EDISON MISSION ENERGY - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 1997

Commission File Number 1-13434

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

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

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

Registrant's telephone number, including area code: (714) 752-5588

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

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

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
--- ---

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K _____.

Aggregate market value of the registrant's Common Stock held by non-affiliates
of the registrant as of March 27, 1998: $0. Number of shares outstanding of the
registrant's Common Stock as of March 27, 1998: 100 shares (all shares held by
an affiliate of the registrant).

TABLE OF CONTENTS

Item Page
- ---- ----

PART I

1. Business................................................................. 1

2. Properties............................................................... 22

3. Legal Proceedings........................................................ 23

4. Submission of Matters to a Vote of Security Holders...................... 23

PART II

5. Market for Registrant's Common Equity and Related Shareholder Matters.... 24

6. Selected Financial Data.................................................. 25

7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................... 26

8. Financial Statements and Supplementary Data.............................. 36

9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 36

PART III

10. Directors and Executive Officers of the Registrant....................... 69

11. Executive Compensation................................................... 71

12. Security Ownership of Certain Beneficial Owners and Management........... 78

13. Certain Relationships and Related Transactions........................... 80

PART IV

14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......... 80

Signatures............................................................... 99

PART I

ITEM 1. BUSINESS

THE COMPANY
- -----------

Edison Mission Energy (EME), through its subsidiaries, is engaged in the
business of developing, acquiring, owning and operating electric power
generation facilities worldwide. EME is a wholly owned subsidiary of The Mission
Group, which is a wholly owned, non-utility subsidiary of Edison International.
Edison International is also the parent holding company of Southern California
Edison Company (SCE), one of the largest electric utilities in the United
States.

EME was formed in 1986 with two domestic operating projects. Currently, EME
owns interests in 26 domestic and 24 international operating electrical power
generation facilities with an aggregate generating capacity of 7,403 megawatts
(MW), of which EME's share is approximately 5,173 MW. Three international
projects totaling 1,922 MW of generating capacity (of which EME's anticipated
share is approximately 887 MW) are currently in the construction stage. At
December 31, 1997, the Company had consolidated assets of $5 billion and total
shareholder's equity of $827 million.

EME is incorporated under the laws of the State of California. Its
headquarters and principal executive offices are located at 18101 Von Karman
Avenue, Suite 1700, Irvine, California 92612, and its telephone number is (714)
752-5588. Unless indicated otherwise or the context otherwise requires,
references in this Annual Report on Form 10-K to EME shall be deemed to include
EME, its subsidiaries and the partnerships or limited liability entities through
which EME and its partners own and manage their project investments.

SEGMENT INFORMATION
- -------------------

EME operates in only one industry segment: electric power generation.

DESCRIPTION OF BUSINESS
- -----------------------

GENERAL OVERVIEW

EME is one of the leading global producers of electricity. Through its
subsidiaries, EME is engaged in the business of developing, acquiring, owning
and operating electric power generation facilities worldwide. EME was formed in
1986 with two domestic operating projects. Currently, EME owns interests in 26
domestic and 24 international operating electrical power generation facilities.

Until the enactment of the Public Utility Regulatory Policies Act of 1978
(PURPA), utilities were the only producers of bulk electric power intended for
sale to third parties in the United States. PURPA 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 or QFs) under certain conditions. The passage of the
Energy Policy Act of 1992 (the Energy Policy Act) further encouraged the
development of independent power by significantly expanding the options
available to independent power producers (IPPs) with respect to their regulatory
status and by liberalizing transmission access. As a result, a significant
market for electric power produced by IPPs, such as EME, has developed in the
United States since the enactment of PURPA.

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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 IPPs
outside the United States. EME believes that it is well-positioned to continue
to realize opportunities in these new foreign markets. See "--Strategy" below.

STRATEGY

EME's business strategy is to play an active role, as a long-term owner, in
all phases of power generation, from planning and development through
construction and commercial operation. EME believes that such involvement
allows EME to better ensure, through the use of its experienced personnel, that
its projects are well-planned, structured and managed.

In making investment decisions, EME evaluates potential project returns
against rate of return guidelines. EME establishes 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. EME endeavors to mitigate project development risk by (i)
selecting partners with complementary skills and local experience, (ii)
structuring investments through subsidiaries, (iii) managing up-front
development costs, (iv) utilizing limited recourse financing and (v) linking
revenue and expense components where appropriate. Many of EME's projects are
operated by its subsidiaries or affiliates (e.g., Edison Mission Operation and
Maintenance, Inc. - Edison Mission O&M), which seek to preserve and enhance the
value of EME's investments.

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

Set forth below is a brief discussion of the current strategy for each of the
three regions and a summary of certain of EME's projects that are currently in
the construction, advanced development, pre-finance or early operations stage in
each of the regions. While EME anticipates the successful completion of these
projects, no assurance can be given that any of these projects, or any other
projects currently in the construction stage, advanced development or pre-
finance stage, will be successfully completed or financed or that the expected
MW capacity (and EME's anticipated share thereof) will be achieved. See " --
Project Development -- Certain Considerations Associated with Project
Development, Finance and Operation".

Americas

The Americas division is comprised of the U.S./Canada and Central and Latin
America regions and is headquartered in Irvine, California. The strategy for the
U.S./Canada and Central and Latin America region is to (i) manage certain
operating independent power projects located throughout the United States, (ii)
pursue the acquisition of existing generating assets from utilities, industrial
companies and other IPPs and (iii) pursue the development of new power projects
throughout the region. EME has 26 operating projects in this region. For
further information regarding EME's 26 domestic operating

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projects, see "--EME's Operating Power Generation Facilities-- Description of
Domestic Operating Projects."

Asia Pacific

The Asia Pacific division is headquartered in Singapore with additional
offices located in Australia, Indonesia and the Philippines. Among the three
geographic divisions, the countries covered by the Asia Pacific division have
experienced the fastest electric demand growth, and are expected to continue
strong growth in the medium term. Most governments in the region have committed
to privatization of the electric power industry, and are looking to the private
sector to finance and develop a significant portion of new generating capacity.

The strategy for this region is to (i) pursue projects in countries where
there exist strong political commitment and the structural framework necessary
for private power, (ii) seek opportunities to employ indigenous fuels and (iii)
seek strategic, complimentary alliances with partners who bring value to the
project by providing fuel, equipment and construction services.

EME's activity in the Asia Pacific region commenced in December 1992 with the
acquisition of a 51% interest of the 1000-MW Loy Yang B Power Station (Loy Yang
B) from the State Government of Victoria (State), Australia's first electric
privatization effort. In May 1997, a subsidiary of EME acquired the State's 49%
interest in Loy Yang B. The first of two 500-MW units at Loy Yang B began
commercial operations in October 1993. Unit 2 commenced commercial operations in
October 1996. An EME affiliate provides operation and maintenance services for
both units.

In April 1995, EME and its partners, Mitsui & Co. Ltd., General Electric
Corporation and P.T. Batu Hitam Perkasa, an Indonesian limited liability
company, commenced construction of the $2.5 billion Paiton project, a 1,230-MW
coal-fired power plant in East Java, Indonesia. The project will consist of two
units, each of which is expected to have a capacity of 615 MW. Construction of
the plant continues on schedule, with commercial operation expected in the first
half of 1999. In January 1996, EME purchased an additional 7.5% interest in the
Paiton project from a subsidiary of General Electric Corporation, thereby
increasing its ownership interest to 40%.

Construction on the two-unit Paiton project is approximately 85% complete.
The tariff is higher in the early years and steps down over time, and the tariff
for the Paiton project includes infrastructure to be used in common by other
units at the Paiton complex. The plant's output is fully contracted with the
state-owned electricity company, PT Perusahaan Listrik Negara (PLN), for payment
in U.S. dollars. The projected rate of growth of the Indonesian economy and the
exchange rate of Indonesian Rupiah into U.S. dollars have deteriorated
significantly since the Paiton project was contracted, approved and financed
with substantial finance and insurance support from the Export-Import Bank of
the United States, The Export-Import Bank of Japan, the U.S. Overseas Private
Investment Corporation and the Ministry of International Trade and Industry of
Japan. The Paiton project's senior debt ratings have been reduced from
investment grade to speculative grade based on the rating agencies' perceived
increased risk that PLN might not be able to honor the electricity sales
contract with Paiton. A Presidential decree has deemed some power plants, but
not including the Paiton project, subject to review, postponement or
cancellation.

Kwinana is a $108 million 116-MW gas-fired cogeneration project located at
the British Petroleum Kwinana refinery near Perth, Australia. The project,
which is 100% owned by EME, began commercial operations in December 1996. The
project supplies electricity to Western Power (formerly the State

3

Electricity Commission of Western Australia) and electricity and steam to the
British Petroleum Kwinana refinery.

In December 1997, EME (40% ownership), along with its partners, Siam City
Cement (30% ownership) and Lanna Lignite (30% ownership), signed a twenty-five
year power purchase contract with the Electricity Generating Authority of
Thailand (EGAT) pursuant to which EGAT will purchase 734 MW of output from the
coal-fired power generation project at Kui Buri in Thailand. Financial closing
and commencement of construction are anticipated in late 1998 or early 1999 with
commercial operations expected to begin in 2001.

In September 1997, the San Pascual project, a consortium including EME (37.5%
ownership), Texaco Inc. (37.5% ownership) and Caltex (25% ownership), signed a
twenty-five year power purchase contract with the National Power Corporation
(NPC), Philippines' state-owned electric utility company, pursuant to which NPC
will purchase 304 MW of output from the San Pascual project. The low-sulfur
residual fuel oil cogeneration project is located in the Philippines. Financial
closing and commencement of construction are anticipated in 1998 with commercial
operations expected to begin in 2001.

