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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 $100,000 per share, plus
accumulated and unpaid dividends. Pursuant to this right of optional
redemption, we may elect to redeem all or less than all of the shares of a
Series without redeeming shares of any other Series. Notwithstanding the
foregoing, if any dividends on shares of any Series are in arrears, no shares of
any Series shall be redeemed unless all outstanding shares are simultaneously
redeemed, and we shall not purchase or otherwise acquire any shares of any
Series; provided, however, that the foregoing shall not prevent the purchase or
acquisition of shares pursuant to
29
any otherwise lawful purchase or exchange offer made on the same terms to
holders of all outstanding shares of such Series.
We entered into a support agreement with Edison Mission Energy Global
Management that requires us to make capital contributions to Edison Mission
Energy Global Management in order for it to maintain a positive net worth and to
provide sufficient funds for payment of declared dividends on preferred stock
and any redemption price in respect of the preferred stock. Our maximum
obligation under the support agreement is limited to either (1) an amount equal
to twice the sum of (a) the liquidation preference of the preferred stock,
currently approximately $240 million, and (b) the liquidation preference of all
outstanding shares of stock of the subsidiary ranking on a parity with the
preferred stock, currently zero, or (2) the amount that we could lawfully
distribute to our shareholder under the Corporations Code of the State of
California, approximately $364 million as of December 31, 1999.
Subject to Mandatory Redemption. During June 1999, Edison Mission Energy
Taupo Limited, a New Zealand corporation, an indirect, wholly owned affiliate of
Edison Mission Energy, issued $84 million of Class A Redeemable Preferred Shares
(16,000 shares at a price of 10,000 New Zealand dollars per share). The
dividend rate ranges from 6.19% to 6.86%. The shares are redeemable in June
2003 at 10,000 New Zealand dollars per share. If an event of default occurs at
any time without prejudice to any other remedies which the redeemable preferred
share subscriber may have, the redeemable preferred share subscriber may, by
notice to the issuer, require redemption of, and the issuer must redeem, the
redeemable preferred shares on the date specified in that notice. Each dividend
will rank for payment in priority to the rights in respect of dividends and the
rights, if any, in respect of interest on arrears thereof of all holders of
other classes of shares of ours other than redeemable preferred shares issued by
us. Edison Mission Energy Taupo shall not pay or make, or allow to be paid or
made, any distribution, other than dividends or the redemption amount or similar
amounts payable in respect of the retail shares, if an event of default or
potential event of default has occurred, which remains unremedied, unless the
redeemable preferred share subscriber has given its prior written consent which
may be given on such conditions as the redeemable preferred share subscriber
deems reasonable.
From July through November 1999, Edison Mission Energy Taupo issued $125
million of retail redeemable preferred shares (240 million shares at a price of
one New Zealand dollar per share). The dividend rate ranges from 5.00% to
6.37%. The shares are redeemable at one New Zealand dollar per share in June
2001 (64 million), June 2002 (43 million), and June 2003 (133 million). Edison
Contact Finance is a special purpose company established to raise funds by the
issuance of retail redeemable preferred shares to assist Edison Mission Energy
Taupo to refinance in part the funding used by it for its acquisition of 40% of
the ordinary shares in Contact Energy. Edison Contact Finance and Edison
Mission Energy Taupo are parties to a subscription and indemnity agreement,
which contains the terms of subscription by Edison Contact Finance for Edison
Mission Energy Taupo retail shares. Edison Contact Finance will subscribe for
Edison Mission Energy Taupo retail shares as and when Edison Contact Finance
issues retail shares. The principal terms of issuance of Edison Mission Energy
Taupo retail shares are set out in the Subscription Agreement and are
substantially the same as the terms of issue of the Class A Redeemable Preferred
shares. On an event of default under the terms of issue of the retail shares,
early redemption of the shares may be required by the holders of the shares by
special resolution, by 15% of the holders of shares, in instances of non-
payment, by written notice to Edison Contact Finance, or Edison Contact Finance
by written notice to the holders of shares. If only part of the retail shares
are redeemed earlier than their scheduled redemption date, in some cases, a
minimum number of retail shares must be redeemed, and unless the redemption
occurs on a dividend payment date, Edison Mission Energy Taupo must redeem all
Edison Mission Energy Taupo shares in any class, with the same scheduled
redemption date and fixed dividend rate. Edison Contact Finance will redeem
30
the same shares of a class corresponding to the redeemed Edison Mission Energy
Taupo shares. Not all classes of shares need be affected by a partial redemption
of Edison Mission Energy Taupo retail shares. Redemption of retail shares can be
accelerated if Edison Mission Energy Taupo exercises its option under the terms
of the subscription and indemnity agreement to redeem any of the Edison Mission
Energy Taupo retail shares at its discretion. Edison Contact Finance will pay
fully imputed dividends, in arrears, to the holder of each retail share on the
record date. Edison Contact Finance may change the annual dividend rates, which
will attach to the shares at any time before acceptance by Edison Contact
Finance of an application for those shares.
We entered into two Deeds of Covenant comprised of a Facility Agreement and a
Subscription Agreement. The Facility Agreement requires us to provide funds to
Edison Mission Energy Taupo (1) of up to 13 million New Zealand dollars annually
in order for Edison Mission Energy Taupo to meet its interest and dividend
payment obligations to Credit Suisse First Boston and (2) to ensure that we
satisfy specified financial ratios. The Subscription Agreement requires us to
provide funds to the preferred stock subscriber to compensate for any shortfall
in attaching tax imputation credits to the dividends on the preferred stock.
