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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, 1999
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 office) (Zip Code)
Registrant's telephone number, including area code: (949) 752-5588
Securities registered pursuant to Section 12(b) of the Act:
9-7/8% Cumulative Monthly
Income Preferred Securities, Series A* New York Stock Exchange
-------------------------------------- -----------------------
(Title of Class) (name of each exchange on
which registered)
8-1/2% Cumulative Monthly New York Stock Exchange
Income Preferred Securities, Series B* -----------------------
-------------------------------------- (name of each exchange on
(Title of Class) which registered)
Securities registered pursuant to section 12(g) of the Act:
Common Stock, no par value
--------------------------
(Title of Class)
* Issued by Mission Capital, L.P., a limited partnership in which Edison
Mission Energy is the sole general partner. The payments of distributions
on the preferred securities and payments on liquidation or redemption are
guaranteed by Edison Mission Energy.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO
------- -------
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K _______.
Aggregate market value of the registrant's Common Stock held by non-
affiliates of the registrant as of March 30, 2000: $0. Number
of shares outstanding of the registrant's Common Stock as of March 30,
2000: 100 shares (all shares held by an affiliate of the registrant).
TABLE OF CONTENTS
Item Page
- ---- ----
PART I
1. Business...............................................................1
2. Properties............................................................26
3. Legal Proceedings.....................................................27
4. Submission of Matters to a Vote of Security Holders...................28
PART II
5. Market for Registrant's Common Equity and Related Shareholder Matters.29
6. Selected Financial Data...............................................32
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................33
7a. Quantitative and Qualitative Disclosures About Market Risk............51
8. Financial Statements and Supplementary Data...........................51
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................51
PART III
10. Directors and Executive Officers of the Registrant....................95
11. Executive Compensation................................................98
12. Security Ownership of Certain Beneficial Owners and Management.......108
13. Certain Relationships and Related Transactions.......................109
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......110
Signatures...........................................................134
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PART I
ITEM 1. BUSINESS
The Company
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Edison Mission Energy is an independent power producer. We are engaged in the
business of developing, acquiring, owning and operating electric power
generation facilities worldwide. Edison International is our parent company and
also owns Southern California Edison Company, one of the largest electric
utilities in the United States.
We were formed in 1986 with two domestic operating projects. Currently, we
own interests in 34 domestic and 38 international operating power stations with
an aggregate generating capacity of 26,649 megawatts (MW), of which our share is
22,056 MW. One domestic and three international projects totaling 1,797 MW of
generating capacity, of which our anticipated share is approximately 714 MW, are
currently in the construction stage. At December 31, 1999, we had consolidated
assets of $15.5 billion and total shareholder's equity of $3.1 billion.
We are incorporated under the laws of the State of California. Our
headquarters and principal executive offices are located at 18101 Von Karman
Avenue, Suite 1700, Irvine, California 92612, and our telephone number is (949)
752-5588. Unless indicated otherwise or the context otherwise requires,
references in this Annual Report on Form 10-K are with respect to Edison Mission
Energy and its consolidated subsidiaries and the partnerships or limited
liability entities through which Edison Mission Energy and its partners own and
manage their project investments.
Forward-Looking Statements
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This annual report contains forward-looking statements that reflect Edison
Mission Energy's current expectations and projections about future events based
on our knowledge of present facts and circumstances and our assumptions about
future events. In this annual report, the words "expects," "believes,"
"anticipates," "estimates," "intends," "plans" and variations of these words and
similar expressions are intended to identify forward-looking statements. These
statements necessarily involve risks and uncertainties that could cause actual
results to differ materially from those anticipated. Some of these risks,
uncertainties and other important factors that could cause results to differ are
described throughout this annual report, particularly in this item under the
caption "Risk Factors Associated with Project Development, Finance and
Operation;" in Part II, Item 7., "Management's Discussion and Analysis of
Financial Condition and Results of Operations;" and in the "Notes to
Consolidated Financial Statements" contained in Part II, Item 8. The
information contained in this report is subject to change without notice.
Readers should review future reports filed by Edison Mission Energy with the
Securities and Exchange Commission.
Segment Information
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We operate predominately in one line of business, electric power generation,
with reportable segments organized by geographic region: Americas, Asia Pacific
and Europe, Central Asia, Middle East and Africa. Our plants are located in
different geographic areas, which mitigate the effects of regional markets,
economic downturns or unusual weather conditions. These regions take advantage
of the increasing globalization of the independent power market. See "-- Notes
to Consolidated Financial Statements, Note 16. Business Segments".
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Description of Business
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General Overview
We are an independent power producer engaged in the business of developing,
acquiring, owning and operating electric power generation facilities worldwide.
Our business has evolved from the development of contract-based domestic power
projects to the development of contract-based international power projects and
the acquisition of operating generating assets within developed and deregulating
power markets. Currently, we own interests in 34 domestic and 38 international
operating electrical power generation facilities.
Until the enactment of the Public Utility Regulatory Policies Act of 1978,
utilities were the only producers of bulk electric power intended for sale to
third parties in the United States. The Public Utility Regulatory Policies Act
encouraged the development of independent power by removing regulatory
constraints relating to the production and sale of electric energy by certain
non-utilities and requiring electric utilities to buy electricity from certain
types of non-utility power producers, qualifying facilities, under certain
conditions. The passage of the Energy Policy Act of 1992 further encouraged the
development of independent power by significantly expanding the options
available to independent power producers with respect to their regulatory status
and by liberalizing transmission access. As a result, a significant market for
electric power produced by independent power producers, such as us, has
developed in the United States since the enactment of the Public Utility
Regulatory Policies Act. In 1998, utility deregulation in several states led
utilities to divest generating assets, which has created new opportunities for
growth of independent power in the United States.
The movement toward privatization of existing power generation capacity in
many foreign countries and the growing need for new capacity in developing
countries have also led to the development of significant new markets for
independent power producers outside the United States. We believe that we are
well-positioned to continue to realize opportunities in these new foreign
markets. See "--Strategy" below.
Strategy
Our business goal is to be one of the leading owners and operators of
electric generating assets in the world. We play an active role, as a long-term
owner, in all phases of power generation, from planning and development through
construction and commercial operation. We believe that this involvement allows
us to better ensure, with our experienced personnel, that our projects are well-
planned, structured and managed, thus maximizing value creation. We have
separate strategies for developed and developing countries.
In developed countries, we expect that new long-term contracts are likely to
be the exception rather than the rule. Our strategy focuses primarily on three
areas with respect to plants whose output is not committed to be sold under
long-term contracts, which are known as merchant plants: valuation, power
marketing and trading and regulation. First, we continuously improve our
valuation tools, enabling us to bid more effectively and competitively on assets
that will be sold over the next five years in the United States, the United
Kingdom, Spain, Italy, Australia, New Zealand and other developed countries.
Second, we draw on our power marketing and trading skills to mitigate price
risks and to enhance the returns of our merchant plants. Third, since our
principal customers continue to be regulated utilities, we strive to understand
the regulatory and economic environment in which these utilities operate so we
may better anticipate and prepare for what they will do.
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In developing countries, our strategy focuses on investing with good
partners, securing non-recourse financing based upon long-term contracts with
state-owned utilities and securing government support from organizations like
the Export-Import Bank of the United States, the U.S. Overseas Private
Investment Corporation and The Export-Import Bank of Japan.
In making investment decisions, we evaluate potential project returns against
rate of return guidelines. We establish these guidelines by identifying a base
rate of return and adjusting the base rate by potential risk factors, like risks
associated with project location and stage of project development. We endeavor
to mitigate these risks by (i) evaluating all projects and the markets in which
they operate, (ii) selecting partners with complementary skills and local
experience, (iii) structuring investments through subsidiaries, (iv) managing
up-front development costs, (v) utilizing limited recourse financing and (vi)
linking revenue and expense components where appropriate. Many of our projects
are operated by our subsidiaries, which help us to preserve and enhance the
value of our investments.
In response to increasing globalization of the independent power market, we
have organized our operation and development activities into three geographic
regions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia,
Middle East and Africa. Each region is served by one or more teams consisting
of business development, operations, finance and legal personnel, and each team
is responsible for all our activities within a particular geographic region.
Also, we mobilize personnel from outside a particular region when needed in
order to assist in the development of specified projects.
Below is a brief discussion of the current strategy for each of the three
regions and a summary of our projects that are currently in the construction or
early operations stage and other significant operating projects in each of the
regions.
Americas
Our Americas region is headquartered in Irvine, California with additional
offices located in Chicago, Illinois; Chantilly, Virginia; and Washington, D.C.
The strategy for the Americas region is (i) to manage our interest in operating
and construction phase projects located throughout the United States, (ii) to
pursue the acquisition and development of existing generating assets from
utilities, industrial companies and other independent power producers throughout
the region, and (iii) to pursue the development of new power projects throughout
the region. We currently have 34 operating projects in this region, all of which
are presently located in the United States.
In December 1998, we acquired 50% of the 540-MW EcoElectrica liquefied
natural gas combined-cycle cogeneration facility under construction in Penuelas,
Puerto Rico for approximately $243 million. The project also includes a
desalination plant and liquefied natural gas storage and vaporization
facilities, and is expected to commence commercial operation by the first
quarter of 2000.
In March 1999, we acquired 100% of the 1,884-MW Homer City Generating Station
for approximately $1.8 billion. This facility is a coal-fired plant in the mid-
Atlantic region of the United States and has direct, high voltage
interconnections to both the New York Independent System Operator, which
controls the transmission grid and energy and capacity markets for the State of
New York and is commonly known as the NYISO and the Pennsylvania-New Jersey-
Maryland Power Pool, which is commonly known as the PJM. We operate the plant,
which we believe is one of the lowest-cost generation facilities in the region.
In December 1999, we acquired the fossil-fuel generating assets of
Commonwealth Edison, which are commonly referred to as the Illinois Plants,
totaling 6,812 MW of generating capacity, for approximately $4.1 billion. We
operate these plants, which provide access to the Mid-America
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Interconnected Network and the East Central Area Reliability Council. In
connection with this transaction, we entered into power purchase agreements with
Commonwealth Edison with a term of up to five years.