Europe, Central Asia, Middle East and Africa

The European organization is headquartered in London, England with additional
offices located in Italy, Spain and Turkey. The London office was established
in 1989, concurrent with the privatization of the power industry in the United
Kingdom. The territorial scope of the region includes Europe, Africa, the Middle
East, India and Pakistan. The region is characterized by a blend of both mature
and less developed markets. The regional strategy is to pursue the development
and acquisition of medium to large scale power and cogeneration facilities with
diversified fuel sources and generation technology.

EME's operating projects in the region are the First Hydro project located in
North Wales, the Roosecote project in northwest England, the Derwent project
located in Derby, England and the Iberian Hy-Power projects (which consist of 18
small, hydroelectric facilities) in Spain.

EME acquired initial ownership interests of Iberian Hy-Power I and II in
December 1992 and August 1993, respectively. In January 1996, EME purchased the
remaining equity stake in Iberian Hy-Power Amsterdam B.V., increasing its
ownership percentage to approximately 100% (minority interests are owned in
three of the projects by third parties).

In December 1995, EME purchased all of the outstanding shares of First Hydro
Company (First Hydro) for approximately $1 billion (653 million pounds
sterling). First Hydro's principal assets are two pumped-storage electric power
stations located in North Wales at Dinorwig and Ffestiniog, which have a
combined capacity of 2,088 MW. The Dinorwig station, which was commissioned in
1983, is comprised of six units totaling 1,728 MW. The Ffestiniog station was
commissioned in 1963 and is comprised of four units totaling 360 MW. First
Hydro is an independent generating company with three main sources of revenues:
(i) selling power into the electricity trading market or "pool" in England and
Wales, (ii) providing system support services to The National Grid Company plc,
and (iii) selling its installed capacity forward by entering into "contracts for
differences" with large electricity suppliers.

In June 1995, EME (49% ownership) and its partner, ISAB S.p.A. (51%
ownership), signed a twenty-year power purchase contract with ENEL S.p.A.,
Italy's state electricity corporation, pursuant to which ENEL S.p.A. will
purchase 507 MW of output from the 512-MW ISAB power project, which is located
near Siracusa in Sicily, Italy. The project will employ gasification technology
to convert heavy

4

oil residues from the ISAB refinery in Priolo Gargallo into clean-burning syngas
that will be used to generate electricity in a combustion turbine. The
approximately 2 trillion lira ($1.3 billion) project financial closing was
completed in April 1996 with construction commencing in July 1996. The project
is more than 75% complete with commercial operation expected in late 1999.

In February 1995, EME (80% ownership) signed a shareholders' agreement to
develop the $180 million Doga Enerji A.S. project in Esenyurt, near Istanbul,
Turkey. The 180-MW combined cycle gas-fired cogeneration facility is
approximately 63% complete with commercial operations expected in 1999. In
April 1997, EME completed financing and commenced construction of the Doga
project.

PROJECT DEVELOPMENT

The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, evaluating market
risk, designing and engineering the project, acquiring necessary land rights,
permits and fuel resources, obtaining financing and managing construction and,
in some cases obtaining power sales agreements and steam sales agreements.

EME initially evaluates and selects potential development projects based on a
variety of factors, including whether a project is based on a proven technology,
the strength of the potential partners in the project, the feasibility of the
project, the likelihood of obtaining a power sales agreement, the probability of
obtaining required licenses and permits and the projected economic return from
the project. During the development process, EME monitors the viability of the
project and makes 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.

Although EME has in the past been successful in developing projects with
long-term contracts and arranging for necessary permits and approvals, there can
be no assurance that EME will continue to be successful in doing so in the
future. EME believes that future market conditions for independent power,
particularly in the United States, may become increasingly characterized by
shorter-term power sales agreements or spot sales arrangements. EME may be
required to consider market or "merchant" risk in the future.

Project Type

The selection of power generation technology for a particular project is
influenced by various factors, including regulatory requirements, availability
of fuel and anticipated economic advantages for a particular application. The
principal technology used in EME's operating projects has been gas-fired
combustion turbine technology, predominately through an application known as
"cogeneration". Cogeneration facilities sequentially produce two or more useful
forms of energy (e.g., electricity and steam) from a single primary source of
fuel (e.g., natural gas or coal). Many of EME's 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 PURPA have become less significant because of
expanded project options made available to IPPs under the Energy Policy Act.
Accordingly, although cogeneration may provide a competitive advantage in the
new market place, EME expects that the majority of its future projects will
generate power without selling steam to industrial users.

5

EME also has interests in projects that use renewable resources such as
hydroelectric and geothermal energy. EME's hydroelectric projects, excluding
First Hydro, use "run-of-the-river" technology to generate electricity. The
First Hydro project utilizes pumped-storage stations which consume electricity
when it is comparatively less expensive in order to pump water up 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.
EME's geothermal projects use technologies that convert the heat from geothermal
fluids and underground steam into electricity.

EME has international interests in an operating project and projects under
construction and advanced development which are large scale, coal-fired projects
using pulverized coal in coal-fired generation technology. In the United
States, EME has developed coal and waste coal-fired projects that employ
traditional stoker and circulating fluidized bed technology.

Power and Steam Sales Contracts

Electric power and steam generated by EME's operating projects in the U.S. is
sold primarily to domestic electric utilities and industrial steam users
pursuant to long-term (typically, 15 to 30 year) contracts. Excluding the U.K.
and a project in Australia, electric power generated overseas is sold primarily
under long-term contracts to electric utilities located in the country where the
power is generated. A project's revenue from a power sales contract usually
consists of two components: energy payments and capacity payments. Energy
payments are generally based on actual deliveries of electric energy (e.g.,
kilowatt-hours) to the purchasing utility. Energy payment rates are usually
indexed to certain variable costs that the purchasing utility avoids by
purchasing such electric energy directly as opposed to operating its own power
plant(s) to produce the same amount of electric energy. The variable components
typically include the fuel cost and certain operation and maintenance expenses.
These costs may be indexed to the utility's cost of fuel and/or certain
inflation indices. Energy payments may also be time-differentiated to provide
relatively higher payments for electric energy delivered during periods of peak
electricity demand. Capacity payments are generally based on a project's proven
capability to deliver reliable electric energy, whether or not the plant is
called on to operate. Capacity payment rates are usually associated with certain
fixed costs that the purchasing utility avoids by having the independent power
producer build and maintain the availability of a power plant. 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.

EME's power sales contracts are typically negotiated during the planning
stage of a project. In negotiating the power sales contracts, EME attempts to
secure long-term contracts that are expected to result in consistent cash flow
under a wide range of economic and operating circumstances. To accomplish this,
EME structures the revenue provisions of the power sales contract so that
changes in the cost components of a facility (e.g., fuel costs) will correspond
to, as effectively as possible, similar changes in the revenue components of the
contract.

In addition to entering into a power sales agreement, EME must make
arrangements to interconnect its project to a local utility's electric system.
The arrangement is typically evidenced through an interconnection agreement that
sets forth the provisions for construction, payment and technical requirements
for the interconnection facilities. In some cases, the project will interconnect
with a utility system that is not the ultimate purchaser of electric power. In
such circumstances, the project must arrange for the local utility to transmit
or "wheel" its power to the ultimate purchaser.

6

Projects in the U.K. and a project in Australia sell their electrical energy
and capacity through a centralized electricity pool, which establishes a half-
hourly clearing price (also referred to as the "pool price"). The pool price is
extremely volatile and in the U.K. can vary by as much as a factor of ten or
more over the course of a few hours, due to the large differentials in demand
according to the time of day. First Hydro mitigates a significant portion of the
market risk of the pool by entering into contracts for differences (electricity
rate swap agreements), related to either the selling or purchasing price of
power, whereby a contract specifies a price at which the electricity will be
traded, and the parties to the agreement make payments, calculated based on the
difference between the price in the contract and the pool price for the element
of power under contract. These contracts can be sold in two structures: one-way
contracts, where a specified monthly amount is received in advance and
difference payments are made when the pool price is above the price specified in
the contract, and two-way contracts, where the counterparty pays First Hydro
when the pool price is below that in the contract instead of a specified monthly
amount. These contracts act as a means of stabilizing production revenues or
purchasing costs by removing an element of First Hydro's net exposure to pool
price volatility. The Roosecote project has avoided the pool price volatility by
entering into a long-term power sales contract that provides for contract
pricing. The Roosecote project's power sales contract provides for the
escalation of capacity payments according to an inflation index for the U.K.

Loy Yang B has entered into a number of financial hedges to mitigate exposure
to price volatility of the electricity traded into the pool. From May 8, 1997
to December 31, 2000, approximately 53% to 64% of the plant output sold is
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, 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, and the parties to the agreement make payments,
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. These
contracts can be sold as one-way or two-way contracts which are structured
similar to the electricity rate swap agreements described above. These
contracts are accounted for as electricity rate swap agreements. The State
Hedge is a long-term contractual arrangement based upon a fixed price commencing
May 8, 1997 and terminating October 31, 2016. The State guarantees SECV's
obligations under the State Hedge.

Steam produced from EME's 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. Domestic steam sales contracts require the purchaser to take
at least the minimum amount of steam necessary for the project to retain its QF
status under PURPA.

Steam payments are generally based on formulas that reflect the cost of
water, fuel and capital. In some cases, EME has provided steam purchasers with
discounts from their previous cost for producing such steam and/or partially
indexed steam payments to other indices including certain oil prices.

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Fuel Supply Contracts

EME seeks to enter into long-term fuel supply and transportation agreements.
Market prices for oil, gas and coal historically have fluctuated significantly.
EME believes, however, that its financial condition will not be substantially
adversely affected by such fluctuations because its 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 such 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.

Project Financing

Each power generation project developed by EME requires a substantial capital
investment. The permanent project financing for a project is often arranged
immediately prior to the construction of the project. With limited exceptions,
such debt financing is for approximately 60 to 80% of each project's costs and
is expected to be structured, on a basis that is nonrecourse to EME and its
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.