EDISON MISSION ENERGY
PREFERRED STOCK REDEMPTION REQUIREMENTS
2000 2001 2002 2003 2004
------ ------ ------ ------ ------
Edison Mission Energy Taupo
Limited Class A Redeemable
Preferred Shares $ 0 $ 0 $ 0 $83,536,000 $ 0
Edison Mission Energy Taupo
Limited Retail Redeemable
Preference Shares 0 33,483,317 22,227,885 69,592,798 0
----- ----------- ----------- ------------ -----
Total $ 0 $33,483,317 $22,227,885 $153,128,798 $ 0
===== =========== =========== ============ =====
31
ITEM 6. SELECTED FINANCIAL DATA
(in millions) Years Ended December 31,
----------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
INCOME STATEMENT DATA
Operating revenues $1,642.4 $ 893.8 $ 975.0 $ 843.6 $467.3
Operating expenses 1,209.5 543.3 581.1 476.5 264.0
-------- ------- ------- ------- ------
Income from operations 432.9 350.5 393.9 367.1 203.3
Interest expense (375.5) (196.1) (223.5) (164.2) (93.1)
Interest and other income 49.3 50.9 53.9 40.7 33.1
Minority interest (3.0) (2.8) (38.8) (69.5) (48.3)
-------- ------- ------- ------- ------
Income before income taxes 103.7 202.5 185.5 174.1 95.0
Provision (benefit) for income taxes (40.4) 70.4 57.4 82.0 31.0
-------- ------- ------- ------- ------
Income before accounting change and extraordinary loss 144.1 132.1 128.1 92.1 64.0
Cumulative effect on prior years of change in
accounting for start-up costs, net of tax (13.8) -- -- -- --
Extraordinary loss on early extinguishment of debt,
net of income tax benefit -- -- (13.1) -- --
-------- ------- ------- ------- ------
$ 130.3 $ 132.1 $ 115.0 $ 92.1 $ 64.0
Net income ======== ======= ======= ======= ======
(in millions) December 31,
----------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
BALANCE SHEET DATA
Assets $15,534.2 $5,158.1 $4,985.1 $5,152.5 $4,374.0
Current liabilities 1,772.8 358.7 339.8 270.9 199.8
Long-term obligations 7,439.3 2,396.4 2,532.1 2,419.9 1,839.0
Preferred securities of subsidiaries 476.9 150.0 150.0 150.0 150.0
Shareholder's equity 3,068.5 957.6 826.6 1,019.9 1,028.5
(in millions) Years Ended December 31,
----------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
CASH FLOW DATA
Cash provided by operating activities $ 417.2 $266.6 $259.5 $294.5 $ 149.9
Cash provided by financing activities 8,363.5 17.9 55.4 184.9 1,115.2
Cash used in investing activities 8,837.8 408.2 91.4 246.3 1,191.3
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
The following discussion 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 discussion, 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. The information contained
in this discussion is subject to change without notice. Unless otherwise
indicated, the information presented in this section is with respect to Edison
Mission Energy and its consolidated subsidiaries.
General
- -------
We are an independent power producer engaged in the business of developing,
acquiring, owning and operating electric power generation facilities worldwide.
Our current investments include 76 projects totaling 28,446 megawatts (MW) of
generation capacity, of which 26,649 MW are in operation, our share is 22,056
MW, and 1,797 MW are under construction, our share is 714 MW.
Our operating revenues are derived primarily from electric revenues and equity
in income from energy projects. Electric revenues accounted for 83%, 74% and
76% of total operating revenues during 1999, 1998 and 1997, respectively.
Consolidated operating revenues also include equity in income from oil and gas
investments and revenues attributable to operation and maintenance services.
Electric revenues are derived from our majority owned domestic and
international entities. Equity in income from energy projects relates to energy
projects where our ownership interest is 50% or less in the projects. The
equity method of accounting is generally used to account for the operating
results of entities over which we have a significant influence but in which we
do not have a controlling interest. With respect to entities accounted for
under the equity method, we recognize our proportional share of the income or
loss of such entities.
Acquisitions
- ------------
Acquisition of Illinois Plants
On December 15, 1999, we completed a transaction with Commonwealth Edison to
acquire Commonwealth Edison's fossil-fuel power generating assets, which are
commonly referred to as the Illinois Plants. We will operate these plants, which
provide access to Mid-America Interconnected Network and the East Central Area
Reliability Council. In connection with this transaction, we entered into power
purchase agreements with Commonwealth Edison with a term of up to five years,
pursuant to which Commonwealth Edison will purchase capacity and have the right
to purchase energy generated by the plants.
Concurrent 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 this transaction with Commonwealth Edison is 9,510 MW.
33
Consideration for the Illinois Plants, excluding $860 million paid by a third
party to acquire the Collins Station, consisted of a cash payment of
approximately $4.1 billion. The acquisition was funded primarily with a
combination of approximately $1.6 billion of non-recourse debt secured by a
pledge of the stock of specified subsidiaries, $1.3 billion of our debt and $1.2
billion in equity contributions from Edison International.
Acquisition of Ferrybridge and Fiddler's Ferry Plants
On July 19, 1999, we completed a transaction with PowerGen UK plc, to acquire
the Ferrybridge and Fiddler's Ferry coal-fired electric generating plants
located in the United Kingdom. Ferrybridge, located in West Yorkshire, and
Fiddler's Ferry, located in Warrington, each has a generating capacity of
approximately 2,000 MW.
Consideration for Ferrybridge and Fiddler's Ferry consisted of approximately
$2.0 billion (1.3 billion pounds Sterling) for the two plants. The acquisition
was funded primarily with a combination of net proceeds of $1.3 billion (830
million pounds sterling) from the Edison First Power Limited Guaranteed Secured
Variable Rate Bonds issued on July 19, 1999 and due 2019, cash and a $500
million equity contribution from Edison International. The Edison First Power
Bonds were issued to a special purpose entity formed by Merrill Lynch
International. Merrill Lynch International sold the variable rate coupons
portion of the bonds to a special purpose entity that borrowed $1.3 billion (830
million pounds sterling) under a Term Loan Facility due 2012 to finance the
purchase.
Acquisition of Interest in Contact Energy
On May 14, 1999, we completed a transaction with the New Zealand government to
acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in 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 hydroelectric, geothermal and natural gas-fired
power generating plants primarily in New Zealand with a total current generating
capacity of 2,626 MW.
Consideration for Contact Energy consisted of a cash payment of approximately
$635 million (1.2 billion New Zealand dollars), which was financed by $120
million of preferred stock, a $214 million (400 million New Zealand dollars)
credit facility, a $300 million equity contribution from Edison International
and cash. The credit facility was subsequently paid off with proceeds from the
issuance of preferred securities.
Acquisition of Homer City Plant
On March 18, 1999, we completed a transaction with GPU, Inc., New York State
Electric & Gas Corporation and their respective affiliates to acquire the 1,884-
MW Homer City Electric Generating Station. This facility is a coal-fired plant
in the mid-Atlantic region of the United States and has direct, high voltage
interconnections to both the New York Independent System Operator, which
controls the transmission grid and energy and capacity markets for 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.
