the sale, exchange,
redemption, retirement or other disposition of an exchange note, unless
(i) the gain is effectively connected with a trade or business carried on by
such holder within the United States or, if a treaty applies (and the holder
complies with applicable certification and other requirements to claim
treaty benefits), is generally attributable to a United States permanent
establishment maintained by the holder, or (ii) the holder is an individual
who is present in the United States for 183 days or more in the taxable year
of disposition and certain other requirements are met.

An exchange note held by an individual who at the time of death is not a
citizen or resident of the United States will not be subject to United States
federal estate tax with respect to an exchange note as a result of such
individual's death, provided that (i) the individual does not actually or
constructively own 10% or more of the total combined voting power of all classes
of our stock entitled to vote and, (ii) the interest accrued on the exchange
note was not effectively connected with the conduct of a United States trade or
business.

BACKUP WITHHOLDING AND INFORMATION REPORTING

In general, payments of interest and the proceeds of the sale, exchange,
redemption, retirement or other disposition of the exchange notes payable by a
United States paying agent or other United States intermediary will be subject
to information reporting. In addition, backup withholding will generally apply
to these payments if (i) in the case of a United States Holder, the holder fails
to provide an

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accurate taxpayer identification number, or fails to certify that such holder is
not subject to backup withholding or fails to report all interest and dividends
required to be shown on its United States federal income tax returns, or
(ii) in the case of a Non-United States Holder, the holder fails to provide the
certification on IRS Form W-8BEN described above or otherwise does not provide
evidence of exempt status. Certain United Status Holders (including, among
others, corporations) and Non-United States Holders that comply with certain
certification requirements are not subject to backup withholding. Any amount
paid as backup withholding will be creditable against the holder's United States
federal income tax liability provided that the required information is timely
furnished to the IRS. Holders of exchange notes should consult their tax
advisors as to their qualification for exemption from backup withholding and the
procedure for obtaining such an exemption.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives exchange notes for its own account in the
exchange offer must acknowledge that it will deliver a prospectus in connection
with any resale of the exchange notes. This prospectus, as it may be amended or
supplemented from time to time, may be used by a broker-dealer in connection
with resales of exchange notes received in exchange for original notes where the
original notes were acquired as a result of market-making activities or other
trading activities. We have agreed that, for a period of at least 120 days after
the expiration date of the exchange offer, we will make this prospectus
available to any broker-dealer for use in connection with any resale.

We will not receive any proceeds from any sale of exchange notes by
broker-dealers. Exchange notes received by broker-dealers for their own account
in the exchange offer may be sold from time to time in one or more transactions
in the over-the-counter market, in negotiated transactions, through the writing
of options on the exchange notes or a combination of these methods of resale.
These resales may be made at market prices prevailing at the time of resale, at
prices related to these prevailing market prices or negotiated prices. Any
resale may be made directly to purchasers or to or through brokers or dealers
who may receive compensation in the form of commissions or concessions from any
broker-dealer or the purchasers of any of the exchange notes. Any broker-dealer
that resells exchange notes that were received by it for its own account in the
exchange offer and any broker or dealer that participates in a distribution of
the exchange notes may be deemed to be an underwriter within the meaning of the
Securities Act, and any profit on the resale of exchange notes and any
commission or concessions received by those persons may be deemed to be
underwriting compensation under the Securities Act. Any broker-dealer that
resells notes that were received by it for its own account in the exchange offer
and any broker-dealer that participates in a distribution of those notes may be
deemed to be an underwriter within the meaning of the Securities Act and must
comply with the registration and prospectus delivery requirements of the
Securities Act in connection with any resale transaction, including the delivery
of a prospectus that contains information with respect to any selling holder
required by the Securities Act in connection with any resale of the exchange
notes. The letter of transmittal states that, by acknowledging that it will
deliver and by delivering a prospectus, a broker-dealer will not be deemed to
admit that it is an underwriter within the meaning of the Securities Act.

Furthermore, any broker-dealer that acquired any of its original notes
directly from us:

- may not rely on the applicable interpretation of the staff of the SEC's
position contained in Exxon Capital Holdings Corp., SEC no-action letter
(April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter
(June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2,
1983); and

- must also be named as a selling noteholder in connection with the
registration and prospectus delivery requirements of the Securities Act
relating to any resale transaction.

For a period of at least 120 days after the expiration date of the exchange
offer, we will promptly send additional copies of this prospectus and any
amendment or supplement to this prospectus to any broker-dealer that requests
these documents in the letter of transmittal. We agree to pay all expenses
incident to the exchange offer, including the expenses of one counsel for the
holders of the notes, other than commissions or concessions of any brokers or
dealers. We will indemnify the holders of the notes, including any
broker-dealers, against various liabilities, including liabilities under the
Securities Act.

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LEGAL MATTERS

The legality of the exchange notes will be passed upon for Edison Mission
Energy by Skadden, Arps, Slate, Meagher & Flom LLP.

EXPERTS

The consolidated financial statements and schedules of Edison Mission Energy
and subsidiaries included in Edison Mission Energy's Annual Report on Form 10-K
for the year ended December 31, 2000, which is incorporated by reference in this
prospectus and elsewhere in the registration statement, have been audited by
Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in giving said report.

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We have not authorized any dealer, salesperson or other person to give any
information or represent anything not contained in this prospectus. You must not
rely on unauthorized information. This prospectus does not offer to sell or buy
any notes in any jurisdiction where it is unlawful. The information in this
prospectus is current as of October 2, 2001. However, you should realize that
our affairs may have changed since the date of this prospectus.

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