In general, each of EME's direct or indirect subsidiaries is organized as a
legal entity separate and apart from EME and its other subsidiaries. Any asset
of any such subsidiary may not be available to satisfy the obligations of EME or
any of its other such subsidiaries; provided, however, that unrestricted cash or
other assets which are available for distribution may, subject to applicable law
and the terms of financing arrangements of such parties, be advanced, loaned,
paid as dividends or otherwise distributed or contributed to EME or its
affiliates.

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

To obtain project financing, EME and its partners are sometimes required to
provide certain guarantees and warranties to lenders, particularly with respect
to construction financing. However, because permanent financing is usually
arranged on a nonrecourse basis, EME's liability is generally substantially
reduced when construction has been completed and the project has passed all
acceptance tests. EME's financial exposure in any project is generally limited
by contractual arrangement to its equity commitment, which is usually about 20
to 40% of EME's share of the aggregate project cost. In addition, the project
loan agreements are generally structured so that a default under one project
loan agreement will have no effect on the loan agreements of other EME projects.

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), EME seeks to obtain all permits, licenses and other approvals
required for the construction and operation of the project, including siting,
construction and environmental permits, rights-of-way and planning approvals,
early in the development process. See "Certain Regulatory Matters-- General".

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Construction and Implementation

In the project implementation stage, EME provides project and construction
management and start-up and testing services. The detailed engineering and
construction of the projects typically are done by outside contractors under
fixed-price, "turnkey" contracts. Under such contracts, the contractor
generally is required to pay liquidated damages to EME in the event of cost
overruns or schedule delays or if the facility fails to meet certain capacity,
efficiency and emission standards.

As a project goes into operation, operation and maintenance services are
provided to the project by one of EME's operation and maintenance subsidiaries
or another operation and maintenance contractor. The day-to-day operation of
each project is generally managed by an executive director. Management
committees comprised of the project partners generally meet monthly or quarterly
to review and manage the operating performance of each project.

Certain Considerations Associated with Project Development, Finance and
Operation

Independent power projects are necessarily subject to a variety of
commercial, financial and other risks, including those described below. By
managing, or participating in the management of each project in which it
invests, EME seeks to hedge, insure against or otherwise manage these risks.

EME attempts to minimize the financial risk in the development of a project
by securing a favorable long-term power sales agreement, obtaining all required
governmental permits and approvals and arranging adequate financing prior to the
commencement of construction. However, the development of a power project may
require EME to expend significant sums for preliminary engineering, permitting
and legal and other expenses before it can determine whether a project is
feasible, economically attractive or financeable. Power sales agreements often
enable the utility to terminate such agreement, or to retain security posted by
the developer as liquidated damages, in the event that a project fails to
achieve commercial operation or certain operating levels by specified dates or
fails to meet other significant contractual requirements. Furthermore, utility
regulators or other parties may attempt to abrogate or amend contracts under
which a project is entitled to receive material revenues or other benefits. If
such events were to occur, the default provisions in a financing agreement could
be triggered (rendering such project debt immediately due and payable) and, as a
result, EME could lose its interest in the project. Although contractual and
regulatory risks cannot be eliminated, EME believes that it has relevant
experience in developing contracts and mitigating regulatory concerns.

Certain geographic areas in which EME operates and is developing projects are
subject to frequent earthquakes of low intensity, and earthquakes of greater
intensity are possible. EME's existing power generation facilities are built to
withstand earthquakes of relatively significant intensity and EME believes it
maintains adequate insurance protection for such occurrences and other
catastrophic events.

The operation of a project involves many risks, including start-up problems,
the breakdown or failure of equipment or processes, performance below expected
levels of output and the inability to meet expected efficiency standards. EME
takes steps to mitigate these risks by obtaining equipment and plant warranties
and arranging for insurance that it believes is adequate. Nonetheless, these
measures 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 such
a financing obligation could result in EME losing its interest in such power
generation facility.

9

EME believes, however, that it will continue to maintain a successful record of
plant performance and operation.

EME's operations are conducted through its subsidiaries and EME's cash flow
is dependent upon the operating revenues of its subsidiaries and the ability of
those subsidiaries to pay cash dividends or make distributions to EME. Financing
agreements for EME's subsidiaries and affiliates generally place certain
limitations on the ability of those subsidiaries and affiliates to pay
dividends, make distributions or otherwise transfer funds to EME. In addition,
financing agreements for EME's subsidiaries and affiliates, although generally
nonrecourse to EME, contain certain representations, warranties, covenants and
other agreements that, if not met, could lead to a default under such financing.
After a default under a project financing for any reason, project lenders may
exercise certain rights and remedies typically granted to secured parties,
including the ability to take control of the project's collateral assets.

The financing and development of international projects entail additional
political and financial risks including uncertainties associated with
privatization efforts, currency exchange rates, currency repatriation, political
instability and other issues that have the potential to cause delays or
impairment of value to the project being developed for which EME may not be
fully capable of insuring against. The uncertainty of the legal structure in
certain foreign countries in which EME may develop or acquire projects could
make it more difficult to enforce its rights under agreements relating to such
projects. In addition, the laws and regulations of certain countries may limit
the ability of EME to hold a majority interest in some of the projects that it
may develop or acquire. Although the risks of participation in international
markets are significant, EME targets relatively higher rates of return on its
international investments and mitigates risk by seeking complimentary alliances
with well-established partners and hedging foreign exchange exposure where it
deems appropriate.

OPERATION AND MAINTENANCE SERVICES

Certain EME subsidiaries provide specialized operating, maintenance, testing
and start-up services for EME-owned projects. At December 31, 1997, Edison
Mission O&M or other subsidiaries had a total of 877 employees and operated 37
of EME's projects totaling 5,161 MW of capacity.

The projects that EME operates have achieved an average 97% availability
during 1997. 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.

EME'S OPERATING POWER GENERATION FACILITIES

Domestic Overview

EME currently owns interests in 26 domestic operating projects in eight
states. These operating projects consist of 16 natural gas cogeneration
projects, one coal cogeneration project, one waste coal project, four geothermal
projects and four gas-fired EWG (as defined herein) projects. All of EME's
domestic cogeneration and geothermal projects, as well as the waste coal
project, are qualifying facilities under PURPA. EME's domestic operating
projects have total generating capacity of 3,679 MW, of which EME's net
ownership share is 1,640 MW.

Each of EME's projects generally relies on one power sales contract with a
single electric utility customer for the majority, and in some cases all, of its
power sales revenues over the life of the power sales contract. The primary
power sales contracts for seven of EME's operating projects are with SCE.

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EME's share of revenues from these projects accounted for 12% of EME's
consolidated revenues in 1997 and 1996. The failure of SCE to fulfill its
contractual obligations could have a negative impact on a source of EME's
revenues. Under the terms of an agreement between SCE and the Office of
Ratepayer Advocates (ORA), the consumer advocacy branch of the California Public
Utility Commission (CPUC), SCE is prohibited from entering into future power
sales contracts with EME or its affiliates without ORA and CPUC consent. The
terms of the agreement, however, do not affect the terms of the existing power
sales contracts between EME and SCE. Fuel supply for EME's projects generally is
arranged through third-party suppliers and transporters.

EME's geothermal projects have power sales agreements that provide for energy
payments that escalate at predetermined rates during the first 10 years of plant
operation. After the initial 10-year period, the energy payments will be based
on rates published monthly by the purchasing utility that reflect its cost for
natural gas and/or oil. Based on current forecasts of natural gas and oil
prices, EME expects the energy payment rate to drop substantially after the
initial 10-year period. Accordingly, cash distributions received from these
projects are recorded as reductions in the equity investments. Future cash
distributions are estimated to be sufficient to recover the remaining geothermal
investment balances. In April 1996, CalEnergy Company, Inc., EME's partner in
four operating geothermal projects in California, purchased all of the stock of
four wholly owned subsidiaries of EME, which held 50% interests in these
projects. The purchase price of $70 million resulted in a pre-tax gain of $20
million. There will be no impact on EME's future revenues as EME discontinued
recognizing earnings from these projects during 1993.

In January 1998, Oxbow Power of Beowawe, Inc., EME's partner in an operating
geothermal project in Nevada, purchased EME's 50% general partnership interest
in this project from a wholly owned subsidiary of EME. The purchase price of
$4.1 million resulted in an after tax gain of $1.1 million. There will be no
impact on EME's future revenues as EME discontinued recognizing earnings from
this project in 1996.

In February 1998, the CPUC issued an order which approved an agreement
entered into in August 1997 between an operating geothermal project in
California in which EME has a 50% partnership interest and SCE to terminate two
power sales agreements. There will be no negative impact on EME's future
revenues as EME discontinued recognizing earnings from this project during 1993.