Consideration for the Homer City plant consisted of a cash payment of
approximately $1.8 billion, which was partially financed by $1.5 billion of new
loans, combined with our revolver borrowings and cash.
34
Acquisition of Interest in EcoElectrica
In December 1998, we acquired 50% of the 540-MW EcoElectrica liquefied natural
gas combined-cycle cogeneration facility under construction in Penuelas, Puerto
Rico for approximately $243 million. The project also includes a desalination
plant and liquefied natural gas storage and vaporization facilities and is
expected to commence commercial operation during the first quarter of 2000.
Acquisition of Loy Yang B Plant
In 1992, we acquired 51% of the 1,000-MW Loy Yang B Power Station from the
State Government of Victoria. In connection with the 1992 acquisition, we
entered into a 30-year power purchase agreement with the State Electricity
Commission of Victoria, under which the State Electricity Commission of Victoria
purchased our share of the plant output. Loy Yang B's principal assets are two
500-MW brown-coal-fired units located near Melbourne, Australia.
In May 1997, we acquired the State Government of Victoria's 49% interest in
Loy Yang B as part of the privatization process in the State of Victoria.
Consideration for the 49% interest consisted primarily of a cash payment of
approximately $64 million (84 million Australian dollars) and termination of an
existing 33-year power purchase agreement and other related agreements. The
transaction value totaled approximately $686 million (900 million Australian
dollars), which was based primarily on the value of the 49% interest in the
power plant using comparable information from sales of other power projects in
the region. As part of the transaction, we entered into a series of new power
related agreements for a 17-year period at market prices. As we previously
consolidated the Loy Yang B project with a minority interest held by the State
Government of Victoria, the acquisition of the remaining 49% resulted in: (1)
an increase to property, plant and equipment of approximately $18 million (24
million Australian dollars), (2) elimination of the State of Government of
Victoria's minority interest of approximately $668 million (876 million
Australian dollars) and (3) an increase of approximately $622 million (816
million Australian dollars) in deferred revenues attributable to the deferral of
the gain associated with the termination of the power sales agreement. The
deferred gain is being amortized over the life of the power purchase agreements.
Each of the acquisitions has been accounted for utilizing the purchase method.
The purchase price was allocated to the assets acquired and liabilities assumed
based on their respective fair market values. The financial statements of the
Homer City plant and Illinois Plants reflect the preliminary allocation of the
purchase price. The allocation has not been finalized relative to specified
valuations and related intangibles. Our consolidated statement of income
reflects the operations of the Homer City plant beginning March 18, 1999,
Contact Energy beginning May 1, 1999, Ferrybridge and Fiddler's Ferry plants
beginning July 19, 1999, and the Illinois Plants beginning December 15, 1999.
The consolidated statement of income for 1997 reflects the operations under the
new contracts and the elimination of the minority interest of the Loy Yang B
plant beginning on May 9, 1997.
Results of Operations
- ---------------------
Operating Revenues
Operating revenues increased $748.6 million in 1999 compared to 1998, and
decreased $81.2 million in 1998 compared to 1997. The 1999 increase resulted
from electric revenues from the Homer City plant acquired in March 1999,
Ferrybridge and Fiddler's Ferry plants acquired in July 1999, the Illinois
Plants acquired in December 1999 and the start of commercial operation of the
Doga project in May 1999. There were no comparable electric revenues for the
Homer City plant, Ferrybridge and Fiddler's Ferry plants, the Illinois Plants,
and the Doga project for 1998. The 1998 decrease was
35
primarily due to the Loy Yang B plant's new series of power purchase agreements
associated with our acquisition of the remainder of that plant in May 1997 and
lower Australian currency exchange rates, partially offset by higher energy
revenues from the First Hydro plants as a result of higher energy prices.
Equity in income from energy projects rose 27% in 1999 over 1998, and 14% in
1998 over 1997. The 1999 increase was primarily the result of higher revenues
from several cogeneration projects due to a final settlement on energy prices
tied to short-run avoided cost with the applicable public utilities. In
addition, equity in income increased from our purchase of a 40% ownership
interest in Contact Energy in May 1999. The 1998 increase was primarily due to
additional income from our 50% interest in a geothermal project, which
recognized a gain of $12.6 million pre-tax on the termination of their power
sales agreement and subsequent sale of the geothermal resource. The gain was
calculated based on the difference of the carrying value of our investment in
the geothermal project and the proceeds received in connection with the
termination of the related power sales agreement. In addition, lower fuel
prices improved earnings at gas-fired cogeneration projects, which was partially
offset by lower electric and steam revenues. Equity in income from oil and gas
investments increased 49% in 1999 compared to 1998, and decreased 54% in 1998
compared to 1997. The 1999 increase was primarily due to higher oil and gas
prices, while the 1998 decrease was primarily due to lower oil and gas prices.
Domestic energy projects, where our ownership interest is 50% or less,
generally rely on one power sales contract with a single electric utility
customer for the majority, and in some cases all, of its power sales revenues
over the life of the power sales contract. The primary power sales contracts
for 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.
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.
Operating Expenses
Total operating expenses increased $666.2 million in 1999 compared to 1998,
and decreased $37.8 million in 1998 compared to 1997. The 1999 increase was due
to higher fuel, plant operations, depreciation and amortization and
administrative and general expenses. Fuel and plant operations expense
increased $435.9 million, depreciation and amortization expense increased $102.9
million and administrative and general expenses increased $128.2 million in
1999. The 1998 decrease was primarily due to lower fuel and depreciation and
amortization expense. Fuel expense decreased $15.4 million and depreciation and
amortization decreased $15.5 million in 1998.
The 1999 increase in fuel expense and plant operations resulted from having no
comparable expenses for the Homer City plant, Ferrybridge and Fiddler's Ferry
plants, the Illinois Plants, and the Doga project for 1998. The 1998 decrease in
fuel expense was primarily due to the new fuel supply agreement entered into for
the Loy Yang B plant in connection with our acquisition of the remainder of that
plant in May 1997, partially offset by higher fuel expense at the First Hydro
plants as a result of higher prices and increased generation in 1998.