Concurrently with this acquisition, we assigned our right to purchase the
Collins Station, a 2,698 MW gas and oil-fired generating station located in
Illinois, to a third party. After this assignment, we entered into a lease of
the Collins Station with a term of 33.75 years. The aggregate MW purchased or
leased as a result of these transactions is 9,510 MW.
For further information regarding our 34 domestic operating projects, see "--
Our Operating Power Generation Facilities--Domestic."
Asia Pacific
Our Asia Pacific region is headquartered in Singapore with additional offices
located in Australia, Indonesia and the Philippines. The strategy for this
region is (i) to pursue projects in countries where there exist strong political
commitment and the structural framework necessary for private power, (ii) to
seek opportunities to employ indigenous fuels and (iii) to seek strategic,
complimentary alliances with partners who bring value to a project by providing
fuel, equipment and construction services.
Beginning in mid-1997, several of the developing economies in Asia
experienced an economic downturn that is continuing, and has resulted in an
overall decline in the growth of demand for electric power, and, in some
countries, a decline in electric power usage. Many governments in the region
have committed to privatization of the electric power industry, and are looking
to the private sector to develop a significant portion of new generating
capacity and to purchase existing generating assets.
Our activity in the Asia Pacific region commenced in December 1992 with the
acquisition of a 51% interest of Loy Yang B from the State Government of
Victoria, Australia's first electric privatization effort. In May 1997, we
acquired the State's remaining 49% interest in the Loy Yang B plant. The first
of two 500-MW units at the Loy Yang B plant began commercial operation in
October 1993. Unit 2 commenced commercial operation in October 1996. We
provide operation and maintenance services for both units.
In April 1995, we and our 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 consists of two
units, each of which has a capacity of approximately 615 MW. In January 1996,
we purchased an additional 7.5% interest in the Paiton project from a subsidiary
of General Electric Corporation, thus increasing our ownership interest to 40%.
In May 1999, Paiton notified PT Perusahaan Listrik Negara that Unit 7 of
Paiton achieved commercial operation under terms of the power purchase agreement
and that Unit 8 of Paiton achieved commercial operation under the terms of the
power purchase agreement in July 1999. The project's output is fully contracted
with the state-owned electricity company, PT Perusahaan Listrik Negara. Payments
are in Indonesian Rupiah, with the portion of these payments intended to cover
non-Rupiah project costs including returns to investors, indexed to the
Indonesian Rupiah/U.S. dollar exchange rate established at the time the power
purchase agreement was executed in February 1994. PT Perusahaan Listrik
Negara's payment obligations are supported by the Government of Indonesia. The
exchange rate of Indonesian Rupiah into U.S. dollars and the projected rate of
growth of the Indonesian economy have deteriorated significantly since the
Paiton project was contracted, approved and financed, thus significantly
increasing the cost of power in Rupiah terms to PT Perusahaan Listrik Negara.
The project
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received 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'
determination that there is increased risk that PT Perusahaan Listrik Negara
might not be able to honor its power purchase agreement with Paiton. In
addition, PT Perusahaan Listrik Negara filed a lawsuit contesting the validity
of its agreement to purchase electricity from the project. The lawsuit was
withdrawn by PT Perusahaan Listrik Negara on January 20, 2000, and on February
21, 2000, Paiton and PT Perusahaan Listrik Negara executed an Interim Agreement
pursuant to which the power purchase agreement will be administered pending a
long-term restructure of the power purchase agreement. Among other things, the
Interim Agreement provides for dispatch of the project, fixed monthly payments
to Paiton by PT Perusahaan Listrik Negara, the first of which was received on
March 24, 2000, and the standstill of any further legal proceedings by either
party during the term of the Interim Agreement, which runs through December 31,
2000 and may be extended by mutual agreement. PT Perusahaan Listrik Negara has
also asked that negotiations on a long-term restructuring of the tariff begin in
April 2000. Any material modifications of the power purchase agreement could
also require a renegotiation of the Paiton project's debt agreements. The
impact of any such renegotiation with PT Perusahaan Listrik Negara, the
Government of Indonesia or the project's creditors on our dividends from the
project is uncertain at this time; however, we believe that we will ultimately
recover our investment in the project.
Kwinana is a 116-MW gas-fired cogeneration project located at the British
Petroleum Kwinana refinery near Perth, Australia. The plant, which is 100%
owned by us, began commercial operations in December 1996. The plant supplies
electricity to Western Power, formerly the State Electricity Commission of
Western Australia, and electricity and steam to the British Petroleum Kwinana
refinery.
In July 1998, we purchased a 25% interest in the Tri Energy project, a 700-MW
gas-fired power plant under construction in the Ratchaburi Province, Thailand.
The project will sell its capacity and energy to the Electricity Generating
Authority of Thailand under a 20-year power purchase agreement. Commercial
operation is expected to begin in mid-2000.
In May 1999, we acquired 40% of Contact Energy from the government of New
Zealand for $635 million. The remaining 60% of Contact Energy's shares were
sold in a public offering resulting in widespread ownership among the citizens
of New Zealand and offshore investors. These shares are publicly traded on
stock exchanges in New Zealand and Australia. Contact Energy owns and operates
ten hydroelectric, geothermal and natural gas-fired power generating plants
primarily in New Zealand with a total current generating capacity of 2,626 MW,
of which our share is 949 MW. Contact Energy also owns interest in one project
under construction in New Zealand with an expected generating capacity of 45 MW,
of which our share is 18 MW. In addition, Contact Energy has expanded into the
retail electricity and gas markets in New Zealand since 1998 through acquisition
of regional electricity supply and retail gas supply businesses. See
"Regulatory Matters - Recent Foreign Regulatory Matters."
Europe, Central Asia, Middle East and Africa
Our Europe, Central Asia, Middle East and Africa region is headquartered in
London, England with additional offices located in Italy, Spain and Turkey. The
London office was established in 1989. The 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 developing markets. Our strategy
for the region is to pursue the development and acquisition of medium to large
scale power and cogeneration facilities with diversified fuel sources and
generation technology.
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Beginning in the early 1990's, we acquired the Iberian Hy-Power projects,
which consist of 18 small hydroelectric facilities located in Spain, an 80%
interest in the 220 MW Roosecote project located in northwest England, and a 33%
interest in the 214 MW Derwent project located in Derby, England.
In December 1995, we purchased all of the outstanding shares of First Hydro
Company for approximately $1 billion or 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 in England and Wales, (ii) providing system
support services to The National Grid Company plc, and (iii) selling its
installed capacity on a forward basis by entering into contracts for
differences, which are electricity rate swap agreements, with large electricity
suppliers.
In June 1995, the ISAB project, of which we own 49%, signed a twenty-year
power purchase contract with ENEL S.p.A., Italy's state electricity corporation,
under 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 oil residues from the ISAB
refinery in Priolo Gargallo into clean-burning synthetic fuel gas that will be
used to generate electricity in a combustion turbine. The approximately 2
trillion lira, or $1.3 billion, project financing was completed in April 1996,
with construction commencing in July 1996. The project is near completion, with
commercial operation expected to begin in the first quarter of 2000.
In February 1995, we signed a shareholders' agreement to develop the $180
million Doga Enerji A.S. project in Esenyurt, near Istanbul, Turkey, in which we
would own 80%. In April 1997, we completed financing and commenced construction
of the Doga project. The 180-MW combined cycle gas-fired cogeneration facility
commenced commercial operation in May 1999.
In July 1999, we acquired 100% of the Ferrybridge and Fiddler's Ferry coal-
fired power plants in the United Kingdom with a total generating capacity of
3,886 MW from PowerGen UK plc for approximately $2.0 billion. Ferrybridge,
located in West Yorkshire, and Fiddler's Ferry, located in Warrington, are in
the middle of the order in which plants are called upon to dispatch electric
power. The plants complement the pumped-storage hydroelectric power plants we
already own in the United Kingdom and sell power into the electricity trading
market there.
During October 1999, we completed the acquisition of the remaining 20% of the
220 MW natural gas-fired Roosecote project located in England. Consideration
for the remaining 20% consisted of a cash payment of approximately $16.0
million, or 9.6 million pounds sterling.
In March 2000, we entered into a purchase agreement with a third party to
acquire a 50% interest in a series of power projects that are in operation or
under development in Italy. All of the projects use wind to generate
electricity from turbines which is sold under fixed-price long-term tariffs.
The initial purchase price is $22 million with equity contribution obligations
of up to $40 million, depending on the number of projects that are ultimately
developed.
Project Development
The development of power generation projects, whether through new
construction or the acquisition of existing assets, involves numerous elements,
including evaluating and selecting development opportunities, evaluating
regulatory and market risks, designing and engineering the
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project, acquiring necessary land rights, permits and fuel resources, obtaining
financing, managing construction and, in some cases, obtaining power and steam
sales agreements.
We initially evaluate and select potential development projects based on a
variety of factors, including the reliability of technology, the strength of the
potential partners, the feasibility of the project, the likelihood of obtaining
a long-term power purchase agreement or profitably selling power without this
agreement, the probability of obtaining required licenses and permits and the
projected economic return. During the development process, we monitor the
viability of our projects and make business judgments concerning expenditures
for both internal and external development costs. Completion of the financing
arrangements for a project is generally an indication that business development
activities are substantially complete.
Project Type
The selection of power generation technology for a particular project is
influenced by various factors, including regulatory requirements, availability
of fuel and anticipated economic advantages for a particular application.
We have interests in operating projects that employ gas-fired combustion
turbine technology, predominately through an application known as cogeneration.
Cogeneration facilities sequentially produce two or more useful forms of energy,
such as electricity and steam, from a single primary source of fuel, such as
natural gas or coal. Many of our cogeneration projects are located near large,
industrial steam users or in oil fields that inject steam underground to enhance
recovery of heavy oil. The regulatory advantages for cogeneration facilities
under the Public Utility Regulatory Policies Act of 1978, as amended, have
become somewhat less significant because of other federal regulatory exemptions
made available to independent power producers under the Energy Policy Act.
Accordingly, we expect that the majority of our future projects will generate
power without selling steam to industrial users.