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Description of Domestic Operating Projects

EME has ownership interests in the following domestic operating projects:

ELECTRIC PRIMARY OPERATION/
CAPACITY ELECTRIC TYPE OF OWNERSHIP ACQUISITION
PROJECT LOCATION (IN MW) PURCHASER(3) FACILITY(4) INTEREST DATE
- ------- -------- ------- ------------ ----------- -------- -----------

Aidlin(1) Cloverdale, California 20 PG&E Geothermal 5% 1990
American Bituminous(2) Grant Town, West Virginia 80 MPC Waste Coal 50% 1993
Auburndale(2) Polk County, Florida 150 FPC EWG 50% 1994
Bayonne Bayonne, New Jersey 165 JCP&L/PSE&G Cogeneration 0.38% 1989
Brooklyn Navy Yard Brooklyn, New York 286 CE Cogeneration 50% 1996
Coalinga(2) Coalinga, California 38 PG&E Cogeneration 50% 1991
Commonwealth Atlantic Chesapeake, Virginia 340 VEPCO EWG 50% 1992
GEO East Mesa(1,2) Holtville, California 40 SCE Geothermal 50% 1989
Gordonsville(2) Gordonsville, Virginia 240 VEPCO EWG 50% 1994
Harbor(2) Wilmington, California 80 SCE Cogeneration 30% 1989
Hopewell Hopewell, Virginia 356 VEPCO Cogeneration 25% 1990
James River Hopewell, Virginia 110 VEPCO Cogeneration 50% 1987
Kern River(2) Oildale, California 300 SCE Cogeneration 50% 1985
Lost Hills Lost Hills, California 10 PG&E Cogeneration 50.09% 1989
March Point 1 Anacortes, Washington 80 PSE Cogeneration 50% 1991
March Point 2 Anacortes, Washington 60 PSE Cogeneration 50% 1993
Mid-Set(2) Fellows, California 38 PG&E Cogeneration 50% 1989
Midway-Sunset(2) Fellows, California 225 SCE Cogeneration 50% 1989
Nevada Sun-Peak Las Vegas, Nevada 210 NVP EWG 50% 1991
Saguaro(2) Henderson, Nevada 90 NVP Cogeneration 50% 1991
Salinas River(2) San Ardo, California 38 PG&E Cogeneration 50% 1991
Sargent Canyon(2) San Ardo, California 38 PG&E Cogeneration 50% 1991
Sycamore(2) Oildale, California 300 SCE Cogeneration 50% 1988
Watson Carson, California 385 SCE Cogeneration 49% 1988

(1) Consists of two projects on the same site.
(2) Operated by EME.
(3) Electric purchaser abbreviations are as follows:

CE Consolidated Edison Company of New York, Inc. PG&E Pacific Gas & Electric Company
FPC Florida Power Corporation PSE Puget Sound Energy
JCP&L Jersey Central Power & Light Company PSE&G Public Service Electric & Gas Company
MPC Monongahela Power Company SCE Southern California Edison Company
NVP Nevada Power Company VEPCO Virginia Electric & Power Company

(4) All of the cogeneration projects are gas-fired facilities, except for the
James River project, which uses coal.

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International Overview

EME owns interests in 24 operating projects outside the United States. The
total generating capacity of such facilities is 3,724 MW, of which EME's net
ownership share is 3,533 MW.

Description of International Operating Projects

EME has ownership interests in the following international operating projects:

ELECTRIC OPERATION/
CAPACITY PRIMARY ELECTRIC OWNERSHIP ACQUISITION
PROJECT LOCATION (IN MW) PURCHASER(2) INTEREST DATE
- ------- -------- ------- ------------ --------- ----------

Alos(1) Spain 5 FECSA 100% 1993
Bocos(1) Spain 2 FECSA 100% 1993
Castellas(1) Spain 2 FECSA 100% 1993
Derwent(1) England 214 SE(3) 33% 1995
Dinorwig(1) Wales 1,728 Pool 100% 1995
Ffestiniog(1) Wales 360 Pool 100% 1995
Gelsa(1) Spain 7 FECSA 100% 1993
Kwinana(1) Australia 116 WP 100% 1996
La Flecha(1) Spain 3 FECSA 100% 1993
La Ribera(1) Spain 4 FECSA 100% 1993
Logrono(1) Spain 4 FECSA 100% 1993
Loy Yang B(1) Australia 1,000 Pool(4) 100% 1993, 1996,
1997
Mendavia(1) Spain 6 FECSA 100% 1993
Menuza(1) Spain 17 FECSA 91.3% 1992
Monasterio(1) Spain 2 FECSA 100% 1993
Olvera(1) Spain 2 FECSA 100% 1992
Quintana(1) Spain 1 FECSA 100% 1993
Roosecote England 220 NORWEB(5) 80% 1992
Sardon Bajo(1) Spain 2 FECSA 100% 1993
Sastago I(1) Spain 3 FECSA 91.3% 1992
Sastago II(1) Spain 17 FECSA 91.3% 1992
Sossis(1) Spain 4 FECSA 100% 1992
Toro(1) Spain 4 FECSA 100% 1993
Tudela(1) Spain 1 FECSA 100% 1993

(1) Operated by EME.
(2) Electric purchaser abbreviations are as follows:

FECSA Fuerzas Electricas de Cataluma, S.A. Pool Electricity trading market for England,
NORWEB North Western Electricity Board Wales and Australia
WP Western Power SE Southern Electric plc.

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

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OIL AND GAS INVESTMENTS

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

Four Star

As of December 31, 1997, EME owned 46.85% of the stock of Four Star Oil & Gas
Company (Four Star), a subsidiary of Texaco Inc. The underlying value of Four
Star is attributable to production of oil and gas from nine producing
properties. EME's proportionate interest in net quantities of proved reserves
at December 31, 1997 totaled 189 billion cubic feet of natural gas and 21.6
million barrels of oil.

During 1995, EME and/or Four Star entered into a series of transactions which
resulted in a net increase in EME's ownership of Four Star by 2.47%. During
1996, EME purchased additional shares of stock of Four Star increasing its
ownership by 4.38%. In January 1998, EME purchased additional shares of stock
of Four Star for approximately $4 million increasing its ownership by 3.24% to
50.09% and its voting ownership to 48.97%.

B.C. Star

B.C. Star was formed in 1991 when a subsidiary of EME and a subsidiary of
Texaco Inc. each purchased a 50% partnership interest in certain proved
producing properties from Esso Resources Canada Limited. These properties are
geographically concentrated in the northeast region of British Columbia and
enjoy proximity and direct pipeline access to the Pacific Northwest and
California. Texaco Canada Petroleum Inc. operates the majority of B.C. Star's
properties.

During the second quarter of 1997, EME completed a sale of its ownership
interest in B.C. Star for approximately $71 million. EME recorded an after-tax
gain of approximately $14 million on the sale.

COMPETITION

EME competes with many other companies, including multinational development
groups, equipment suppliers and other IPPs (including affiliates of utilities),
in selling electric power and steam, and 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 such
contracts and decreases the chances of obtaining such contracts. As a result of
competition, it may be difficult to obtain a power sales agreement for a
proposed project, and the prices offered in new power sales agreements for both
electric capacity and energy may be less than the prices in prior agreements.
EME evaluates 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 (PUHCA) made by
the Energy Policy Act have increased the number of competitors in the domestic
independent power industry by

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reducing certain restrictions applicable to projects that are not QFs under
PURPA. "Retail wheeling" of power could also lead to increased competition in
the independent power market. See "Certain Regulatory Matters--Retail
Competition".

TAX SHARING AGREEMENTS

EME is included in the consolidated federal income tax and state franchise
tax returns of Edison International. EME calculates its current tax benefit
receivable on a separate company basis under a tax sharing agreement with The
Mission Group, which in turn has a tax sharing agreement with Edison
International. The Mission Group receives payment from Edison International for
tax benefits and pays Edison International for tax liabilities. The Mission
Group similarly pays EME for tax benefits and EME pays The Mission Group for tax
liabilities.

EMPLOYEES AND OFFICES

At February 27, 1998, EME employed 1,172 people, all of whom were full-time
employees and approximately 216, 26 and 144 of whom were covered by a collective
bargaining agreement in Wales, Spain and Australia, respectively. EME has never
experienced a work stoppage, strike or labor dispute. EME believes its relations
with its employees to be good.

EME leases its corporate headquarters in Irvine, California and its principal
regional offices in London, Melbourne and Singapore. It also leases other
smaller offices in the United States and certain foreign countries.

CERTAIN REGULATORY MATTERS
- --------------------------

GENERAL

EME's 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 its projects.
Federal laws and regulations govern, among other things, transactions by and
with utility companies, the operations of a project and the ownership of a
project. Under certain circumstances where exclusive federal jurisdiction is not
applicable or specific exemptions are otherwise unavailable, 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 such permits and approvals. While EME believes the requisite approvals for
its existing projects have been obtained and that its business is operated in
substantial compliance with applicable laws, EME remains subject to a varied and
complex body of laws and regulations that both public officials and private
parties may seek to enforce. There can be no assurance that future developments
will not have a material adverse effect on EME's business or results of
operations, nor can there be any assurance that EME will be able to obtain and
comply with all necessary licenses, permits and approvals for proposed projects.
In addition, 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

15

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.

Each of EME's international projects will be (or, to the extent that such
projects are already in operation or under construction, currently are) subject
to the energy and environmental laws and regulations of the foreign jurisdiction
in which it is located. The degree of regulation will vary according to each
country and may be materially different from the regulatory regime in the United
States.

U.S. FEDERAL ENERGY REGULATION

The enactment of PURPA in 1978 and the adoption of regulations thereunder by
the Federal Energy Regulatory Commission (FERC) provided incentives for the
development of cogeneration facilities and small power production facilities
(those utilizing alternative or renewable fuels). The passage of the Energy
Policy Act in 1992 further encouraged independent power production by providing
certain exemptions from PUHCA (but not from the Federal Power Act (FPA) or state
regulation) for exempt wholesale generators (EWGs) and foreign utility companies
(FUCOs).

A domestic electricity generating project must be a QF under FERC regulations
in order to take advantage of certain rate and regulatory incentives provided by
PURPA. Subject to certain exceptions, PURPA exempts owners of QFs from PUHCA,
exempts QFs from most provisions of the FPA and, except under certain limited
circumstances, state laws concerning rate or financial regulation. In order to
be a QF, a cogeneration facility must (i) sequentially produce both useful
thermal (e.g., steam) and electric energy, (ii) meet certain 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, an electric utility,
electric utility holding company or an affiliate thereof. A non-cogeneration
facility may also be a QF if it produces power from renewable energy (e.g.,
geothermal energy) or a waste source of fuel (e.g., waste coal). Before 1990,
non-cogeneration QFs were subject to 30-MW or 80-MW size limits, depending upon
their fuel source. In 1990, these limits were lifted for solar, wind, waste, and
geothermal QFs, provided that applications for or notices of QF status were
filed with FERC for such facilities on or before December 31, 1994, and
provided, in the case of new facilities, the construction of such facilities
commenced on or before December 31, 1999.