36
The 1999 increase in depreciation and amortization resulted primarily from
expenses at the Homer City plant and Ferrybridge and Fiddler's Ferry plants,
which had no comparable expenses in 1998. The 1998 decrease in depreciation and
amortization is the result of a full year's impact of the extension in the
useful life of the Loy Yang B project's plant and equipment from approximately
30 years, the term of the previous power purchase agreement, to 50 years, the
projected economic life of the plant, as a result of the May 1997 acquisition,
combined with lower Australian currency exchange rates. The extension in the
useful life of the Loy Yang B project's plant and equipment resulted in lower
depreciation expense of $13.8 million, after-tax, in 1997.
Administrative and general expenses increased in 1999 primarily due to higher
compensation expense for charges related to our phantom stock plan. In the
fourth quarter of 1999, we recorded a one-time charge of $67.5 million, after-
tax, in connection with the termination of the plan and the related proposed
exchange offer to holders of outstanding phantom options. Administration and
general expenses decreased slightly in 1998 as a result of lower compensation
expense for charges related to our phantom stock plan, partially offset by
higher project development costs. Compensation expense recorded with respect to
our phantom stock plan was $136.3 million, including the termination charge
discussed above, $39 million and $70 million in 1999, 1998 and 1997,
respectively.
Other Income (Expense)
Interest and other income decreased $8.1 million in 1999 compared to 1998, and
increased $22.5 million in 1998 compared to 1997. The 1999 decrease was
primarily due to lower interest income as a result of lower cash balances. The
1998 increase resulted primarily from interest earned on higher cash balances.
During the fourth quarter of 1999, we completed a sale of a portion of our
interest in Four Star Oil & Gas Company 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 and we recorded an after-tax gain of approximately $30 million.
During the second quarter of 1997, we completed a sale of our ownership
interest in B.C. Star Partners for total net proceeds of $71.2 million. We
recorded an after-tax gain of approximately $14 million on the sale in April
1997.
Interest expense increased $170.3 million in 1999 compared to 1998, and
decreased $27.4 million in 1998 compared to 1997. The 1999 increase was
primarily the result of additional debt financing of the Homer City plant,
Ferrybridge and Fiddler's Ferry plants, and the Illinois Plants acquisitions.
The 1999 increase was partially offset by higher capitalized interest
principally due to our investment in the EcoElectrica project in December 1998.
The decrease in 1998 was due to lower Australian currency exchange rates and
higher capitalized interest as a result of higher accumulated construction
expenditures.
Dividends on preferred securities increased $9.2 million in 1999 compared to
1998. The 1999 increase reflects the additional issuance of preferred securities
in connection with the Contact Energy acquisition.
Minority interest expense decreased $36.1 million in 1998 compared to 1997.
The 1998 decrease resulted from the acquisition of the remaining 49% ownership
interest in the Loy Yang B plant in May 1997.
Provision for Income Taxes
37
We had effective tax provision (benefit) rates of (39.0)%, 34.8% and 30.9% in
1999, 1998 and 1997, respectively. Income taxes decreased in 1999, principally
due to lower pre-tax income and income tax benefits. In 1999, we recorded tax
benefits associated with a capital loss attributable to the sale of a portion of
our interest in Four Star Oil & Gas Company, refund of advanced corporation tax
payments from the United Kingdom and a reduction in deferred taxes in Australia
as a result of a decrease in statutory rates. In addition, our effective tax
rate has decreased as a result of lower foreign income taxes that result from
the permanent reinvestment of earnings from foreign affiliates located in
different foreign tax jurisdictions. The Australia corporate tax rate decreased
from 36% to 34% effective in July 2000, and from 34% to 30% effective in July
2001. The 1998 and 1997 tax provisions reflect a benefit from reductions in the
United Kingdom corporate tax rate from 33% to 31% effective in April 1997, and
from 31% to 30% effective in April 1999. In accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes," the
reductions in the Australia and United Kingdom income tax rates resulted in
reductions in income tax expense of approximately $5.9 million, $11 million and
$20 million in 1999, 1998 and 1997, respectively.
We are, and may in the future be, under examination by tax authorities in
varying tax jurisdictions with respect to positions we take in connection with
the filing of our tax returns. Matters raised upon audit may involve
substantial amounts, which, if resolved unfavorably, an event not currently
anticipated, could possibly be material. However, in our opinion, it is
unlikely that the resolution of any such matters will have material adverse
effect upon our financial condition or results of operations.
Cumulative Effect of Change in Accounting Principle
In April 1998, the American Institute of Certified Public Accountants issued
Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities,"
which became effective in January 1999. The Statement requires that specified
costs related to start-up activities be expensed as incurred and that specified
previously capitalized costs be expensed and reported as a cumulative change in
accounting principle. The impact to our net income of adopting SOP 98-5 was
$13.8 million, after tax.
Extraordinary Loss
The early repayment of the Loy Yang B plant's existing debt facilities of $713
million in connection with our acquisition of the remaining 49% interest in May
1997 resulted in an extraordinary loss of $13.1 million, net of income tax
benefit of $8.6 million, attributable to the write-off of unamortized debt issue
costs.
Liquidity and Capital Resources
- -------------------------------
Cash provided by operating activities is derived primarily from distributions
from energy projects and dividends from investments in oil and gas. Net cash
provided by operating activities increased $150.6 million in 1999 compared to
1998, and $7.1 million in 1998 compared to 1997. The 1999 increase was
primarily due to higher distributions from energy projects and higher dividends
from oil and gas investments. The 1998 increase was primarily due to lower
income taxes paid and higher distributions from energy projects, partially
offset by lower dividends from investments in oil and gas and an increase in
working capital requirements.
Net working capital at December 31, 1999 was ($815.5) million compared to
$248.6 million at December 31, 1998. Net working capital decreased primarily as
a result of utilizing short-term capacity under commercial paper facilities to
finance a portion of the acquisitions of the Homer City project and the Illinois
Plants. We expect to re-finance the short-term borrowings with a combination of
new or extended short-term borrowings and issuance of long-term debt.
38
At December 31, 1999, we had cash and cash equivalents of $398.7 million and
had available $159.6 million of borrowing capacity under a $500 million
revolving credit facility that expires in 2001, and $70 million of borrowing
capacity under a $700 million commercial paper facility that expires in 2000.