We also have interests in projects that use renewable resources like
hydroelectric energy and geothermal energy. Our hydroelectric projects,
excluding First Hydro's plants, use run-of-the-river technology to generate
electricity. The First Hydro plant utilizes pumped-storage stations that
consume electricity when it is comparatively less expensive in order to pump
water for storage in an upper reservoir. Water is then allowed to flow back
through turbines in order to generate electricity when its market value is
higher. This type of generation is characterized by its speed of response, its
ability to work efficiently at wide variations of load and the basic reliance of
revenue on the difference between the peak and trough prices of electricity
during the day. Our geothermal projects totaling 269 MW (our share 108 MW),
included as part of our Contact Energy investment, use technologies that convert
the heat from geothermal fluids and underground steam into electricity.
We also have domestic and international interests in operating projects and
projects under construction and advanced development which are large scale,
coal-fired projects using pulverized coal and coal-fired generation technology.
In the United States, we have developed and acquired coal and waste coal-fired
projects that employ traditional pulverized coal and circulating fluidized bed
technology, which allows for the use of lower quality coal and the direct
removal of sulfur from the coal.
Long-Term Power and Steam Sales Contracts
Many of our operating projects in the United States sell power and steam to
domestic electric utilities and industrial steam users under contracts.
Electric power generated by several of our
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international projects is sold under long-term contracts to electric utilities
located in the country where the power project is located. These projects'
revenues from power purchase agreements usually consist of two components:
energy payments and capacity payments. Energy payments are made based on actual
deliveries of electric energy, such as kilowatt-hours, to the purchaser. Energy
payments are usually indexed to specified variable costs that the purchaser
avoids by purchasing this electric energy from our projects opposed to operating
its own power plants to produce the same amount of electric energy. The variable
components typically include fuel costs and selected operation and maintenance
expenses. These costs may be indexed to the utility's cost of fuel and/or
selected inflation indices. Capacity payments are based on a project's proven
capability to reliably make electric capacity available, whether or not the
project is called to deliver electric energy. Capacity payments compensate a
project for specified fixed costs that are incurred independent of the amount of
energy sold by the project. Such fixed costs include taxes, debt service and
distributions to the project's owners. To receive capacity payments, there are
typically minimum performance standards that must be met, and often there is a
performance range that further influences the amount of capacity payments.
Steam produced from our cogeneration facilities is sold to industrial steam
users, such as petroleum refineries or companies involved in the enhanced
recovery of oil through steam flooding of oil fields, under long-term steam
sales contracts. Steam payments are generally based on formulas that reflect the
cost of water, fuel and capital to us. In some cases, we have provided steam
purchasers with discounts from their previous costs for producing this steam
and/or have partially indexed steam payments to other indices including
specified oil prices.
Sale of Power from Merchant Plants
Over the past two years, we have shifted our primary focus to the acquisition
and operation of competitive generation, both domestically and internationally.
We have recently acquired a number of merchant plants, which sell capacity,
energy and, in some cases, other services on a competitive basis under bilateral
arrangements or through centralized power pools that provide an institutional
framework for price setting, dispatch and settlement procedures.
Electric power generated at the Homer City plant is sold under bilateral
arrangements with domestic utilities and power marketers under short-term
contracts with terms of two years or less, or to the PJM or the NYISO. These
pools have short-term markets, which establish an hourly clearing price. The
Homer City plant is situated in the PJM control area and is physically connected
to high-voltage transmission lines serving both the PJM and NYISO markets. The
Homer City plant can also transmit power to the midwestern United States.
Electric power generated at the Illinois Plants is sold under a power
purchase agreement with Commonwealth Edison, in which Commonwealth Edison will
purchase capacity and have the right to purchase energy generated by the
Illinois Plants. The agreements, which began on December 15, 1999, and have a
term of up to five years, provide for capacity and energy payments.
Commonwealth Edison will be obligated to make a capacity payment for the plants
under contract and an energy payment for the electricity produced by these
plants. The capacity payment will provide the Illinois Plants revenue for fixed
charges, and the energy payment will compensate the Illinois Plants for variable
costs of production. If Commonwealth Edison does not fully dispatch the plants
under contract, the Illinois Plants may sell, subject to specified conditions,
the excess energy at market prices to neighboring utilities, municipalities,
third party electric retailers, large consumers and power marketers on a spot
basis. A bilateral trading infrastructure already exists with access to the
Mid-America Interconnected Network and the East Central Area Reliability
Council.
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Our projects in the United Kingdom sell their electrical energy and capacity
through a centralized electricity pool, which establishes a half-hourly clearing
price, also referred to as the pool price, for electrical energy. The pool
price is extremely volatile and can vary by as much as a factor of ten or more
over the course of a few hours, due to the large differentials in demand
according to the time of day. First Hydro and Ferrybridge and Fiddler's Ferry
mitigate a portion of the market risk of the pool by entering into contracts for
differences, which are electricity rate swap agreements related to either the
selling or purchasing price of power. These contracts specify a price at which
the electricity will be traded, and the parties to the agreement make payments
calculated based on the difference between the price in the contract and the
pool price for the element of power under contract. These contracts are sold in
various structures and act to stabilize revenues or purchasing costs by removing
an element of their net exposure to pool price volatility. See "Regulatory
Matters - Recent Foreign Regulatory Matters."
The Loy Yang B plant sells its electrical energy through a centralized
electricity pool, which provides for a system of generator bidding, central
dispatch and a settlements system based on a clearing market for each half-hour
of every day. The National Electricity Market Management Company, operator and
administrator of the pool, determines a system marginal price each half-hour.
To mitigate exposure to price volatility of the electricity traded into the
pool, the Loy Yang B plant has entered into a number of financial hedges. From
May 8, 1997 to December 31, 2000, approximately 53% to 64% of the plant output
sold 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 Government of Victoria, Australia, between each generator and
each distributor, prior to the privatization of electric power distributors in
order to provide more predictable pricing for those electricity customers that
were unable to choose their electricity retailer. Vesting contracts set base
strike prices at which the electricity will be traded. The parties to the
vesting contracts make payments, which are calculated based on the difference
between the price in the contract and the half-hourly pool clearing price for
the element of power under contract. Vesting contracts are sold in various
structures and are accounted for as electricity rate swap agreements. In
addition, the Loy Yang B plant has entered into a State Hedge agreement with the
State Electricity Commission of Victoria. 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 Government of Victoria, Australia
guarantees the State Electricity Commission of Victoria's obligations under the
State Hedge.
Power Marketing and Trading Activities
When making sales under negotiated contracts, it is our policy to deal with
investment grade parties or companies that provide equivalent credit support.
We hedge a portion of the electric output of our merchant plants in order to
stabilize and enhance the operating revenues from merchant plants. When
appropriate, we manage the "spark spread," or margin, which is the spread
between electric prices and fuel prices and use forward contracts, swaps,
futures, or options contracts to achieve those objectives.
Our power marketing and trading organization is divided into front-, middle-,
and back-office segments, with specified duties segregated for control purposes.
The risk management personnel have a high level of knowledge of utility
operations, fuel procurement, energy marketing and futures and options trading.
We have systems in place which monitor real-time spot and forward pricing and
perform option valuations. We also have a wholesale power scheduling group that
operates on a 24-hour basis.
9
Fuel Supply Contracts
We seek to enter into long-term contracts to mitigate the risks of
fluctuations in prices for coal, oil, gas and fuel transportation. We believe,
however, that our financial condition will not be substantially adversely
affected by these fluctuations for our non-merchant plants because our long-term
contracts to sell power and steam typically are structured so that fluctuations
in fuel costs will produce similar fluctuations in electric energy and/or steam
revenues. The degree of linkage between these revenues and expenses varies from
project to project, but generally permits the projects to operate profitably
under a wide array of potential price scenarios.
Project Financing
Each project we develop requires a substantial capital investment. The
permanent project financing is often arranged immediately prior to the
construction of the project. With limited exceptions, this debt financing is for
approximately 50% to 80% of each project's costs and is structured on a basis
that is non-recourse to us and our other projects. In addition, the collateral
security for each project's financing generally has been limited to the physical
assets, contracts and cash flow of that project and our ownership interests in
that project.
In general, each of our direct or indirect subsidiaries is organized as a
legal entity separate and apart from us and our other subsidiaries. Any asset
of any of these subsidiaries may not be available to satisfy our obligations or
those of any of our other such subsidiaries. However, unrestricted cash or
other assets that are available for distribution by a subsidiary may, subject to
applicable law and the terms of financing arrangements of these subsidiaries, be
advanced, loaned, paid as dividends or otherwise distributed or contributed to
us.
The ability to arrange project financing and the cost of such financing are
dependent upon numerous factors, including general economic and capital market
conditions, the credit attributes of a project, conditions in energy markets,
regulatory developments, credit availability from banks or other lenders,
investor confidence in the industry, Edison Mission Energy and other project
participants, the continued success of our other projects, and provisions of tax
and securities laws that are conducive to raising capital.
Our financial exposure in any project is generally limited by contractual
arrangement to our equity commitment, which is usually about 20% to 50% of our
share of the aggregate project cost. In some cases, we provide additional
credit support to projects in the form of debt service reserves, contingent
equity commitments, revenue shortfall support or other arrangements designed to
provide limited support.
Permits and Approvals
Because the process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated and lengthy, often taking a
year or longer, we seek to obtain all permits, licenses and other approvals
required for the construction and operation of the project, including siting,
construction and environmental permits, rights-of-way and planning approvals
early in the development process for a project. See "Regulatory Matters--
General".
Emission allowances were acquired by Edison Mission Energy as part of the
acquisition of the Illinois Plants and the Homer City plant. Emission
allowances are required by our facilities in order to be certified by the local
environmental authorities and are required to be maintained throughout the
10
period of operation of those facilities located in Pennsylvania and Illinois.
We purchase additional emission allowances when necessary to meet the
environmental regulations. We also use forward sales and purchases, together
with options, to achieve our objective of stabilizing and enhancing the
operations from these merchant plants.
Construction, Operations & Maintenance and Management
In the project implementation stage, we often provide construction
management, start-up and testing services. The detailed engineering and
construction of the projects typically are performed by outside contractors
under fixed-price, turnkey contracts. Under these contracts, the contractor
generally is required to pay liquidated damages to us in the event of cost
overruns, schedule delays or the project's failure to meet specified capacity,
efficiency and emission standards.