Amendments made to PUHCA by the Energy Policy Act provide that owners or
operators of EWGs and FUCOs will not be considered "electric utility companies"
under PUHCA. An EWG is an entity determined by the FERC to be exclusively
engaged, directly or indirectly, in the business of owning and/or operating
certain eligible facilities and selling electric energy at wholesale (or, if
located in a foreign country, at wholesale or retail). A FUCO 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 derives none of
its income, directly or indirectly, from such activities within the United
States.

The exemptions from federal and state regulation afforded to QFs, and the
exemptions from PUHCA afforded to EWGs and FUCOs, are important to EME and to
its competitors. Under present federal law, EME is not and will not be subject
to regulation as a holding company under PUHCA as long as the projects in which
it has an interest are QFs, EWGs or FUCOs (or are subject to another exemption
from regulation). Of the projects that EME currently owns, operates or has an
investment in, 22 projects have been certified as QFs by the FERC, four projects
have been certified as EWGs and 15 projects are FUCOs. Most of the U.S. projects
currently in the planning or development stage are expected to be QFs and the
international projects are expected to be FUCOs. To the extent that any of

16

EME's projects in the development stage will not be QFs or FUCOs, EME expects to
qualify those projects as EWGs. See "PUHCA".

PURPA

PURPA provides two primary benefits to QFs. First, QFs are relieved of
compliance with extensive federal and state regulations that control the
development, financial structure and operation of an energy-producing project
and the prices and terms on which wholesale energy may be sold by the project.
Second, FERC regulations promulgated under PURPA require that electric utilities
purchase electricity generated by QFs at a price based on the purchasing
utility's "avoided cost," and that the utilities sell back-up power to the QF on
a non-discriminatory basis. The term "avoided cost" is defined by PURPA 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, such utility would generate itself or purchase from another source."
FERC regulations also permit QFs and utilities to negotiate agreements for
utility purchases of power at prices lower than the utility's avoided costs.
While public utilities are not explicitly required by PURPA to enter into long-
term contracts, it has been common for long-term contracts to be negotiated 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. However, increasing competition and power brokering may result
in a trend toward shorter term power contracts that would place greater risk on
the project owner.

EME endeavors to develop its QF projects, monitor regulatory compliance by
such projects and choose its customers in a manner that minimizes the risks of
losing such projects' QF status. However, certain factors necessary to maintain
QF status are subject to the risk of events outside EME's 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
QF could cause the facility to fail requirements regarding the level of useful
thermal energy output. Upon the occurrence of such an event, EME would seek to
replace the thermal energy customer or find another use for the thermal energy
that meets PURPA's requirements, but no assurance can be given that this would
be possible.

If one of the projects in which EME has an interest was to lose its status as
a QF, the project would no longer be entitled to the QF-related exemptions from
regulation under PUHCA and the FPA. This could subject the project to rate
regulation as a public utility under the FPA and could result in EME
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. Loss of QF status may also trigger defaults under covenants
to maintain QF 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. Such loss of QF status may
be on a retroactive or a prospective basis. If a power purchaser ceased taking
and paying for electricity or sought to obtain refunds of past amounts paid due
to the loss of QF status, there can be no assurance that the costs incurred in
connection with the project could be recovered through sales to other
purchasers. Moreover, EME's business and financial condition could be adversely
affected if regulations or legislation were modified or enacted that changed the
standards for achieving QF status or that eliminated or reduced the benefits
currently enjoyed by QFs. If a project were to lose its QF status, EME could
attempt to avoid holding company status on a prospective basis by qualifying the
project as an EWG. However, assuming this changed status would be permissible
under the terms of the applicable power sales agreement, rate approval from the
FERC would be required. In addition, the project would be required to cease
selling electricity to any retail customers (in order to qualify for EWG status)
and could become subject to state regulation of sales of thermal energy. Loss of
QF status on a retroactive basis could lead to, among other things, fines

17

and penalties being levied against EME and its subsidiaries, or claims by the
utility customer for refund of payments previously made. Loss of QF status by
one project could also, because of PURPA ownership restrictions, adversely
affect the QF status of other projects having one or more of the same partners.
In addition, pursuant to Section 26(b) of PUHCA, any project contracts that are
entered into in violation of PUHCA are subject to possible voidability by the
courts should a lawsuit to void the contract be filed.

The Energy Policy Act

The passage of the Energy Policy Act in 1992 significantly expanded the
options available to IPPs with respect to their regulatory status. The Energy
Policy Act created a new class of power producer, the EWG, that (like a QF) is
not considered an electric utility company under PUHCA. EWGs may own facilities
of any size, use any fuel source and may be owned by utilities or non-utilities.
Thus, in addition to QF status, an IPP now can also apply to the FERC to be
granted status as an EWG. EWGs, however, are not exempt from regulation by the
FERC or state public utility commissions. The effect of such amendments is to
enhance the development of non-QFs that do not have to meet the fuel, production
and ownership requirements of PURPA. EME believes that the amendments benefit
EME by expanding its ability to own and operate facilities that do not qualify
for QF status, but may also result in increased competition because utilities
and other companies (e.g., equipment suppliers) may now develop facilities that
are not subject to the constraints of PUHCA. The Energy Policy Act also expanded
FERC authority to order utilities to grant transmission access to QFs and EWGs
and lifted restrictions on ownership of foreign utilities by U.S. companies.
Pursuant to the Energy Policy Act, FUCOs are also considered not to be electric
utility companies under PUHCA.

PUHCA

Under PUHCA, any corporation, partnership or other entity or organized group
that owns, controls or holds with power to vote 10% or more of the outstanding
voting securities of a "public-utility company" or a company that is a "holding
company" of a public utility company, is subject to registration with the
Securities and Exchange Commission (SEC) and regulation under PUHCA, unless
eligible for an exemption or unless an appropriate application is filed with,
and an order is granted by, the SEC declaring it not to be a holding company. A
registered public utility holding company regulated under PUHCA 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. Approval by the SEC is required for major financial commitments and
other business dealings of the regulated holding company or its subsidiaries.

As noted above, however, regulations have been adopted under PURPA and the
Energy Policy Act providing that QFs, EWGs and FUCOs are not public utility
companies. Accordingly, EME is not regulated as a "holding company" under PUHCA
because the power generation facilities owned by EME or in which EME has
investments are either QFs, EWGs or FUCOs. All international projects and
certain U.S. projects that EME is currently developing will be non-QF
independent power projects. EME intends for each such project to qualify as an
EWG or as a FUCO. Loss of EWG or FUCO status (like loss of QF status, as
discussed above) could also result in EME becoming subject to registration and
regulation as a public utility holding company under PUHCA and could trigger
defaults under covenants in project agreements. Loss of EWG or FUCO status on a
retroactive basis could lead to, among other things, fines and penalties and
could cause certain project contracts to be voidable.

18

Natural Gas Act

Twenty of the domestic operating facilities that EME owns, operates or has
investments in are fueled by natural gas. Pursuant to the Natural Gas Act, the
FERC has jurisdiction over the sale, transportation and storage of natural gas
in interstate commerce. With respect to most transactions that do not involve
the construction of pipeline facilities, regulatory authorization can be
obtained on a self-implementing basis. However, pipeline rates for such services
are subject to continuing FERC oversight. Order No. 636, issued by the FERC in
April 1992 (and affirmed in Orders 636A and 636B issued, respectively, in August
and November 1992), mandated the restructuring of interstate natural gas
pipeline sales and transportation services and changed the terms and conditions
under which interstate pipelines provide transportation services, as well as the
rates pipelines may charge for such services. The restructuring required by the
rule included (i) the separation (unbundling) of a pipeline's sales,
transportation and storage services, (ii) the implementation of a straight
fixed-variable rate design methodology under which all of a pipeline's fixed
costs are recovered through its reservation charge, (iii) the implementation of
a capacity releasing mechanism under which holders of firm transportation
capacity on pipelines can release that capacity for resale by the pipeline, and
(iv) the opportunity for pipelines to recover 100% of their prudently incurred
costs (transition costs) associated with implementing the restructuring mandated
by the rule.

FPA

The FPA grants the FERC exclusive ratemaking jurisdiction over wholesale
sales of electricity in interstate commerce, including ongoing as well as
initial rate jurisdiction, which enables the FERC to revoke or modify previously
approved rates. Such rates may be based on a cost-of-service approach or may, in
competitive markets, be market-based. While qualifying facilities under PURPA
generally are exempt from the ratemaking and certain other provisions of the
FPA, EWGs and other non-QF independent power projects are subject to the FPA and
to FERC ratemaking jurisdiction, which may limit their flexibility in
negotiations with power purchasers. However, since such projects would not be
bound by PURPA's thermal energy use requirement, they have greater latitude in
site selection and facility size.

Currently, only three of EME's operating projects, Nevada Sun-Peak, Brooklyn
Navy Yard and Commonwealth Atlantic, are subject to FERC rate-making regulation
under the FPA. EME's future domestic non-QF independent power projects will
also be subject to FERC jurisdiction on rates.

STATE ENERGY REGULATION

State public utility commissions (PUCs) have broad jurisdiction over non-QF
independent power projects (including EWGs), which are considered public
utilities in many states. Such jurisdiction often includes the issuance of
certificates of public convenience and necessity (CPCNs) to construct a facility
as well as regulation of organizational, accounting, financial and other
corporate matters on an ongoing basis. QFs may also be required to obtain CPCNs
in some states. Although the FERC generally has exclusive jurisdiction over the
rates charged by a non-QF independent power project to its wholesale customers,
PUCs have the ability, in practice, to influence the establishment of such rates
by asserting jurisdiction over the purchasing utility's ability to pass-through
the resulting cost of purchased power to its retail customers. PUCs also have
the authority to determine avoided cost for QFs. 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

19

these facilities. The actual scope of jurisdiction over independent power
projects by state PUCs varies from state to state.