The credit facility provides credit available in the form of cash advances or
letters of credit, and bears interest on advances under the London Interbank
Offered Rate, LIBOR, which was 6.44% at December 31, 1999, plus the applicable
margin as determined by our long-term debt ratings (0.175% margin at December
31, 1999). In addition to the interest component described above, we pay a
facility fee as determined by our long-term debt ratings (0.075% at December 31,
1999) on the entire credit facility independent of the level of borrowings.
This borrowing capacity under the revolving credit facility may be reduced by
borrowings for firm commitments to contribute project equity and to fund capital
expenditures and construction costs of its project facilities.
Net cash provided by financing activities totaled $8,363.5 million in 1999,
compared to $17.9 million and $55.4 million in 1998 and 1997, respectively. The
1999 increase was primarily due to an increase in financings related to the
acquisition of four new projects. A term loan facility of $1.3 billion related
to the Ferrybridge and Fiddler's Ferry plants, senior secured bonds totaling
$830 million related to the Homer City plant, $120 million Flexible Money Market
Cumulative Preferred Stock and $125 million Retail Redeemable Preference Shares
and $84 million Class A Redeemable Preferred Shares related to Contact Energy
and a credit facility totaling $1.7 billion related to the Illinois Plants. In
addition, our financings in connection with the aforementioned acquisitions
consisted of floating rate notes of $500 million, borrowings of $215 million
under our revolving credit facility and commercial paper facilities totaling
$1.2 billion. In addition, we also received $2.0 billion in equity
contributions from Edison International to finance our 1999 acquisitions. In
June 1999, we issued $600 million, 7.73% Senior Notes due 2009 to be used for
general corporate purposes. As of December 31, 1999, we had recourse debt of
$2.6 billion, with an additional $6.2 billion of non-recourse debt (debt which
is recourse to specific assets or subsidiaries) on our consolidated balance
sheet.
The 1998 decrease was principally due to a reduction in financing activities.
In 1997, the Loy Yang B project's financing proceeds, received in connection
with our acquisition of the remaining 49% of that plant, were primarily used to
repay existing debt facilities.
The Loy Yang B financing in 1997 consisted of (1) borrowings under a $373
million (490 million Australian dollars) 15-year interest only term facility,
(2) borrowings under a $583 million (765 million Australian dollars) 20-year
amortizing term facility with principal and interest payments scheduled
quarterly commencing September 30, 1998 and (3) borrowings under an $8 million
(10 million Australian dollars) working capital facility with a term equal to
that of the 20-year amortizing term facility. The financing was structured on a
non-recourse basis to us.
Net cash used in investing activities totaled $8,837.8 million in 1999
compared to $408.2 million and $91.4 million in 1998 and 1997, respectively.
The 1999 increase was primarily due to the purchase of the Homer City plant,
Ferrybridge and Fiddler's Ferry generating facilities, the Illinois Plants and
an ownership interest in Contact Energy. The 1998 increase was principally due
to the investments and loans totaling $242.8 million for the purchase of our
ownership interest in the EcoElectrica project and lower proceeds from loan
repayments. Proceeds of $71.2 million were received from the sale of our
ownership interest in B.C. Star Partners in 1997. We invested $216.4 million,
$73.4 million and $87.7 million in 1999, 1998 and 1997, respectively, in new
plant and equipment principally related to the Homer City plant and Ferrybridge
and Fiddler's Ferry plants in 1999, and the Doga project in 1998 and 1997.
Capital expenditures, including environmental expenditures disclosed under the
caption "Environmental Matters or Regulations," in 2000 are expected to
approximate $297 million.
39
Firm Commitments to Contribute Project Equity
Projects Local Currency U.S. ($ in millions)
- -------- -------------- --------------------
ISAB (i) 244 billion Italian Lira $127
EcoElectrica (ii) 34
Tri Energy (iii) 25
(i) ISAB is a 512-MW integrated gasification combined cycle power plant under
construction near Siracusa in Sicily, Italy. A wholly owned subsidiary of
Edison Mission Energy owns a 49% interest. Equity will be contributed at
commercial operation, which is currently scheduled for the first quarter
of 2000.
(ii) EcoElectrica is a 540-MW liquefied natural gas combined-cycle cogeneration
facility under construction in Penuelas, Puerto Rico. A wholly owned
subsidiary of Edison Mission Energy owns a 50% interest. Equity will be
contributed at commercial operation, which is currently scheduled for the
first quarter of 2000.
(iii) Tri Energy is a 700-MW gas-fired power plant under construction in the
Ratchaburi Province, Thailand. A wholly owned subsidiary of Edison Mission
Energy owns a 25% interest. Equity will be contributed at commercial
operation, which is currently scheduled for mid-2000.
Firm commitments to contribute project equity could be accelerated due to
specified events of default as defined in the non-recourse project financing
facilities. We have no reason to believe that these events of default will
occur to require acceleration of the firm commitments.
Contingent Obligations to Contribute Project Equity
Projects U.S. ($ in millions)
- -------- --------------------
Paiton (i) $111
Tri Energy (ii) 20
All Other 28
(i) Contingent obligations to contribute additional project equity would be
based on events principally related to insufficient cash flow to cover
interest on project debt and operating expenses, project cost overruns
during the plant construction, specified partner obligations or events of
default. In any and all circumstances, our obligation to contribute
contingent equity will not exceed $141 million, of which $30 million was
contributed as of December 31, 1999.
As more fully described below under the caption "Other Commitments and
Contingencies", PT Perusahaan Listrik Negara, the main source of revenue for
the project, has failed to pay the project in respect of its last eight
invoices and paid only a portion of another invoice. In addition, PT
Perusahaan filed a lawsuit, which it subsequently withdrew, contesting the
validity of the power purchase agreement under which it was to purchase
electricity from the project.