As a project goes into operation, operation and maintenance services are
provided to the project by one of our operation and maintenance subsidiaries or
another operation and maintenance contractor. The projects that we operated in
1999 achieved an average 95% availability. Availability is a measure of the
weighted average number of hours each generator is available for generation as a
percentage of the total number of hours in a year.
An executive director generally manages the day-to-day administration of each
project. Management committees comprised of the project's partners generally
meet monthly or quarterly to review and manage the operating performance of the
project.
Risk Factors Associated with Project Development, Finance and Operation
The development projects and acquisitions in which we have invested or in
which we may invest in the future may be large and complex, and we may not be
able to complete the development or acquisition of any of these projects. The
development of a power project may require us to expend significant sums for
preliminary engineering, permitting, legal and other expenses before we can
determine whether we will win a competitive bid, or whether a project is
feasible, economically attractive or financeable. Moreover, access to capital
for future projects is uncertain. We cannot assure you that we will be
successful in structuring the financing for our projects on a substantially non-
recourse basis or that we will obtain sufficient additional equity capital,
project cash flow or additional borrowings to enable us to fund the equity
commitments required for future projects.
Power purchase agreements often enable the utility to terminate these
agreements, or to retain security posted by the developer as liquidated damages,
in the event that a project fails to achieve commercial operation or target
operating levels by specified dates or fails to meet other significant
contractual requirements. In addition, most of our acquisition agreements
permit the seller to terminate the agreement or impose penalties if the
acquisition of the project is not achieved by a specified date. If these events
were to occur, the default provisions in a financing agreement could be
triggered, rendering the project debt immediately due and payable, and, as a
result, we could lose our interest in the project.
A significant portion of the projects in which we have acquired an interest
do not have long-term power purchase agreements. As merchant plants whose
output is not committed to be sold under long-term contracts, these projects are
subject to market forces to determine the amount and price of power that they
sell. We cannot assure you that these plants will be successful in selling
power into their respective markets. If they are unsuccessful, they may not be
able to generate enough cash to service their own debt or to make distributions
to us.
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In addition, some utilities have brought litigation aimed at forcing the
renegotiation or termination of long-term power purchase agreements based upon,
among other things, revised estimates of avoided cost or power demands. We
cannot assure you that in the future utilities that purchase power from our
contract-based power plants or other power purchasers that purchase power under
long-term agreements from us will not seek to terminate their existing
agreements with us.
The global independent power industry is characterized by numerous strong and
capable competitors, some of which may have more extensive operating experience,
more extensive experience in the acquisition and development of power projects,
larger staffs and greater financial resources than we do. Further, in recent
years, power markets have been characterized by strong and increasing
competition as a result of regulatory changes and other factors which have
contributed to a reduction in market prices for power. These regulatory and
other changes may continue to increase competitive pressures in the markets
where we operate. Increased competition for our new project investment
opportunities may adversely affect our ability to develop or acquire projects on
economically favorable terms.
The operation of power generating plants involves many risks, including
start-up problems, the breakdown or failure of equipment or processes,
performance below expected levels of output, the inability to meet expected
efficiency standards, operator error, unpredictable weather conditions and
catastrophic events such as earthquakes, landslides, fires, floods, explosions
or similar calamities. Some geographic areas in which we operate and are
developing projects are subject to frequent earthquakes of low intensity,
although earthquakes of greater intensity are possible. Our existing power
generation facilities are built to withstand earthquakes of relatively
significant intensity. The occurrence of any of these events could
significantly reduce revenues generated by our projects or increase their
generation expenses. Equipment and plant warranties and insurance obtained by
us may not be adequate to cover lost revenues or increased expenses and, as a
result, a project may be unable to fund principal and interest payment under its
financing obligations and may operate at a loss. A default under a financing
obligation could cause us to lose our interest in that project.
Our international projects are subject to political and business risks,
including uncertainties associated with currency exchange rates, currency
repatriation, expropriation, political instability, privatization efforts and
other issues that have the potential to impair these projects from making
dividends or other distributions to us and against which we may not be fully
capable of insuring. In particular, fluctuations in currency exchange rates can
affect, on a U.S. dollar equivalent basis, the amount of our equity
contributions to, and distributions from, our international projects. At times,
we have hedged a portion of our exposure to fluctuations in currency exchange
rates. However, hedge contracts may involve risks, including counterparty
default, and we cannot assure you that fluctuations in currency exchange rates
will be fully offset by these hedges. The economic crisis in Indonesia has
raised concerns over the ability of the state owned electricity company to meet
its obligations under the current power purchase agreement with PT Paiton Energy
as discussed previously in "-- Strategy -- Asia Pacific." Generally, the
uncertainty of the legal structure in foreign countries in which we may develop
or acquire projects could make it more difficult to enforce our rights under
agreements relating to these projects. In addition, the laws and regulations of
some countries may limit our ability to hold a majority interest in some of the
projects that we may develop or acquire.
Our Operating Power Generation Facilities
Domestic Overview
12
We currently own interests in 34 domestic operating projects in ten states.
These operating projects consist of 13 natural gas-fired cogeneration projects,
one coal-fired cogeneration project, seven coal-fired exempt wholesale generator
projects, one waste coal project and 12 gas-fired exempt wholesale generator
projects. All of our domestic cogeneration projects, as well as the waste coal
project, are qualifying facilities under the Public Utility Regulatory Policies
Act. Our domestic operating projects have total generating capacity of 15,003
MW, of which our net ownership share is 13,008 MW.
The primary power sales contracts for four of our operating projects in 1999
and five of our operating projects in 1998 and 1997 are with Southern California
Edison Company. Our share of revenues from these projects accounted for 8% in
1999 and 12% in 1998 and 1997 of our consolidated revenues. The failure of
Southern California Edison Company to fulfill its contractual obligations could
have a negative impact on a source of our revenues. Under the terms of an
agreement between Southern California Edison Company and the Office of Ratepayer
Advocates, the consumer advocacy branch of the California Public Utilities
Commission, Southern California Edison Company is prohibited from entering into
future power sales contracts with us or our affiliates without Office of
Ratepayer Advocates and the California Public Utilities Commission consent. The
terms of the agreement, however, do not affect the terms of the existing power
sales contracts between us and Southern California Edison Company. Fuel supply
for our projects generally is arranged through third-party suppliers and
transporters.
In September 1998, the California Public Utilities Commission issued an order
which approved an agreement entered into between an operating cogeneration
project in which we have a 30% partnership interest and Southern California
Edison Company to terminate a power sales agreement. The termination agreement
became effective in February 1999. This will result in a slight negative impact
on our future revenues.
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Description of Domestic Operating Projects
We have ownership interests in the following domestic operating projects:
Electric Operation/
Capacity Primary Electric Ownership Acquisition
Project Location (in MW) Purchaser(3) Type of Facility (4) Interest Date
- -------- -------- --------- --------------- -------------------- ------------- -----------
American West Virginia 80 MPC Waste Coal 50% 1993
Bituminous(1)
Auburndale(1) Florida 150 FPC Cogeneration/EWG 50% 1994
Bayonne New Jersey 165 JCP&L/PSE&G Cogeneration 0.38% 1989
Brooklyn Navy New York 286 CE Cogeneration/EWG 50% 1996
Yard
Coalinga(1) California 38 PG&E Cogeneration 50% 1991
Commonwealth Virginia 340 VEPCO EWG 50% 1992
Atlantic
Gordonsville(1) Virginia 240 VEPCO Cogeneration/EWG 50% 1994
Harbor(6) California 80 Pool EWG 30% 1989
Homer City(2) Pennsylvania 1,884 Pool EWG 100% 1999
Hopewell Virginia 356 VEPCO Cogeneration 25% 1990
Illinois Illinois 9,510 ComEd EWG 100%(5) 1999
Plants(2)
(12 projects)
James River Virginia 110 VEPCO Cogeneration 50% 1987
Kern River(1) California 300 SCE Cogeneration 50% 1985
March Point 1 Washington 80 PSE Cogeneration 50% 1991
March Point 2 Washington 60 PSE Cogeneration 50% 1993
Mid-Set(1) California 38 PG&E Cogeneration 50% 1989
Midway-Sunset(1) California 225 SCE Cogeneration 50% 1989
Nevada Sun-Peak Nevada 210 SPR EWG 50% 1991
Saguaro(1) Nevada 90 SPR Cogeneration 50% 1991
Salinas River(1) California 38 PG&E Cogeneration 50% 1991
Sargent Canyon(1) California 38 PG&E Cogeneration 50% 1991
Sycamore(1) California 300 SCE Cogeneration 50% 1988
Watson California 385 SCE Cogeneration 49% 1988
(1) Operated by Edison Mission Operation & Maintenance, an indirect, wholly
owned affiliate of Edison Mission Energy.
(2) Operated by Midwest Generation, LLC, an indirect, wholly owned affiliate of
Edison Mission Energy.
(3) Electric purchaser abbreviations are as follows:
CE Consolidated Edison Company of PG&E Pacific Gas & Electric
New York, Inc. Company
ComEd Commonwealth Edison Company PSE Puget Sound Energy, Inc.
FPC Florida Power Corporation PSE&G Public Service Electric &
Gas Company
JCP&L Jersey Central Power & Light SCE Southern California
Company Edison Company
MPC Monongahela Power Company SPR Sierra Pacific Resources
Pool Regional electricity trading VEPCO Virginia Electric & Power
market Company
(4) All of the cogeneration projects are gas-fired facilities, except for the
James River project, which uses coal. All of the exempt wholesale generator
(EWG) projects are gas-fired facilities, except for the Homer City plant and
six of the Illinois Plants, which use coal.
(5) We own 6,812 MW of the Illinois Plants and lease the remaining 2,698 MW
under a 33.75 year lease entered into by us in December 1999.
(6) Operation of the plant ceased in September 1999 resulting from the
termination of the power sales agreement.
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International Overview
We own interests in 38 operating projects outside the United States. The
total generating capacity of these facilities is 11,646 MW, of which our net
ownership share is 9,048 MW.