In addition, state PUCs may seek to modify, suspend or terminate a QF's power
sales contract under certain circumstances. This could occur if the state PUC
determined 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 such instance, the state PUC may attempt to alter the
terms of the power sales contract to reflect more accurately market conditions
for the prevailing cost of power. While EME believes that such attempts are not
common and that the state PUCs may not have any jurisdiction to modify the terms
of the wholesale power sales, there can be no assurance that the power sales
contracts of its projects will not be subject to adverse regulatory actions.

The CPUC has authorized the electric utilities in California to "monitor"
compliance by QFs with PURPA rules and regulation. However, the United States
Court of Appeals for the Ninth Circuit found in 1994 that a CPUC program was
preempted by PURPA insofar as it authorized utilities to determine that a QF was
not in compliance with PURPA rules and regulations, to then pay a reduced
avoided cost rate and to take other action contrary to a facility's status as a
QF. The court did, however, uphold reasonable monitoring of QF operating data.
Other states, such as New York, have also instituted QF monitoring programs.

EME buys and transports the natural gas used at its domestic facilities
through local distribution companies (LDCs). State PUCs have jurisdiction over
the transportation of natural gas by LDCs. Each state's regulatory laws are
somewhat different; however, all generally require the LDC to obtain approval
from the PUC for the construction of facilities and transportation services if
the LDC's generally applicable tariffs do not cover the proposed transaction.
LDC rates are usually subject to continuing PUC oversight.

TRANSMISSION OF WHOLESALE POWER

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 (wheeling). The prices and other terms and
conditions of transmission contracts are regulated by FERC, when the entity
providing the wheeling service is a jurisdictional public utility under the FPA.
Until 1992, FERC'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.

FERC's authority under the FPA to require electric utilities to provide
transmission service on a case-by-case basis to QFs, EWGs, and other power
generators was expanded substantially by the Energy Policy Act. Furthermore, in
1996 FERC issued a rulemaking order, Order 888, in which FERC asserted the
power, under its authority to eliminate undue discrimination in transmission, to
compel all jurisdictional public utilities under the FPA to file open access
transmission tariffs consistent with a pro forma tariff drafted by FERC.
Although the pro forma tariff does not cover the pricing of transmission
service, Order 888 is expected to improve transmission access for independent
power producers such as EME.

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

20

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 (e.g., the delivery of electric power through its local
distribution lines) from its transmission and generation service (e.g., the
provision of electric power from the utility's generating facilities or
wholesale power purchases). A few state commissions and legislatures have
already issued orders or passed legislation requiring utilities to begin to
offer unbundled retail distribution service (retail wheeling) beginning as soon
as 1998. Other states are expected to move toward retail competition by 2000.

The competitive pricing environment that will result from retail competition
may cause utilities to experience revenue shortfalls and deteriorating
creditworthiness. However, EME expects 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 QFs and EWGs. On the other hand, QFs and EWGs may be
subject to pressure to lower their contract prices in an effort to reduce the
"stranded investment" costs of their utility customers.

EME believes that, as a predominately low cost producer of electricity, it
will ultimately benefit from any increased competition that may arise from the
opening of the retail market. Although EME's EWGs are forbidden under PUHCA
from selling electric power at retail, its QFs will be 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. EME also
believes it will be an attractive supplier to power marketers serving the newly-
open retail markets.

ENVIRONMENTAL REGULATION

The construction and operation of power projects are subject to environmental
regulation by federal, state and local authorities in the United States and
regulatory authorities with jurisdiction over the projects located outside the
United States. EME believes that it is in substantial compliance with
environmental regulatory requirements and that maintaining compliance with
current requirements will not materially affect its financial condition or
results of operations. EME conducted a review of some of its sites in 1995 and
does not believe that a material liability exists as of December 31, 1997.
However, possible future developments, such as more stringent environmental laws
and regulations, could affect the costs and the manner in which EME conducts its
business. There can be no assurance that in such event EME would be able to
recover such increased costs from its customers or that its 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 of 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.

In 1990, Congress passed amendments (the 1990 Amendments) to the Clean Air
Act that greatly expand the scope of federal regulations in several significant
respects. An EME project is anticipated to make capital expenditures of
approximately $11.6 million ($5.8 million is EME's share) from 1998 through 1999
in order to comply with the 1990 Amendments. Provisions related to
nonattainment, air toxins, permitting, enforcement and "acid rain" may affect
EME's projects; however, final details of all these programs have not been
issued by the United States Environmental Protection Agency and state agencies.

21

The Comprehensive Environmental Response, Compensation, and Liability Act
(Superfund) requires the cleanup of sites from which there has been a release or
threatened release of hazardous substances. At the present time, EME is not
aware of any Superfund liability; however, there can be no assurance that EME
will not incur such liability in the future.

FOREIGN AND DOMESTIC OPERATIONS
- -------------------------------

A summary of EME's operations by geographic area including operating
revenues, net income (loss) and identifiable assets is incorporated herein by
reference from note 15 (Geographic Areas--Financial Data) of Notes to the
Consolidated Financial Statements.

ITEM 2. PROPERTIES

EME leases its principal office in Irvine, California. This lease is
approximately 92,600 square feet contained on six floors. The term of the lease
for approximately 65,500 square feet expires on December 31, 2002 with two five-
year options to extend. The term of the lease for the balance of approximately
27,100 square feet expires on December 31, 2002 with no options to extend. EME
also leases office space in Fairfax, Virginia and Washington, D.C. which is not
material. Subsidiaries of EME also lease office space in Barcelona, Spain;
Esenyurt, Turkey; Jakarta, Indonesia; London, England; Manila, Philippines;
Melbourne, Australia; Rome, Italy; and Singapore, none of which are material.

The following table shows the material properties owned or leased by EME, its
subsidiaries, or partnerships. Each property represents at least five percent of
EME's income before tax or is one in which EME has an investment balance greater
than $50 million. All of these properties are subject to mortgages or other
liens or encumbrances granted to the lenders providing financing for the plant
or project.

22

DESCRIPTION OF PROPERTIES

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

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

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

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

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

Loy Yang B Victoria, Australia Owned Coal-fired power facility

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

Paiton East Java, Indonesia Leased Coal-fired power facility under construction

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

Sycamore Oildale, California Leased Natural gas-turbine cogeneration facility

Watson Carson, California Leased Natural gas-turbine cogeneration facility

ITEM 3. LEGAL PROCEEDINGS

PMNC Litigation -In February 1997, a civil action was commenced in the
---------------
Superior Court of the State of California, Orange County, entitled The Parsons
-----------
Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P., Mission
- -------------------------------------------------------------------------------
Energy New York, Inc. and B-41 Associates. L.P., Case No. 774980, in which
- -----------------------------------------------
plaintiffs assert general monetary claims under the Construction Turnkey
Agreement in the amount of $136,800,000. 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
$13,000,000 under the Construction Turnkey Agreement. EME believes that the
outcome of this litigation will not have a material adverse effect on its
consolidated financial position or results of operations.

EME experiences other routine litigation in the normal course of its
business. None of such pending litigation is expected to have a material adverse
effect on the consolidated financial position or results of operations of EME.
See "Certain Regulatory Matters--Environmental Regulation".

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

Inapplicable.

23

PART II

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

All of the outstanding Common Stock of EME is, as of the date hereof, owned
by The Mission Group, which is a wholly owned subsidiary of Edison
International. There is no market for the Common Stock.

Dividends of the Common Stock will be paid when declared by the Board of
Directors of EME. EME made cash dividend payments to The Mission Group of $197
million and $150 million in 1997 and 1996, respectively. In 1997, a noncash
dividend of $78 million was also made to The Mission Group. At present, EME has
no plans to pay a dividend on the Common Stock.

In November 1994, Mission Capital, L.P. (Mission Capital), a limited
partnership of which EME is the sole general partner, issued 3.5 million 9-7/8%
Cumulative Monthly Income Preferred Securities, Series A (the Preferred
Securities) and EME issued $90,206,186 of 9-7/8% junior subordinated deferrable
interest debentures due 2024 (the Debentures) pursuant to a subordinated
indenture dated as of November 30, 1994 (the Subordinated Indenture) between EME
and The First National Bank of Chicago, as trustee. During August 1995, Mission
Capital issued 2.5 million 8-1/2% Cumulative Monthly Income Preferred
Securities, Series B (the Preferred Securities) and EME issued $64,432,990 of 8-
1/2% junior subordinated deferrable interest debentures due 2025 pursuant to the
Subordinated Indenture. EME issued a guarantee (the Guarantee) in favor of the
holders of the Preferred Securities, which guarantees the payments of
distributions declared on the Preferred Securities, payments upon a liquidation
of Mission Capital and payments on redemption with respect to any Preferred
Securities called for redemption by Mission Capital. So long as any Preferred
Securities remain outstanding, EME will not be able to declare or pay, directly
or indirectly, any dividend on, or purchase, acquire or make a distribution or
liquidation payment with respect to, any of its Common Stock if at such time (i)
EME shall be in default with respect to its payment obligations under the
Guarantee, (ii) there shall have occurred any event of default under the
Subordinated Indenture, or (iii) EME shall have given notice of its selection of
an extended interest payment period as provided in the Indenture and such
period, or any extension thereof, shall be continuing.