In response to PT Perusahaan's failure to pay, Paiton Energy entered into an
interim agreement with its lenders which modified the contingent equity
provisions of the Paiton debt documents during the agreed interim period,
which extends from October 15, 1999 through July 31, 2000. The interim
agreement provides, among other things, that contingent equity from us and
the other Paiton Energy
40
shareholders shall be contributed from time to time as needed to enable
Paiton Energy to pay interim project costs. Interim project costs include
interest on project debt and operating costs which become due and payable
during the term of the interim agreement and other costs related to the
construction of the project, provided that in the latter case no more than
an aggregate of $30 million of contingent equity can be used for this
purpose. The interim agreement provides that a portion of unfunded
contingent equity in the original amount of $206 million, of which our
current unfunded share is $85 million, will become due and payable by the
shareholders in the event that certain events of default, other than those
specifically waived under the interim agreement, occur. The interim
agreement further provides that all unfunded contingent equity in the
original amount of $300 million, of which our current unfunded share is $93
million, will become due and payable by the shareholders in the event that
Paiton Energy fails to make any interest payment during the pendency of the
interim agreement. As of March 14, 2000, Paiton Energy's shareholders have
contributed to Paiton $103 million of contingent equity, of which our share
is $48 million.
The contractor for the Paiton project and Paiton Energy reached a global
settlement in principal, the terms of which are being finalized. The global
settlement deals with all claims, including contractor claims for
retention, costs relating to a dispute involving a slope adjacent to the
Paiton site and other cost overruns related to delays in the completion of
the construction of the project and Paiton Energy's claims under the
construction contract. Terms and conditions of this settlement will require
the approval of Paiton Energy's lenders. We have no reason to believe that
these approvals will not be obtained. As noted, the shareholders'
obligation to contribute contingent equity to Paiton to enable it to pay
the contractor for the finally agreed amount is limited to $30 million.
Paiton's obligations to the contractor may exceed this amount. The
shortfall, if any, will be considered as part of the renegotiation of the
power purchase agreement and the project's debt agreements, as more fully
discussed under the caption, "Other Commitments and Contingencies."
Our contingent equity obligations for the Paiton project are to be
cancelled, if unused, as of the later of the date of term financing by the
Export-Import Bank of the United States and August 1, 2000. Term financing
by the Export-Import Bank of the United States is the subject of a
comprehensive set of conditions. The obligation of the Export-Import Bank
of the United States to provide term financing was initially scheduled to
terminate on October 15, 1999. The Export-Import Bank of the United States
agreed to extend the term financing commitment through December 31, 2000
and has determined that the project will need to meet additional terms and
conditions for take-out of the construction lenders.
(ii) Contingent obligations to contribute additional equity to the project would
be based on events principally related to capital cost overruns during the
plant's construction, specified partner obligations or events of default.
Other than as noted above, we are not aware, at this time, of any other
contingent obligations or obligations to contribute project equity.
Other Commitments and Contingencies
Subsidiary Indemnification Agreements
Some of our subsidiaries have entered into indemnification agreements,
under which the subsidiaries agreed to repay capacity payments to the projects'
power purchasers in the event the projects unilaterally terminate their
performance or reduce their electric power producing capability during the term
of the power contracts. Obligations under these indemnification agreements as of
December 31, 1999, if payment were required, would be $280 million. We have no
reason to believe
41
that the projects will either terminate their performance or reduce their
electric power producing capability during the term of the power contracts.
Paiton
Paiton is a 1,230-MW coal-fired power plant in operation in East Java,
Indonesia. A wholly owned subsidiary of Edison Mission Energy owns a 40%
interest and has a $419 million investment at December 31, 1999. The project's
tariff is higher in the early years and steps down over time. The tariff for
the Paiton project includes infrastructure to be used in common by other units
at the Paiton complex. The plant's output is fully contracted with the state-
owned electricity company, PT Perusahaan Listrik Negara. Payments are in
Indonesian Rupiah, with the portion of such 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 of the power purchase
agreement in February 1994. The project 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. PT Perusahaan's payment
obligations are supported by the Government of Indonesia. The projected rate of
growth of the Indonesian economy and the exchange rate of Indonesian Rupiah into
U.S. dollars have deteriorated significantly since the Paiton project was
contracted, approved and financed. The Paiton project's senior debt ratings have
been reduced from investment grade to speculative grade based on the rating
agencies' determination that there is increased risk that PT Perusahaan might
not be able to honor the electricity sales contract with Paiton. The Government
of Indonesia has arranged to reschedule sovereign debt owed to foreign
governments and has entered into discussions about rescheduling sovereign debt
owed to private lenders. Specified events, including those discussed in the
paragraph below, which, with the passage of time or upon notice, may mature into
defaults of the Project's debt agreements have occurred. On October 15, 1999,
the project entered into an interim agreement with its lenders pursuant to which
the lenders waived such defaults until July 31, 2000. However, this waiver may
expire on an earlier date if additional defaults, other than those specifically
waived, or other specified events occur.
In May 1999, Paiton notified PT Perusahaan 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. Because of the economic downturn, PT Perusahaan is
experiencing low electricity demand and PT Perusahaan has therefore dispatched
the Paiton plant to zero; however, under the terms of the power purchase
agreement, PT Perusahaan is required to continue to pay for capacity and fixed
operating costs once each unit and the plant achieve commercial operation. An
invoice for these charges for May in the amount of $7.8 million was submitted to
PT Perusahaan. The project and PT Perusahaan met to review the invoice and a
partial payment of $2.5 million was subsequently received. The primary reason
for the payment shortage was the use of an arbitrary Indonesian Rupiah/U.S.
dollar exchange rate of 2,450 Indonesian Rupiah to one U.S. dollar by PT
Perusahaan. The use of this exchange rate is not in agreement with the power
purchase agreement, but is the exchange rate on which PT Perusahaan payments to
other independent power producers in Indonesia have been based. Additional
invoices for capacity charges and fixed operating costs in an aggregate amount
of $312 million were later submitted to PT Perusahaan. PT Perusahaan has yet to
make any payments in respect of such latter invoices. In addition, PT
Perusahaan filed a lawsuit contesting the validity of its agreement to purchase
electricity from the project. The lawsuit was withdrawn by PT Perusahaan on
January 20, 2000, and on February 21, 2000, Paiton and PT Perusahaan 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, 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,
42
2000 and may be extended by mutual agreement. PT Perusahaan 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
renegotiations with PT Perusahaan, the Government of Indonesia or the project's
creditors on our expected return on our investment in Paiton is uncertain at
this time; however, we believe that we will ultimately recover our investment in
the project.