Description of International Operating Projects
We have ownership interests in the following international operating
projects:
Electric Operation/
Capacity Primary Electric Ownership Acquisition
Project Location (in MW) Purchaser(2) Interest Date
- ------- -------- ----------- ----------------- ----------- ---------------
Contact (10 projects) New Zealand(6) 2,626 Pool 40% 1999, 2000
Derwent(1) England 214 SE(3) 33% 1995
Dinorwig(1) Wales 1,728 Pool 100% 1995
Doga(1) Turkey 180 TEAS 80% 1999
Ferrybridge(1) England 1,960 Pool 100% 1999
Ffestiniog(1) Wales 360 Pool 100% 1995
Fiddler's Ferry(1) England 1,926 Pool 100% 1999
Iberian Hy-Power I(1) Spain 43 FECSA 100%(7) 1992, 1996
(5 projects)
Iberian Hy-Power II(1) Spain 43 FECSA 100% 1993, 1996
(13 projects)
Kwinana(1) Australia 116 WP 100% 1996
Loy Yang B (1) Australia 1,000 Pool(4) 100% 1993, 1996,
1997
Paiton(1) Indonesia 1,230 PLN 40% 1999
Roosecote England 220 NORWEB(5) 100% 1992, 1999
(1) Operated by an Edison Mission Energy international operating affiliate.
(2) Electric purchaser abbreviations are as follows:
FECSA Fuerzas Electricas de Cataluma, S.A. PLN PT Perusahaan Listrik Negara
NORWEB North Western Electricity Board SE Southern Electric plc.
WP Western Power TEAS Turkiye Elektrik Urehm A.S.
Pool Electricity trading market for England,
Wales, Australia and New Zealand
(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.
(6) Minority interest in one project in Australia.
(7) Minority interests are owned by third parties in three of the projects.
Oil and Gas Investments
In 1988, we formed a wholly-owned subsidiary, Mission Energy Fuel Company, to
develop and invest in fuel interests. Since that time, Mission Energy Fuel
Company 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, 1999, we owned 35% of the stock of Four Star Oil & Gas
Company, a subsidiary of Texaco Inc. The underlying value of Four Star is
attributable to production of oil and gas
15
from nine producing properties. Our proportionate interest in net quantities of
proved reserves at December 31, 1999 totaled 173.5 billion cubic feet of natural
gas and 11.4 million barrels of oil.
In November 1999, we completed the sale of a portion of our interest in Four
Star to a company in which we hold a 50% interest. Net proceeds from the sale
of a portion of this investment were $20.5 million. We recorded an after-tax
gain on the sale of our investment of approximately $30 million. Our net
ownership interest in Four Star was reduced from 50% at December 31, 1998, to
34% as a result of the transaction. During December 1999, we purchased
additional shares of stock of Four Star, increasing our ownership to 34.88%.
Competition
We compete with many other companies, including multinational development
groups, equipment suppliers and other independent power producers, including
affiliates of utilities, in selling electric power and steam. We also compete
with electric utilities in obtaining the right to install new generating
capacity. Over the past decade, obtaining a power sales contract with a utility
has generally become a progressively more difficult, expensive and competitive
process. Many power sales contracts are now awarded by competitive bidding,
which both increases the costs of obtaining these contracts and decreases the
chances of obtaining these contracts. We evaluate each potential project in an
effort to determine when the probability of success is high enough to justify
expenditures in developing a proposal or bid for the project.
Amendments to the Public Utility Holding Company Act of 1935 made by the
Energy Policy Act have increased the number of competitors in the domestic
independent power industry by reducing restrictions applicable to projects that
are not qualifying facilities under the Public Utility Regulatory Policies Act.
Retail wheeling of power, which is the offering by utilities of unbundled retail
distribution service, could also lead to increased competition in the
independent power market. See "Regulatory Matters--Retail Competition".
Tax Sharing Agreements
We are included in the consolidated federal income tax and combined state
franchise tax returns of Edison International. We calculate our income tax
provision on a separate company basis under a tax sharing arrangement with The
Mission Group, which in turn has an agreement with Edison International. Tax
benefits generated by us and used in the Edison International consolidated tax
return are recognized by us without regard to separate company limitations.
Seasonality
Due to warmer weather during the summer months, electric revenues generated
from the Homer City plant and the Illinois Plants are usually higher during the
third quarter of each year. In addition, our third quarter revenues from energy
projects are materially higher than other quarters of the year due to a
significant number of our domestic energy projects located on the West Coast,
which generally have power sales contracts that provide for higher payments
during summer months. The First Hydro plants, Ferrybridge and Fiddler's Ferry
plants and the Iberian Hy-Power plants provide for higher electric revenues
during the winter months.
Employees and Offices
At December 31, 1999, we employed 3,245 people, all of whom were full-time
employees and approximately 636, 146 and 1,179 of whom were covered by
collective bargaining agreements in the
16
United Kingdom, Australia and the United States, respectively. We have never
experienced a work stoppage, strike or labor dispute. We believe we have good
relations with our employees.
We lease our corporate headquarters in Irvine, California and our principal
regional offices in London, Melbourne and Singapore. We also lease other
smaller offices in the United States and certain foreign countries.
Regulatory Matters
- ------------------
General
Our operations are subject to extensive regulation by governmental agencies
in each of the countries in which we conduct operations. Our domestic projects
are subject to energy, environmental and other governmental laws and regulations
at the federal, state and local levels in connection with the development,
ownership and operation of, and use of electric energy, capacity and related
products, including ancillary services from, our projects. Federal laws and
regulations govern, among other things, transactions by and with purchasers of
power, including utility companies, the operations of a project and the
ownership of a project. Under limited circumstances where exclusive federal
jurisdiction is not applicable or specific exemptions or waivers from state or
federal laws or regulations are otherwise unavailable, federal and/or state
utility regulatory commissions may have broad jurisdiction over non-utility
owned electric power plants. Energy-producing projects are also subject to
federal, state and local laws and regulations that govern the geographical
location, zoning, land use and operation of a project. Federal, state and local
environmental requirements generally require that a wide variety of permits and
other approvals be obtained before the commencement of construction or operation
of an energy-producing facility and that the facility then operate in compliance
with these permits and approvals. While we believe the requisite approvals for
our existing projects have been obtained and that our business is operated in
substantial compliance with applicable laws, we remain subject to a varied and
complex body of laws and regulations that both public officials and private
parties may seek to enforce. Regulatory compliance for the construction of new
facilities is a costly and time consuming process. Intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures and may create a significant risk of expensive delays or
significant loss of value in a project if the project is unable to function as
planned due to changing requirements or local opposition.
Each of our international projects is subject to the energy and environmental
laws and regulations of the foreign country in which this project is located.
The degree of regulation varies according to each country and may be materially
different from the regulatory regime in the United States.
U.S. Federal Energy Regulation
The enactment of the Public Utility Regulatory Policies Act of 1978 and the
adoption of regulations under this act by the Federal Energy Regulatory
Commission provided incentives for the development of cogeneration facilities
and small power production facilities utilizing alternative or renewable fuels.
The passage of the Energy Policy Act in 1992 further encouraged independent
power production by providing limited exemptions from the Public Utility Holding
Company Act of 1935, but not from the Federal Power Act, or state regulation,
for exempt wholesale generators and foreign utility companies.
A domestic electricity generating project must be a qualifying facility under
the Federal Energy Regulatory Commission regulations in order to take advantage
of selected rate and regulatory incentives provided by the Public Utility
Regulatory Policies Act. Subject to limited exceptions, the Public Utility
17
Regulatory Policies Act exempts owners of qualifying facilities from the Public
Utility Holding Company Act, exempts qualifying facilities from most provisions
of the Federal Power Act and exempts qualifying facilities from most provisions
of state laws concerning rate, financial or organizational regulation, except
under limited circumstances. In order to be a qualifying facility, a
cogeneration facility must (i) sequentially produce both useful thermal, such as
steam, and electric energy, (ii) meet specified operating standards, and energy
efficiency standards when oil or natural gas is used as a fuel source and (iii)
not be controlled, or more than 50% owned by, an electric utility, an electric
utility holding company or an affiliate of these entities. A number of non-
cogeneration facilities may also be qualifying facilities if they produce power
from renewable energy, such as geothermal energy, or a waste source of fuel,
such as waste coal, and meet the ownership restrictions discussed above. Before
1990, non-cogeneration qualifying facilities 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 qualifying facilities, provided that
applications for or notices of qualifying facility status were filed with the
Federal Energy Regulatory Commission for these facilities on or before December
31, 1994, and provided, in the case of new facilities, the construction of these
facilities commenced on or before December 31, 1999.
Amendments made to the Public Utility Holding Company Act by the Energy
Policy Act provide that owners or operators of exempt wholesale generators and
foreign utility companies will not be considered electric utility companies, and
upstream owners will not be considered holding companies under the Public
Utility Holding Company Act. An exempt wholesale generator is an entity
determined by the Federal Energy Regulatory Commission to be exclusively
engaged, directly or indirectly, in the business of owning and/or operating
specified eligible facilities and selling electric energy at wholesale, or, if
located in a foreign country, at wholesale or retail. A foreign utility company
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.
Under present federal law, we are not and will not be subject to regulation
as a holding company under the Public Utility Holding Company Act as long as
the projects in which we have an interest are qualifying facilities, exempt
wholesale generators, or foreign utility companies or are subject to another
exemption from regulation. See "Public Utility Holding Company Act."
Public Utility Regulatory Policies Act of 1978
The Public Utility Regulatory Policies Act provides two primary benefits to
qualifying facilities. First, qualifying facilities 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, the
Federal Energy Regulatory Commission regulations promulgated under the Public
Utility Regulatory Policies Act require that electric utilities purchase
electricity generated by qualifying facilities at a price based on the
purchasing utility's avoided cost, and that the utilities sell back-up power to
the qualifying facility on a non-discriminatory basis. The term "avoided cost"
is defined by the Federal Energy Regulatory Commission regulations 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, this utility would generate itself or purchase from another source.
The Federal Energy Regulatory Commission regulations also permit qualifying
facilities and utilities to negotiate agreements for utility purchases of power
at prices different than the utility's avoided costs. While public utilities
are not explicitly required by the Public Utility Regulatory Policies Act 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
18
financing of independent power facilities and to reflect the deferral by the
utility of capital costs for new plant additions. However, increasing
competition and the development of new power markets have resulted in a trend
toward shorter term power contracts that would place greater risk on the project
owner.