24

ITEM 6. SELECTED FINANCIAL DATA

(IN MILLIONS) YEARS ENDED DECEMBER 31,
------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----

INCOME STATEMENT DATA
Operating revenues $ 975.0 $ 843.6 $ 467.3 $ 380.6 $ 290.5
Operating expenses 581.1 476.5 264.0 199.9 258.7(a)
-------- -------- -------- -------- ----------
Income from operations 393.9 367.1 203.3 180.7 31.8
Interest expense (223.5) (164.2) (93.1) (89.0) (33.5)
Interest and other income 53.9 40.7 33.1 38.8 4.7
Minority interest (38.8) (69.5) (48.3) (46.1) (11.4)
-------- -------- -------- -------- --------
Income (loss) before income taxes 185.5 174.1 95.0 84.4 (8.4)
Provision (credit) for income taxes 57.4 82.0 31.0 29.4 (4.2)
-------- -------- -------- -------- --------
Income (loss) before extraordinary loss and
cumulative effect of change in
accounting principle 128.1 92.1 64.0 55.0 (4.2)
Extraordinary loss on early extinguishingment
of debt, net of income tax benefit (13.1) -- -- -- --
Cumulative effect on prior periods of
change in accounting for income taxes -- -- -- -- 6.5
-------- -------- -------- -------- --------
Net income $ 115.0 $ 92.1 $ 64.0 $ 55.0 $ 2.3
======== ======== ======== ======== ========

DECEMBER 31,
(IN MILLIONS) ------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----

BALANCE SHEET DATA
Assets $4,985.1 $5,152.5 $4,374.0 $2,842.9 $2,286.1
Current liabilities 339.8 270.9 199.8 170.9 116.3
Long-term obligations 2,532.1 2,419.9 1,839.0 1,159.0 962.6
Shareholder's equity 826.6 1,019.9 1,028.5 622.2 551.3

(IN MILLIONS) YEARS ENDED DECEMBER 31,
------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----

PROPORTIONATE DATA (UNAUDITED)(C)
Operating revenues $1,502.2 $1,261.8 $ 865.4 $ 733.0 $ 712.8
Operating expenses 1,107.1 912.4 650.3 552.5 667.5(a)
-------- -------- -------- -------- --------
Income from operations 395.1 349.4 215.1 180.5 45.3
Interest expense (269.2) (212.8) (160.9) (138.5) (69.8)
Interest and other income 69.2 44.2 42.1 45.7 16.1
-------- -------- -------- -------- --------
Income (loss) before income taxes 195.1 180.8 96.3 87.7 (8.4)
Provision (credit) for income taxes 67.0 88.7 32.3 32.7 (4.2)
-------- -------- -------- -------- --------
Income (loss) before extraordinary loss and
cumulative effect of change in
accounting principle 128.1 92.1 64.0 55.0 (4.2)
Extraordinary loss on early extinguishment
of debt, net of income tax benefit (13.1) -- -- -- --
Cumulative effect on prior periods of
change in accounting for income taxes -- -- -- -- 6.5
-------- -------- -------- -------- --------
Net income $ 115.0 $ 92.1 $ 64.0 $ 55.0 $ 2.3
======== ======== ======== ======== ========

Operating cash flow(b) $ 559.3 $ 493.7 $ 326.5 $ 264.9 $ 202.9
======== ======== ======== ======== ========

25

(a) For the year ended December 31, 1993, operating expenses include special
charges of $98.4 million. Special charges include (1) costs (unreimbursed
development expenses and capitalized interest) associated with the
termination of negotiations for the Carbon II project in Mexico of $28.0
million; (2) a reserve of $52.4 million, which reflects the reduced value
of investments in five geothermal power plants due to lower gas price
forecasts; and (3) a reserve of $18.0 million for project development and
other costs.

(b) Income from operations plus depreciation, amortization and other non-cash
charges.

(c) Reflects EME's pro rata ownership interest in its energy projects and oil
and gas investments. Because significant 50% or less owned investments of
EME are not consolidated, EME believes that the discussion set forth below
of certain proportionate data facilitates an understanding and assessment of
its results of operations. Except for certain industries, proportionate
accounting is not in accordance with generally accepted accounting
principles.

Operating revenues increased in 1997 and 1996. The 1997 increase resulted
primarily from increases in electric revenues attributable to the start of
commercial operation of Loy Yang B Unit 2 in October 1996 and the Kwinana
project in December 1996 and higher energy revenues from First Hydro as a
result of increased utilization and higher pool prices, partially offset by
lower capacity prices in 1997. There were no comparable electric revenues
for Loy Yang B Unit 2 for the first nine months of 1996 or Kwinana for the
first 11 months of 1996. The 1996 increase in electric revenues over 1995
was primarily due to the acquisition of First Hydro in December 1995,
combined with its strong operating performance since acquisition, the start
of commercial operation of Loy Yang B Unit 2 and the Kwinana project in the
fourth quarter of 1996, both of which were previously under construction,
and the increase in ownership of Iberian Hy-Power from 34% to 100% in
January 1996. The 1997 increase in fuel expense and plant operations was
primarily due to commencement of commercial operations of the Kwinana
project in the fourth quarter of 1996 and increased generation and higher
prices at First Hydro. The 1997 increase in depreciation and amortization
resulted from commencement of commercial operations of Loy Yang B Unit 2 and
the Kwinana project in the fourth quarter of 1996. The 1996 increase
resulted from having no comparable expenses for First Hydro for the first 11
months of 1995 and no comparable expenses for Iberian Hy-Power, Loy Yang B
Unit 2 and Kwinana for fiscal year 1995.

Interest expense increased in 1997 and 1996, principally as a result of
higher project debt levels. Interest and other income increased in 1997 and
1996. The 1997 increase resulted from interest earned on higher cash
balances. The 1996 increase is primarily due to a pre-tax gain of $20
million on the sale of EME's interest in four operating geothermal projects.

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

This Annual Report on Form 10-K includes certain forward-looking statements, the
realization of which may be affected by certain important factors discussed in
Management's Discussion and Analysis of Results of Operations and Financial
Condition thereunder and elsewhere herein.

GENERAL
- -------

Edison Mission Energy (EME) is one of the leading global producers of
electricity. Through its subsidiaries, EME is engaged in the business of
developing, acquiring, owning and operating electric power generation facilities
worldwide. EME's current investments include 53 projects totaling 9,325
megawatts (MW) of generation capacity, of which 7,403 MW are in operation and
1,922 MW are under construction.

EME's operating revenues are derived primarily from electric revenues and
equity in income from energy projects. Electric revenues accounted for 76%, 77%
and 64% of total operating revenues during

26

1997, 1996 and 1995, respectively. Operating revenues also include equity in
income from oil and gas investments and revenue attributable to operation and
maintenance services.

Electric revenues are derived from consolidated results of operations of five
international entities. Equity in income from energy projects primarily relates
to EME's ownership interest of 50% or less in projects. The equity method of
accounting is generally used to account for the operating results of entities
over which a company has a significant influence but in which it does not have a
controlling interest. With respect to entities accounted for under the equity
method, EME recognizes its proportional share of the income or loss of such
entities.

ACQUISITIONS
- ------------

In 1992, a subsidiary of EME (together with other wholly owned affiliates of
EME) acquired 51% of the 1,000-MW Loy Yang B Power Station (Loy Yang B) from the
State Government of Victoria (State). In May 1997, a subsidiary of EME acquired
the State's 49% interest in Loy Yang B. In connection with the 1992
acquisition, the State Electricity Commission of Victoria (SECV) entered into a
30-year power purchase agreement with EME to purchase its share of the plant
output. Loy Yang B's principal assets are two 500-MW units fired by brown coal
located near Melbourne, Australia.

Consideration for the State's 49% interest consisted of (1) a cash payment of
approximately $64 million (84 million Australian dollars), (2) termination of
the existing power purchase agreement and other related agreements and (3)
entering into a new series of power sales-related contracts with the State
resulting in a total transaction value of approximately $686 million (900
million Australian dollars).

In December 1995, an indirect subsidiary of EME purchased all of the
outstanding shares of First Hydro Company (First Hydro) for approximately $1
billion (653 million pounds sterling). First Hydro's principal assets are two
pumped-storage electric power stations located in North Wales at Dinorwig and
Ffestiniog, which have a combined capacity of 2,088 MW.

This acquisition was funded through a combination of (i) a $621 million (400
million pounds sterling) credit facility with a bank and (ii) a $455 million
(295.3 million pounds sterling) equity investment funded from a combination of a
$350 million capital contribution from Edison International (EME's parent
company) and from EME's working capital and credit lines. In January 1996, the
400 million pounds sterling credit facility was canceled upon repayment of all
outstanding principal and accrued interest with proceeds from the issuance of
400 million pounds sterling of 9% Guaranteed Secured Bonds due on July 31, 2021.

In January 1996, EME purchased the remaining 66% of Iberian Hy-Power
Amsterdam B.V. (Iberian Hy-Power) for approximately $20 million, increasing its
ownership to 100%. Iberian Hy-Power owns interests in 18 run-of-the-river
hydroelectric facilities in Spain totaling 86 MW.

Each of the acquisitions 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, with the excess being
allocated to goodwill. The consolidated statement of income for 1995 includes
operating results of First Hydro beginning in December 1995 and the consolidated
statement of income for 1997 reflects the operations under the new contracts and
the elimination of the minority interest of Loy Yang B beginning on May 9, 1997.

27

RESULTS OF OPERATIONS
- ---------------------

Operating Revenues

Operating revenues increased significantly in 1997 and 1996. The 1997
increase resulted primarily from increases in electric revenues attributable to
the start of commercial operation of Loy Yang B Unit 2 in October 1996 and the
Kwinana project in December 1996 and higher energy revenues from First Hydro as
a result of increased utilization and higher pool prices, partially offset by
lower capacity prices in 1997. There were no comparable electric revenues for
Loy Yang B Unit 2 for the first nine months of 1996 and Kwinana for the first 11
months of 1996. The 1996 increase in electric revenues over 1995 was primarily
due to the acquisition of First Hydro in December 1995 combined with its strong
operating performance since acquisition, the start of commercial operation of
Loy Yang B Unit 2 and the Kwinana project in the fourth quarter of 1996, both of
which were previously under construction, and the increase in ownership of
Iberian Hy-Power from 34% to 100% in January 1996.