43
Contact Energy
In May 1999, a wholly owned subsidiary of Edison Mission Energy issued $120
million of preferred stock in connection with the acquisition of a 40% interest
in Contact Energy. We entered into a support agreement with this subsidiary
that requires us to make capital contributions to the subsidiary in order for it
to maintain a positive net worth and to provide sufficient funds for payment of
declared dividends on preferred stock and any redemption price in respect of the
preferred stock. Our maximum obligation under the support agreement is limited
to either (1) an amount equal to twice the sum of (a) the liquidation preference
of the preferred stock, currently approximately $240 million, and (b) the
liquidation preference of all outstanding shares of stock of the subsidiary
ranking on a parity with the preferred stock, currently zero, or (2) the amount
that we could lawfully distribute to our shareholder under the Corporations Code
of the State of California, approximately $364 million as of December 31, 1999.
Brooklyn Navy Yard
Brooklyn Navy Yard is a 286-MW gas-fired cogeneration power plant in Brooklyn,
New York. Our wholly owned subsidiary owns 50% of the project. In February
1997, the construction contractor asserted general monetary claims under the
turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for
damages in the amount of $136.8 million. Brooklyn Navy Yard Cogeneration
Partners has asserted general monetary claims against the contractor. In
connection with a $407 million non-recourse project refinancing in 1997, we
agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner
from all claims and costs arising from or in connection with the contractor
litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration
Partners' lenders. At the present time, we cannot reasonably estimate the
amount that would be due, if any, related to this litigation. Additional
amounts, if any, which would be due to the contractor with respect to completion
of construction of the power plant would be accounted for as an additional part
of its power plant investment. Furthermore, our partner has executed a
reimbursement agreement with us that provides recovery of up to $10 million over
an initial amount, including legal fees, payable from its management and royalty
fees. At December 31, 1999, no accrual has been recorded in connection with
this litigation. We believe that the outcome of this litigation will not have a
material adverse effect on our consolidated financial position or results of
operations.
Homer City
We have guaranteed to the bondholders, banks and other secured parties, which
financed the acquisition of the Homer City plant the performance and payment
when due by Edison Mission Holdings Co. of its obligations in respect of
specified senior debt, up to $42 million. This guarantee will be available
until December 31, 2001, after which time we will have no further obligations
under this guarantee.
Collins Operating Station Lease
In connection with the acquisition of the Illinois Plants, we assigned the
right to purchase the Collins gas-fired power plant to a third party. The third
party purchased the Collins Station for $860 million and entered into a lease of
the plant with us. The lease, which is being accounted for as an operating
lease, has an initial term of 33.75 years with payments due on a quarterly
basis. The base lease rent includes both a fixed and variable component; the
variable component of which is impacted by movements in defined short-term
interest rate indexes. Under the terms of the lease, we may request the lessor,
at its option, to refinance the lessor's debt, which if completed would impact
the base lease rent. If the lessor intends to sell the interest in the Collins
Station, we have a first right of refusal to
44
acquire the facility at fair market value. Minimum lease payments during the
next five years are $16.7 million in 2000; $42.3 million in 2001; $50.3 million
in 2002; $50.3 million in 2003; and $50.4 million in 2004. At December 31, 1999,
the total remaining minimum lease payments are $1.5 billion.
Fuel Supply Contracts
At December 31, 1999, we had contractual commitments to purchase and/or
transport coal and fuel oil. Based on the contract provisions, which consist of
fixed prices, subject to adjustment clauses in certain cases, these minimum
commitments are currently estimated to aggregate $2.5 billion in the next five
years summarized as follows: 2000 - $838 million; 2001 - $637 million; 2002 -
$445 million; 2003 - $326 million; 2004 - $291 million.
Employment Agreements
During the first quarter of 2000, we entered into mutual agreements with two
key officers of Edison Mission Energy terminating their positions with Edison
Mission Energy and related companies. One of the agreements provides for an
officer to be paid $500,000 as a one-time severance payment. The other agreement
provides for an officer to be paid one-year's salary as severance and permitted
to continue his current living arrangements in Europe for one year. In March
2000, we paid the officers $35 million and $12 million, respectively, in
cancellation of their vested Edison Mission Energy phantom stock options. These
payments equaled agreed upon amounts per Edison Mission Energy phantom stock
option over the exercise prices of the officers' vested phantom stock options
and were accrued as of the end of 1999 in anticipation of a contemplated
exchange offer or future phantom stock option exercises. The amounts are
subject to upward adjustment if an exchange offer for similarly situated
individuals is completed at a higher price per share.
The agreement with one of the officers also provides for consulting services
to be rendered by him to Edison Mission Energy for a period of up to 24 months,
subject to earlier termination under certain circumstances. During the
consulting period, we will pay the officer a consulting fee at the rate of
$300,000 per annum and his unvested Edison International stock options will
continue to vest ratably. The unvested phantom stock options will also vest
ratably during the consulting period and be paid out at the same rate per
phantom stock option as was paid in cancellation of his vested phantom stock
options, up to $1.712 million in the aggregate.
Under the agreements with Edison Mission Energy, both officers are subject to
a number of covenants, including confidentiality, non-solicitation, non-
disparagement and non-interference. One of the officers is also subject to a
non-competition covenant.
Other
In support of the businesses of our subsidiaries, we have made, from time to
time, guarantees, and have entered into indemnity agreements with respect to our
subsidiaries' obligations like those for debt service, fuel supply or the
delivery of power, and have entered into reimbursement agreements with respect
to letters of credit issued to third parties to support our subsidiaries'
obligations.
We may incur additional guaranty, indemnification, and reimbursement
obligations, as well as obligations to make equity and other contributions to
projects in the future. We believe that we will have sufficient liquidity on
both a short- and long-term basis to fund pre-financing project development
costs, make equity contributions to project subsidiaries, pay our debt
obligations and pay other administrative and general expenses as they are
incurred from (1) distributions from energy projects and
45
dividends from investments in oil and gas, (2) proceeds from the repayment of
loans made by us to our project subsidiaries, and (3) funds available from our
revolving credit facility.