We endeavor to develop our qualifying facility projects, monitor regulatory
compliance by these projects and choose our customers in a manner that minimizes
the risks of losing these projects' qualifying facility status. However, some
factors necessary to maintain qualifying facility status are subject to risks of
events outside of our control. For example, loss of a thermal energy customer
or failure of a thermal energy customer to take required amounts of thermal
energy from a cogeneration facility that is a qualifying facility could cause
this facility to fail requirements regarding the level of useful thermal energy
output. Upon the occurrence of this event, we would seek to replace the thermal
energy customer or find another use for the thermal energy that meets Public
Utility Regulatory Policies Act's requirements.
If one of the projects in which we have an interest were to lose its status
as a qualifying facility, the project would no longer be entitled to the
qualifying facility-related exemptions from regulation under the Public Utility
Holding Company Act and the Federal Power Act. This could subject the project
to rate regulation as a public utility under the Federal Power Act and could
result in Edison Mission Energy 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 the Public Utility Holding Company
Act. Loss of qualifying facility status may also trigger defaults under
covenants to maintain qualifying facility status in the project's power sales
agreements, steam sales agreements and financing agreements and result in
termination, penalties or acceleration of indebtedness under such agreements.
This loss of qualifying facility 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 qualifying facility
status, we cannot assure you that the costs incurred in connection with the
project could be recovered through sales to other purchasers. Moreover, our
business and financial condition could be adversely affected if regulations or
legislation were modified or enacted that changed the standards for maintaining
qualifying facility status or that eliminated or reduced the benefits and
exemptions currently enjoyed by qualifying facilities. If a project were to
lose its qualifying facility status, we could attempt to avoid holding company
status on a prospective basis by qualifying the project as an exempt wholesale
generator. However, assuming this changed status would be permissible under
the terms of the applicable power sales agreement, rate approval from the
Federal Energy Regulatory Commission would be required. In addition, the
project would be required to cease selling electricity to any retail customers,
in order to qualify for exempt wholesale generator status, and could become
subject to additional state regulation. Loss of qualifying facility status on a
retroactive basis could lead to, among other things, fines and penalties being
levied against us, or claims by the utility customer for refund of payments
previously made. Loss of qualifying facility status by one project could also,
because of the Public Utility Regulatory Policies Act ownership restrictions,
adversely affect the qualifying facility status of other projects having one or
more of the same partners. In addition, under Section 26(b) of the Public
Utility Holding Company Act, any project contracts that are entered into in
violation of the Public Utility Holding Company Act may be determined by the
courts or the SEC to be void.
The Energy Policy Act
The passage of the Energy Policy Act in 1992 significantly expanded the
options available to independent power producers with respect to their
regulatory status. The Energy Policy Act created a new class of power producer,
the exempt wholesale generator, that, like a qualifying facility, is not
considered an electric utility company under the Public Utility Holding Company
Act. Exempt
19
wholesale generators may own facilities of any size, use any fuel source and may
be owned by utilities or non-utilities. Thus, in addition to qualifying facility
status, independent power producers now can also apply to the Federal Energy
Regulatory Commission to be granted status as an exempt wholesale generator.
Exempt wholesale generators, however, are not exempt from regulation by the
Federal Energy Regulatory Commission or state public utility commissions. The
effect of these amendments is to enhance the development of non-qualifying
facilities that do not have to meet the fuel, production and ownership
requirements of the Public Utility Regulatory Policies Act. We believe that the
amendments benefit us by expanding our ability to own and operate facilities
that do not qualify for qualifying facility status, but also result in increased
competition because utilities and other companies, such as equipment suppliers,
may now develop facilities that are not subject to the constraints of the Public
Utility Holding Company Act. The Energy Policy Act also expanded the Federal
Energy Regulatory Commission's authority to order utilities to grant
transmission access to qualifying facilities and exempt wholesale generators and
lifted restrictions on ownership of foreign utilities by U.S. companies. Under
the Energy Policy Act, foreign utility companies are also not electric utility
companies under the Public Utility Holding Company Act.
Public Utility Holding Company Act of 1935
Under the Public Utility Holding Company Act, 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 SEC and regulation under the Public Utility Holding
Company Act, 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 the Public Utility Holding Company Act 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 registered holding company or its subsidiaries.
As noted above, however, regulations have been adopted under the Public
Utility Regulatory Policies Act and the Energy Policy Act providing that
qualifying facilities, exempt wholesale generators and foreign utility
companies are not public utility companies under the Public Utility Holding
Company Act. Accordingly, we are not regulated as a holding company under the
Public Utility Holding Company Act because the power generation facilities we
own or in which we have investments are either qualifying facilities, exempt
wholesale generators or foreign utility companies. All international projects
and specified U.S. projects that we are currently developing or proposing to
acquire will be non-qualifying facility independent power projects. We intend
for each project to qualify as an exempt wholesale generator or as a foreign
utility company. Loss of exempt wholesale generator or foreign utility company
status, like loss of qualifying facility status, could also result in Edison
Mission Energy becoming subject to registration and regulation as a public
utility holding company under the Public Utility Holding Company Act and could
trigger defaults under covenants in project agreements. Loss of exempt
wholesale generator or foreign utility company status on a retroactive basis
could lead to, among other things, fines and penalties and could cause specified
project and other contracts to be void.
Natural Gas Act
Twenty-five of the domestic operating facilities that we own, operate or have
investments in are fueled by natural gas. Under the Natural Gas Act, the
Federal Energy Regulatory Commission 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
20
can be obtained on a self-implementing basis. However, pipeline rates for such
services are subject to continuing Federal Energy Regulatory Commission
oversight. Order No. 636, issued by the Federal Energy Regulatory Commission in
April 1992, and affirmed in Orders 636A and 636B issued, respectively, in August
and November 1992, required 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 these services. The restructuring required by the rule
included (i) the separation of a pipeline's sales, transportation and storage
services, (ii) the prohibition against pipelines engaging in sales of gas, (iii)
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, (iv) 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 (v) the opportunity for pipelines to recover
100% of their prudently incurred costs associated with implementing the
restructuring mandated by this rule.
Federal Power Act
The Federal Power Act grants the Federal Energy Regulatory Commission
exclusive ratemaking jurisdiction over wholesale sales of electricity in
interstate commerce, including ongoing, as well as initial, rate jurisdiction.
This jurisdiction enables the Federal Energy Regulatory Commission to revoke or
modify previously approved rates. These rates may be based on a cost-of-service
approach or may, in competitive markets, be market-based. While qualifying
facilities under the Public Utility Regulatory Policies Act generally are exempt
from the ratemaking and some other provisions of the Federal Power Act, exempt
wholesale generators and other non-qualifying facility independent power
projects are subject to the Federal Power Act and to Federal Energy Regulatory
Commission ratemaking jurisdiction, which may limit their flexibility in
negotiations with power purchasers. However, since these projects are not bound
by the Public Utility Regulatory Policies Act's thermal energy use requirement,
they have greater latitude in site selection and facility size. In addition, as
noted above, we may own 100% of exempt wholesale generators. In addition, the
Federal Power Act grants the Federal Energy Regulatory Commission jurisdiction
over the sale or transfer of jurisdictional facilities, including wholesale
power sales contracts, and in some cases, jurisdiction over the issuance of
securities or the assumption of specified liabilities.
Currently, six of our operating project companies, owning the Homer City
plant, the Illinois Plants, the Nevada Sun-Peak, Brooklyn Navy Yard,
Commonwealth Atlantic and Harbor facilities, are subject to the Federal Energy
Regulatory Commission rate making regulation under the Federal Power Act.
State Energy Regulation
State public utility commissions have broad jurisdiction over non-qualifying
facility independent power projects, including exempt wholesale generators,
which are considered public utilities in many states. This jurisdiction often
includes the issuance of certificates of public convenience and necessity and/or
other certifications to construct, own and operate a facility, as well as
regulation of organizational, accounting, financial and other corporate matters
on an ongoing basis. Qualifying facilities may also be required to obtain these
certificates in some states. Several states that have restructured their
electric industries require generators to register to provide electric service
to customers. Many states are currently undergoing significant changes in their
electric statutory and regulatory frameworks that result from restructuring the
electric industries that may affect generators in those states. Although the
Federal Energy Regulatory Commission generally has exclusive jurisdiction over
the rates charged by a non-qualifying facility independent power project to its
wholesale customers, a state's public utility commission has the ability, in
practice, to influence the establishment of these rates by asserting
jurisdiction over the purchasing utility's ability to pass through the resulting
21
cost of purchased power to its retail customers. A state's public utility
commission also has the authority to determine avoided costs for qualifying
facilities and regulate the retail rates charged by qualifying facilities. In
addition, states may assert jurisdiction over the siting and construction of
independent power projects and, among other things, the issuance of securities,
related party transactions and the sale or other transfer of assets by these
facilities. The actual scope of jurisdiction over independent power projects by
state public utility commissions varies from state to state.
In addition, state public utility commissions may seek to modify, suspend or
terminate a qualifying facility's power sales contract under limited
circumstances. This could occur if the state public utility commission
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 this instance, the state public utility commission may
attempt to alter the terms of the power sales contract to reflect more
accurately market conditions for the prevailing cost of power. While we believe
that these attempts are not common and that the state public utility commission
may not have any authority to modify the terms of the wholesale power sales, we
cannot assure you that the power sales contracts of our projects will not be
subject to adverse regulatory actions.
The California Public Utilities Commission has authorized the electric
utilities in California to monitor compliance by qualifying facilities with the
Public Utility Regulatory Policies Act rules and regulations. However, the
United States Court of Appeals for the Ninth Circuit found in 1994 that a
California Public Utilities Commission program was preempted by the Public
Utility Regulatory Policies Act, to the extent it authorized utilities to
determine that a qualifying facility was not in compliance with the Public
Utility Regulatory Policies Act rules and regulations, to then pay a reduced
avoided cost rate and to take other action contrary to a facility's status as a
qualifying facility. The court did, however, uphold reasonable monitoring of
qualifying facility operating data. Other states, like New York and Virginia,
have also instituted qualifying facility monitoring programs.