Electric revenues in the fourth quarter of 1997 were lower from fourth
quarter revenues in 1996 attributable to the Loy Yang B project due to the
restructuring of agreements associated with the 49% acquisition of Loy Yang B.
This also resulted in partially offsetting the higher electric revenues from the
Loy Yang B project in 1997.

Equity in income from energy projects rose 17% in 1997 over 1996, compared
with a 2% increase in 1996 over 1995. The 1997 increase is primarily
attributable to higher electric and steam revenue for several cogeneration
projects due to higher fuel gas prices upon which revenues are based. Equity in
income from oil and gas investments increased substantially in 1997 and 1996,
primarily due to higher gas prices in 1997 and higher oil and gas prices and
increased gas production in 1996.

A significant number of EME's domestic projects are located on the West
Coast. These projects generally have power sales contracts that provide for
higher payments during the summer months. Both First Hydro and Iberian Hy-Power
provide for higher electric revenues during the winter months. In addition,
First Hydro experienced higher energy sales in 1996 due to higher capacity
prices resulting from narrowing of the margin between the demand and available
generation forecast over the summer months and increased utilization. Unusual
weather conditions and unanticipated facility maintenance may have an effect on
future quarterly revenues.

Operating Expenses

Total operating expenses increased $104.6 million in 1997 and $212.4 million
in 1996. The increases for both periods were principally due to higher fuel
expense, plant operations, depreciation and amortization and administrative and
general expenses. Fuel and plant operations expense increased $62.8 million in
1997 and $140.4 million in 1996, depreciation and amortization expense increased
$12.9 million in 1997 and $44.3 million in 1996 and administrative and general
expenses increased $27.6 million in 1997 and $26.6 million in 1996.

The 1997 increase in fuel expense and plant operations was primarily due to
commencement of commercial operations of the Kwinana project in the fourth
quarter of 1996 and increased generation and higher prices at First Hydro.

28

The 1997 increase in depreciation and amortization resulted from commencement
of commercial operations of Loy Yang B Unit 2 and the Kwinana project in the
fourth quarter of 1996. Loy Yang B's depreciation expense in 1997 was partially
reduced due to an extension in the useful life of Loy Yang B's plant and
equipment from approximately 30 years, the term of the previous power purchase
agreement, to 50 years (the projected economic life of the plant). The 1996
increase resulted from having no comparable expenses for First Hydro for the
first 11 months of 1995 and no comparable expenses for Iberian Hy-Power, Loy
Yang B Unit 2 and Kwinana for fiscal year 1995.

Both the 1997 and 1996 increase in administrative and general expenses is
attributable to an increase of approximately $54 million and $16 million,
respectively, in compensation expense as a result of charges related to EME's
phantom stock plan which is a part of Edison International Officer's Long-Term
Incentive Plan. The higher charges in 1997 were principally due to a substantial
appreciation in the value of EME's "phantom stock" over its exercise price. The
1997 increase in compensation expense was partially offset by lower project
development costs.

Other Income (Expense)

Interest and other income increased $6.5 million in 1997 over 1996, compared
with a decrease of $9.3 million in 1996 from 1995. The 1997 increase resulted
primarily from interest earned on higher cash balances. The 1996 decrease was
primarily due to income recognized in August 1995 for reimbursement of certain
1994 development expenses not previously recognized in settlement of EME's
remaining investment in Minera Carbonifera Rio Escondido.

During the second quarter of 1997, EME completed a sale of its ownership
interest in B.C. Star Partners (B.C. Star) for total cash proceeds of $71.2
million. EME recorded an after-tax gain of approximately $14 million on the
sale in April 1997. Based upon management's forecast of operating profits that
may have been realized from this operation, EME expects a minimal impact on its
future results of operations.

During the second quarter of 1996, CalEnergy Company, Inc., EME's partner in
four operating geothermal projects in California, purchased all of the stock of
four wholly owned subsidiaries of EME, which held interests in these projects.
The purchase price of $70 million resulted in an after-tax gain of $15.5
million. There was no impact on EME's future revenues as EME discontinued
recognizing earnings from these projects during 1993.

Interest incurred rose slightly in 1997 over 1996, compared to a $71.3
million increase in 1996 over 1995. The 1996 increase was due primarily to a
full year's inclusion of interest on the debt related to the First Hydro
acquisition and debt related to Iberian Hy-Power. Capitalized interest decreased
$51.9 million in 1997 from 1996, compared to an increase of $3.3 million in 1996
over 1995. The 1997 decrease is due to the completion of construction and
resultant commercial operation of Loy Yang B Unit 2 and the Kwinana project in
the fourth quarter of 1996 at which time the Company discontinued recording
capitalized interest related to these projects.

Dividends on preferred securities increased $3 million in 1996 over 1995.
The increase in 1996 was due to the inclusion of a full year of dividends on the
Series B preferred securities issued during the third quarter of 1995.

Minority interest expense decreased $30.7 million in 1997 from 1996, compared
with an increase of $21.2 million in 1996 over 1995. The 1997 decrease resulted
from the acquisition of the remaining 49%

29

ownership interest in Loy Yang B in May 1997. The acquisition also contributed
to significantly lower minority interest expense in the fourth quarter of 1997
from 1996. The 1996 increase is due to Loy Yang B Unit 2 commencing commercial
operation in October 1996.

Provision for Income Taxes

EME had an effective tax provision rate of 30.9%, 47.1% and 32.6% in 1997,
1996 and 1995, respectively. The decrease in the 1997 effective tax rate was
primarily due to a reduction in corporate income taxes in the United Kingdom
(U.K.). The U.K. government decreased the corporate tax rate from 33% to 31%,
effective April 1, 1997. In accordance with Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes," this reduction in the U.K.
income tax rate resulted in an one-time reduction in income tax expense of
approximately $20 million to adjust the U.K. deferred income tax liability
(primarily related to First Hydro) to the new lower tax rate. The increase in
the 1996 effective tax rate was primarily due to higher international earnings
taxed at higher tax rates and certain expenditures not deductible in foreign
jurisdictions.

Extraordinary Loss

The early repayment of Loy Yang B's existing debt facilities of $713 million
in connection with the acquisition of the remaining 49% interest in May 1997
resulted in an extraordinary loss of $13.1 million (net of income tax benefit of
$8.6 million) attributable to the write-off of unamortized debt issue costs.

LIQUIDITY AND CAPITAL RESOURCES
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Cash provided by operating activities is derived primarily from distributions
from energy projects and dividends from investments in oil and gas. For the
year ended December 31, 1997, net cash provided by operating activities
decreased $35 million over 1996, compared with an increase of $144.6 million in
1996 from 1995. The 1997 decline primarily reflects an increase in working
capital requirements principally due to lower accounts receivable collections
from First Hydro. The 1996 improvement primarily reflects higher net income,
increased dividends from oil and gas investments and improved accounts
receivable collections principally attributable to First Hydro.

Dividends from investments in oil and gas increased $31.1 million in 1996
over 1995. The increase was principally due to increased dividends paid by Four
Star Oil & Gas Company as a result of higher earnings in 1996 over 1995.

Net cash provided by financing activities decreased $123.7 million during
1997 from 1996, compared with a substantial decrease during 1996 from 1995. The
1997 decrease was principally due to a reduction in financing activities and
higher cash dividends paid to Edison International. In 1997, the Loy Yang B
financing proceeds received in connection with the acquisition of the remaining
49% interest were primarily used to repay Loy Yang B's existing debt facilities.
In 1996, EME issued 400 million pounds sterling of 9% Guaranteed Secured Bonds
(U.S. $603.8 million), the proceeds of which were used to repay the 400 million
pounds sterling credit facility entered into in December 1995. In addition,
Edison Mission Energy Funding Corp., 99% owned by Broad Street Contract
Services, Inc. and 1% owned by EME, completed a sale of $450 million of senior
notes and bonds to institutional investors pursuant to the Rule 144A exemption
under the U.S. Securities Act of 1933 for non-public sales in December 1996. The
1996 decrease was primarily attributable to (1) a reduction in net borrowings
under

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EME's $500 million revolving credit facility in 1996, (2) a dividend paid to
Edison International of $150 million in 1996 compared with a $350 million
capital contribution received from Edison International in 1995 (pursuant to the
acquisition of First Hydro) and (3) proceeds of $62.5 million received in 1995
from the issuance of Series B Preferred Securities.

The Loy Yang B financing in 1997 consists of (1) a $373 million (490 million
Australian dollars) 15-year interest only term facility, (2) a $583 million (765
million Australian dollars) 20-year amortizing term facility with principal and
interest payments scheduled quarterly commencing September 30, 1998 and (3) an
$8 million (10 million Australian dollars) working capital facility with a term
equal to that of the 20-year amortizing term facility. The financing was
structured on a non-recourse basis. Lenders look solely to the operating cash
proceeds of Loy Yang B to repay the debt and have taken a security interest in
the Loy Yang B project assets.

In December 1996, Edison Mission Energy Funding Corp., 99% owned by Broad
Street Contract Services, Inc. and 1% owned by EME, completed a sale of $450
million of senior notes and bonds to institutional investors pursuant to the
Rule 144A exemption under the U.S. Securities Act of 1933 for non-public sales.
The senior notes and bonds are secured by the pledge of (i) notes issued by four
EME subsidiaries that own interests in four California cogeneration projects,
(ii) 99% of the capital stock of Edison Mission Energy Funding Corp. and (iii) a
guarantee issued by