We buy and transport the natural gas used at our domestic facilities through
local distribution companies. State public utility commissions have
jurisdiction over the transportation of natural gas by local distribution
companies. Each state's regulatory laws are somewhat different; however, all
generally require the local distribution companies to obtain approval from the
relevant public utility commission for the construction of facilities and
transportation services if the local distribution company's generally applicable
tariffs do not cover the proposed transaction. Local distribution companies
rates are usually subject to continuing public utility commission oversight.
Recent Foreign Regulatory Matters
United Kingdom
In July 1998, the UK Director General of Electricity Supply proposed to the
Minister for Science, Energy and Industry that the current structure of
contracts for differences and compulsory trading via the pool at half-hourly
clearing prices bid a day ahead be abolished. The UK Government accepted the
proposals in October 1998 subject to certain reservations. Following this,
further proposals were published by the Regulator in July and October 1999. The
proposals include, among other things, the establishment of voluntary long-term
forwards and futures markets, organized by independent market operators and
evolving in response to demand; voluntary short-term power exchanges operating
from 24 to 4-hours before a trading period; a balancing mechanism to enable the
system operator to balance generation and demand and resolve any transmission
constraints; a mandatory settlement process for recovering imbalances between
contracted and metered volumes with stronger incentives for being in balance;
and a Balancing and Settlement Code Panel to oversee governance of the balancing
mechanism. The Minister for Science, Energy and Industry has recommended that
the proposal be
22
implemented by the end of October 2000. It is difficult at this stage to
evaluate the future impact of the proposals. However, a key feature of the new
trading arrangements is to move to firm physical delivery which means that a
generator must deliver, and a consumer take delivery, against their contracted
positions or face the uncertain consequences of the system operator buying or
selling in the balancing market, on their behalf, and passing the costs back to
them. A consequence of this will be to increase greatly the motivation of
parties to contract in advance. Recent experience has been that this has placed
a significant downward pressure on forward contract prices. Legislation in the
form of a Utilities Bill, published on January 20, 2000, is being introduced to
allow for the implementation of new trading arrangements and the necessary
amendments to generators' licenses. The introduction of the new electricity
trading arrangements coupled with uncertainties surrounding the new Utilities
Bill and a proposed "good behavior" clause, discussed below, and an unseasonably
warm winter have contributed to a drop in electricity market prices in the first
quarter of 2000 and a drop of approximately 20% in the forward electricity price
curve for the remainder of the year. As a result of these events, we expect
lower than anticipated revenue from our Ferrybridge and Fiddler's Ferry plants.
The Utilities Bill is scheduled to become law by July 2000. The core of the
proposals is a fair deal for consumers through the provision of proper
incentives to innovate and improve efficiency, growth of competition, protection
for consumers and contribution of the utilities of a better environment. While
the UK Government recognizes the need to strike a balance between consumer and
shareholder interest, the proposals have far reaching implications for the
utilities sector. In December 1999, the UK Director General of Electricity
Supply gave notice of an intention to introduce a new condition into the
licenses of a number of generators to curb the perceived exercise of market
power in the determination of wholesale electricity prices. The majority of the
major generators have accepted the new clauses, including Edison Mission Energy,
which has sought and received specific assurances from the Regulator on the
definition of market abuse and the way the clauses will be interpreted in the
future.
New Zealand
The New Zealand Government has been undergoing a steady process of electric
industry deregulation since 1987. Reform in the distribution and retail supply
sector began in 1992 with legislation that deregulated electricity distribution
and provided for competition in the retail electric supply function. The New
Zealand Energy Market, established in 1996, is a voluntary competitive wholesale
market which allows for the trading of physical electricity on a half-hourly
basis. The Electricity Industry Reform Act, which was passed in July 1998, was
designed to increase competition at the wholesale generation level by splitting
up Electricity Company of New Zealand Limited, the large state-owned generator,
into three separate generation companies. The Electricity Industry Reform Act
also prohibits the ownership of both generation and distribution assets by the
same entity.
The New Zealand Government announced in February 2000 an Inquiry into the
electricity industry. This Inquiry is aimed at assessing present regulatory
policy of the government to ensure price competition to the retail customers.
The Inquiry panel is expected to report its findings in mid-June 2000, and the
Government will then determine whether new legislation is required. The main
focus of the Inquiry has been on the monopoly segments of the industry,
transmission and distribution.
Transmission of Wholesale Power
Generally, projects that sell power to wholesale purchasers other than the
local utility to which the project is interconnected require the transmission of
electricity over power lines owned by others, which is called wheeling. The
prices and other terms and conditions of transmission contracts are regulated by
the Federal Energy Regulatory Commission, when the entity providing the wheeling
service is a jurisdictional public utility under the Federal Power Act. Until
1992, the Federal Energy Regulatory
23
Commission's ability to compel wheeling was very limited, and the availability
of voluntary wheeling service could be a significant factor in determining
whether a site was viable for project development.
The Federal Energy Regulatory Commission's authority under the Federal Power
Act to require electric utilities to provide transmission service on a case by
case basis to qualifying facilities, exempt wholesale generators, and other
power generators was expanded substantially by the Energy Policy Act.
Furthermore, in 1996 the Federal Energy Regulatory Commission issued a
rulemaking order, Order 888, in which the Federal Energy Regulatory Commission
asserted the power, under its authority to eliminate undue discrimination in
transmission, to compel all jurisdictional public utilities under the Federal
Power Act to file open access transmission tariffs consistent with a pro forma
tariff drafted by the Federal Energy Regulatory Commission. The Federal Energy
Regulatory Commission subsequently issued Orders 888-A, 888-B and 888-C to
clarify the terms that jurisdictional transmitting utilities are required to
include in their open access transmission tariffs. The Federal Energy
Regulatory Commission also issued Order 889, which required those transmitting
utilities to abide by specified standards of conduct when using their own
transmission systems to make wholesale sales of power, and to post specified
transmission information, including information about transmission requests and
availability, on a publicly available computer bulletin board. Although the pro
forma tariff does not cover the pricing of transmission service, Order 888 is
expected to improve transmission access for independent power producers like us.
A recent decision by the United States Court of Appeals for the Eighth Circuit
has cast doubt on the extent of the Federal Energy Regulatory Commission's
authority to require specified curtailment policies in the pro forma tariff.
Retail Competition
In response to pressure from retail electric customers, particularly large
industrial users, the state commissions or state legislatures of most states are
considering, or have considered, whether to open the retail electric power
market to competition. Retail competition is possible when a customer's local
utility agrees, or is required, to unbundle its distribution service from its
transmission and generation service and deliver to the homes and businesses of
retail customers power that is sold to them by another company. Several state
commissions and legislatures have issued orders or passed legislation requiring
utilities to offer unbundled retail distribution service, which is called retail
wheeling, beginning as early as 1998 and phasing in retail wheeling over the
next several years. Other states are expected to move toward retail competition
in 2000.
The competitive pricing environment that will result from retail competition
may cause utilities to experience revenue shortfalls and deteriorating
creditworthiness. However, we expect that most, if not all, state plans will
insure that utilities receive sufficient revenues, through a distribution
surcharge if necessary, to pay their obligations under existing long-term power
purchase contracts with qualifying facilities and exempt wholesale generators.
On the other hand, qualifying facilities and exempt wholesale generators may be
subject to pressure to lower their contract prices in an effort to reduce the
stranded investment costs of their utility customers.
We believe that, as a predominately low cost producer of electricity, we will
ultimately benefit from any increased competition that may arise from the
opening of the retail market. Although our exempt wholesale generators are
forbidden under the Public Utility Holding Company Act from selling electric
power in the retail market, our exempt wholesale generators can sell at
wholesale to a power marketer which resells at retail. Furthermore, some
qualifying facilities may 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. We also believe we will be an
attractive wholesale supplier to power marketers serving the newly-open retail
markets.
24
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. We believe that, as of the filing date of this report, we are in
substantial compliance with environmental regulatory requirements and that
maintaining compliance with current requirements will not materially affect our
financial condition or results of operations. However, possible future
developments, like more stringent environmental laws and regulations, could
affect the costs and the manner in which we conduct our business. We cannot
assure you that in this event we would be able to recover these increased costs
from our customers or that our financial position and results of operations
would not be materially adversely affected.
Typically, environmental laws require a lengthy and complex process for
obtaining licenses, permits and approvals prior to construction and operation of
a project. Meeting all 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.
The Clean Air Act provides the statutory framework to implement a program for
achieving national ambient air quality standards in areas exceeding such
standards and provides for maintenance of air quality in areas already meeting
such standards. Among other requirements, it also restricts the emission of
toxic air contaminants and provides for the reduction of sulfur dioxide
emissions to address acid deposition. For example, we spent $77 million in 1999
and expect to spend approximately $139 million for 2000 and $42 million in 2001
to install upgrades to the environmental controls at the Homer City plant to
control sulfur dioxide and nitrogen oxide emissions. Similarly, we plan to
upgrade the environmental controls at the Illinois Plants to control nitrogen
oxide emissions and expect to spend approximately $54 million, $45 million and
$80 million for 2000, 2001 and 2002, respectively. Provisions related to
nonattainment, air toxins, permitting of new and existing units, enforcement and
acid rain may affect our domestic plants; however, final details of all these
programs have not been issued by the United States Environmental Protection
Agency and state agencies. In addition, at the Ferrybridge and Fiddler's Ferry
plants, we expect to incur environmental costs arising from plant modification,
totaling approximately $222 million for the 2000-2004 period.
The Comprehensive Environmental Response, Compensation, and Liability Act
requires the cleanup of sites from which there has been a release or threatened
release of hazardous substances. As of the filing date of this report, we are
not aware of any liability under this act; however, we cannot assure you that we
will not incur such liability in the future.
Foreign and Domestic Operations
- -------------------------------
A summary of our operations by geographic area including operating revenues,
net income (loss) and identifiable assets is incorporated herein by reference
from Note 16. Business Segments of Notes to the Consolidated Financial
Statements.
25
ITEM 2. PROPERTIES
We lease our principal office in Irvine, California. This lease is
approximately 142,000 square feet contained on eight floors. The term of the
lease for approximately 65,500 square feet expires on December 31, 2004 with two
five-year options to extend. The term of the lease for the balance of
approximately 76,500 square feet expires on December 31, 2004 with no options to
extend. We also lease office space in Chicago, Illinois, Chantilly, Virginia,
Fairfax, Virginia and Washington, D.C. The Chicago lease is approximately
41,000 square feet and expires on December 31, 2009. The Chantilly lease is
approximately 30,000 square feet and expires on October 31, 2009. Both the
Fairfax and the Washington, D.C. leases are immaterial. Our subsidiaries in the
Asia Pacific region lease office space in Manila, Philippines; Melbourne,
Australia; Jakarta, Indonesia; and Singapore. Our subsidiaries in the Europe,
Central Asia, Middle East and Africa region lease office space in Barcelona,
Spain; Esenyurt, Turkey; London, England; and Rome, Italy. These subsidiary
leases are immaterial.
The following table shows the material properties owned or leased by us. Each
property represents at least five percent of our income before tax or is one in
which we have an investment balance greater than $50 million. All of these
properties are subject to mortgages or other liens or encumbrances granted to
the lenders providing financing for the plant or project.
Description of Properties
Business Interest
Plant or Project Segment Location In Land Plant Description
- ---------------- -------- -------- ------- -----------------
Brooklyn Navy Yard Americas Brooklyn, New York Leased Natural gas-turbine cogeneration facility
EcoElectrica Americas Penuelas, Puerto Rico Owned Liquefied natural gas cogeneration facility
Ferrybridge Europe Knottingley, West Leased Coal-fired generation facility
Yorkshire, UK
Fiddler's Ferry Europe Warrington, Cheshire, Leased Coal-fired generation facility
UK
First Hydro Europe Dinorwig, Wales Owned Pumped-storage electric power facility
First Hydro Europe Ffestiniog, Wales Owned Pumped-storage electric power facility
Homer City Americas Pittsburgh, Owned Coal-fired generation facility
Pennsylvania
Gordonsville Americas Gordonsville, Virginia Leased Natural gas-turbine cogeneration facility
Illinois Plants Americas Northeast Illinois Owned/ Coal, oil/gas-fired generation facilities
Leased
James River Americas Hopewell, Virginia Leased Coal-fired generation facility
Kern River Americas Oildale, California Leased Natural gas-turbine cogeneration facility
Kwinana Asia Perth, Australia Leased Natural gas-turbine cogeneration facility
Pacific
Loy Yang B Asia Victoria, Australia Owned Coal-fired generation facility
Pacific
March Point 1&2 Americas Anacortes, Washington Leased Natural gas-turbine cogeneration facility
Midway-Sunset Americas Fellows, California Leased Natural gas-turbine cogeneration facility
Paiton Asia East Java, Indonesia Leased Coal-fired generation facility
Pacific
Roosecote Europe Barrow-in-Furness, Owned Combined cycle generation technology
Cumbria, UK
Saguaro Americas Henderson, Nevada Leased Natural gas-turbine cogeneration facility
Sycamore Americas Oildale, California Leased Natural gas-turbine cogeneration facility
Watson Americas Carson, California Leased Natural gas-turbine cogeneration facility
26
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 $136.8 million. Brooklyn Navy Yard has also filed an
action entitled Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons
---------------------------------------------------------------
Main of New York, Inc., Nab Construction Corporation, L.K. Comstock & Co., Inc.
- -------------------------------------------------------------------------------
and The Parsons Corporation, in the Supreme Court of the State of New York,
- ---------------------------
Kings County, Index No. 5966/97 asserting general monetary claims in excess of
$13 million under the Construction Turnkey Agreement. On March 26, 1998, the
Superior Court in the California action granted PMNC's motion for attachment in
the amount of $43 million against Brooklyn Navy Yard and attached a Brooklyn
Navy Yard bank account in the amount of $0.5 million. Brooklyn Navy Yard is
appealing the attachment order. On the same day, the court stayed all
proceedings in the California action pending the New York action. PMNC's motion
to dismiss the New York action was denied by the New York Supreme Court and
further denied on appeal in September 1998. On March 9, 1999, Brooklyn Navy
Yard filed a motion for partial summary judgment in the New York action. The
motion was denied and Brooklyn Navy Yard has appealed. The appeal and the
commencement of discovery were suspended until June 2000 to allow for voluntary
mediation between the parties. The mediation ended unsuccessfully on March 23,
2000. We agreed to indemnify Brooklyn Navy Yard and our partner in the venture
from all claims and costs arising from or in connection with the contractor
litigation. We believe that the outcome of this litigation will not have a
material adverse effect on our consolidated financial position or results of
operations.
P. T. Perusahaan Listrik Negara - One of our subsidiaries, MEC Indonesia,
--------------------------------
B.V., owns a 40% interest in P. T. Paiton Energy, formerly known as Paiton
Energy Company, an Indonesian limited liability company. Paiton Energy
constructed a 1,230 MW coal-fired power project in East Java, Indonesia. The
Paiton project has achieved commercial operation. In 1994, Paiton Energy
entered into a Power Purchase Agreement with Indonesia's state-owned electricity
company, P. T. Perusahaan Listrik Negara, pursuant to which PT Perusahaan is
obligated to purchase the capacity and energy of the Paiton project.
On October 7, 1999, PT Perusahaan announced that it had filed a lawsuit in
the Central Jakarta District Court against Paiton Energy seeking to annul the
Power Purchase Agreement, notwithstanding that Paiton Energy continued to seek a
negotiated basis on which to operate the plant for an interim period during
which the parties could discuss longer term remedies for the effect on the
project of the current financial crisis affecting Indonesia. In its complaint,
PT Perusahaan generally alleged that the contract was the result of corruption,
cronyism and nepotism, was one-sided and against the public interest. The terms
of the Power Purchase Agreement provide that any disputes with respect thereto
must be submitted to arbitration in Stockholm, Sweden, and cannot be brought in
the courts of any country. Accordingly, immediately following the filing of PT
Perusahaan's lawsuit, Paiton Energy commenced an arbitration in accordance with
the terms of the Power Purchase Agreement in order to confirm the validity of
the agreement and to protect the interests of Paiton Energy's shareholders,
lenders and other credit support providers.
On January 20, 2000, pursuant to an understanding between PT Perusahaan and
Paiton Energy committing to negotiate an agreement on an interim arrangement, PT
Perusahaan withdrew its lawsuit and Paiton Energy withdrew the arbitration
proceedings against PT Perusahaan and the Government of Indonesia.
27
On February 21, 2000, PT Perusahaan and Paiton Energy executed an Interim
Agreement pursuant to which the Power Purchase Agreement will be administered
pending a long-term restructuring of the Power Purchase Agreement. Among other
things, the Interim Agreement provides for dispatch of the Paiton project, fixed
monthly payments to Paiton Energy by PT Perusahaan and the standstill of any
further legal proceedings by either party during the term of the Interim
Agreement. The term of the Interim Agreement is February 21, 2000 through
December 31, 2000, and may be extended by mutual agreement. See "Item 7.
Management's Discussion and Analysis of Results of Operations and Financial
Condition - Other Commitments and Contingencies - Paiton."
We experience other routine litigation in the normal course of our business.
None of our pending litigation is expected to have a material adverse effect on
our consolidated financial position or results of operations. See "Regulatory
Matters--Environmental Regulation".
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Inapplicable.
28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
All of the outstanding Common Stock of Edison Mission Energy is, as of the
date hereof, owned by The Mission Group, which is a wholly owned subsidiary of
Edison International. There is no market for the Common Stock.
Dividends of the Common Stock will be paid when declared by our Board of
Directors. We made a cash dividend payment to The Mission Group of $197 million
in 1997. In 1997, a non-cash dividend of $78 million was also made to The
Mission Group. In February 2000, we made a $22 million cash dividend payment to
The Mission Group.
Company Obligated Mandatorily Redeemable Security of Partnership Holding
Solely Parent Debentures. In November 1994, Mission Capital, L.P., a limited
partnership of which Edison Mission Energy is the sole general partner, issued
3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a
price of $25 per security. These securities are redeemable at the option of
Mission Capital, in whole or in part, beginning November 1999, with mandatory
redemption in 2024 at a redemption price of $25 per security, plus accrued and
unpaid distributions. No securities were redeemed in 1999. In November 1994,
we issued $90 million of 9.875% junior subordinated deferrable interest
debentures due 2024 pursuant to a subordinated indenture dated as of November
30, 1994 between us and The First National Bank of Chicago, as trustee. During
August 1995, Mission Capital issued 2.5 million 8.5% Cumulative Monthly Income
Preferred Securities, Series B at a price of $25 per security. These securities
are redeemable at the option of Mission Capital, in whole or in part, beginning
August 2000, with mandatory redemption in 2025 at a redemption price of $25 per
security, plus accrued and unpaid distributions. In August 1995, we issued $64
million of 8.5% junior subordinated deferrable interest debentures due 2025
pursuant to the subordinated indenture. We issued a guarantee in favor of the
holders of the preferred securities, which guarantees the payments of
distributions declared on the preferred securities, payments upon a liquidation
of Mission Capital and payments on redemption with respect to any preferred
securities called for redemption by Mission Capital. So long as any preferred
securities remain outstanding, we will not be able to declare or pay, directly
or indirectly, any dividend on, or purchase, acquire or make a distribution or
liquidation payment with respect to, any of its common stock if at such time (i)
we shall be in default with respect to its payment obligations under the
guarantee, (ii) there shall have occurred any event of default under the
subordinated indenture, or (iii) we shall have given notice of its selection of
an extended interest payment period as provided in the indenture and such
period, or any extension thereof, shall be continuing.
Not Subject to Mandatory Redemption. In connection with the 40% acquisition
of Contact Energy in May 1999, Edison Mission Energy Global Management, Inc., an
indirect, wholly owned affiliate of Edison Mission Energy, issued $120 million
of Flexible Money Market Cumulative Preferred Stock. The stock issuance
consists of (1) 600 Series A shares and (2) 600 Series B shares, both with
liquidation preference of $100,000 per share and a dividend rate of 5.74% until
May 2004. After May 28, 2004, the shares of each Series will be redeemable at
the option of us at a redemption price of US