Market Risk Exposures
- ---------------------
Edison Mission Energy's primary market risk exposures arise from changes in
interest rates, changes in oil and gas prices and electricity pool pricing and
fluctuations in foreign currency exchange rates. We manage these risks by using
derivative financial instruments in accordance with established policies and
procedures. We do not use derivative financial instruments for speculative
purposes.
Interest Rate Risk
Interest rate changes affect the cost of capital needed to finance the
construction and operation of our projects. We have mitigated the risk of
interest rate fluctuations by arranging for fixed rate financing or variable
rate financing with interest rate swaps or other hedging mechanisms for a number
of our project financings. Interest expense included $25.2 million, $22.8
million and $20.5 million for the years 1999, 1998 and 1997, respectively, as a
result of interest rate hedging mechanisms. We have entered into several
interest rate swap agreements under which the maturity date of the swaps occurs
prior to the final maturity of the underlying debt.
A 10% increase in market interest rates would result in a $29.4 million
increase in the fair value of our interest rate hedge agreements. A 10%
decrease in market interest rates would result in a $29 million decline in the
fair value of our interest rate hedge agreements.
Commodity Price Risk
Electric power generated at our uncontracted plants is generally sold under
bilateral arrangements with utilities and power marketers under short-term
contracts with terms of two years or less, or in the case of the Homer City
plant, to the PJM or the NYISO. We have developed risk management policies and
procedures which, among other matters, address credit risk. When making sales
under negotiated bilateral contracts, it is our policy to deal with investment
grade counterparties. We hedge a portion of the electric output of our merchant
plants, whose output is not committed to be sold under long term contracts, in
order to lock in desirable outcomes. When appropriate, we manage the "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 plants 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. The First Hydro and Ferrybridge and Fiddler's
Ferry plants 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.
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
46
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 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.
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. At
December 31, 1999, we had entered into a series of power call options in
connection with the Homer City plant. Based on year-end forward prices, we had
a net deferred gain of $3.5 million on those contracts.
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
47
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.
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.
Our electric revenues were increased by $60.9 million, $108.4 million and
$95.5 million in 1999, 1998 and 1997 as a result of electricity rate swap
agreements and other hedging mechanisms. A 10% increase in pool prices would
result in a $130.3 million decrease in the fair market value of electricity rate
swap agreements. A 10% decrease in pool prices would result in a $129.7 million
increase in the fair market value of electricity rate swap agreements. An
electricity rate swap agreement is an exchange of a fixed price of electricity
for a floating price. As a seller of power, we receive the fixed price in
exchange for a floating price, like the index price associated with electricity
pools.
Foreign Exchange Rate Risk
Fluctuations in foreign currency exchange rates can affect, on a United States
dollar equivalent basis, the amount of our equity contributions to, and
distributions from, our international projects. As we continue to expand into
foreign markets, fluctuations in foreign currency exchange rates can be expected
to have a greater impact on our results of operations in the future. At times,
we have hedged a portion of our current exposure to fluctuations in foreign
exchange rates through financial derivatives, offsetting obligations denominated
in foreign currencies, and indexing underlying project agreements to United
States dollars or other indices reasonably expected to correlate with foreign
exchange movements. In addition, we have used statistical forecasting
techniques to help assess foreign exchange risk and the probabilities of various
outcomes. There can be no assurance, however, that fluctuations in exchange
rates will be fully offset by hedges or that currency movements and the
relationship between certain macro economic variables will behave in a manner
that is consistent with historical or forecasted relationships. Foreign
exchange considerations for three major international projects, other than
Paiton which was discussed earlier, are discussed below.
48
The First Hydro and Ferrybridge and Fiddler's Ferry plants in the United
Kingdom and the Loy Yang B plant in Australia have been financed in their local
currency, pound sterling and Australian dollars, respectively, thus hedging the
majority of their acquisition costs against foreign exchange fluctuations.
Furthermore, we have evaluated the return on the remaining equity portion of
these investments with regard to the likelihood of various foreign exchange
scenarios. These analyses use market derived volatilities, statistical
correlations between specified variables, and long-term forecasts to predict
ranges of expected returns. Based upon these analyses, we believe that the
investment returns for the First Hydro, Ferrybridge and Fiddler's Ferry, and Loy
Yang B plants are adequately insulated from a broad range of foreign exchange
scenarios at this time.
We will continue to monitor our foreign exchange exposure and analyze the
effectiveness and efficiency of hedging strategies in the future.
Other
The electric power generated by some of our domestic operating projects,
excluding the Homer City plant and the Illinois Plants, is sold to electric
utilities under long-term, typically with terms of 15 to 30-years, power
purchase agreements and is expected to result in consistent cash flow under a
wide range of economic and operating circumstances. To accomplish this, we
structure our long-term contracts so that fluctuations in fuel costs will
produce similar fluctuations in electric and/or steam revenues and enter into
long-term fuel supply and transportation agreements. The degree of linkage
between these revenues and expenses varies from project to project, but
generally permits the projects to operate profitably under a wide array of
potential price fluctuation scenarios.
ENVIRONMENTAL MATTERS OR REGULATIONS We are subject to environmental regulation
by federal, state, and local authorities in the United States and foreign
regulatory authorities with jurisdiction over projects located outside the
United States. We believe that 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 position or results of operation.
We expect that the implementation of Clean Air Act Amendments will result in
increased capital expenditures and operating expenses. 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. 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. We do not expect these increased capital expenditures and
operating expenses to have a material effect on our financial position or
results of operation.
YEAR 2000 ISSUE We implemented a comprehensive program to remediate potential
year 2000 impacts from critical systems. We divided our year 2000 issue
activities into five phases: inventory, impact assessment, remediation,
documentation and certification. A critical system was defined as those
applications and systems, including embedded processor technology, which, if not
appropriately remediated, might have had a significant impact on customers, the
revenue stream, regulatory compliance, or the health and safety of personnel.
49
The other essential component of our year 2000 readiness program was to
identify and assess vendor products and business partners for year 2000
readiness. We utilized a process to identify and contact vendors and business
partners to determine their year 2000 status, and have evaluated the responses.
Our general policy requires that all newly purchased products be year 2000 ready
or otherwise designed to allow us to determine whether such products present
year 2000 issues.
Plant contingency plans have been developed and reviewed for any significant
issues and to schedule appropriate testing and/or training. These contingency
plans include strategies for dealing with year 2000-related processing failures
or malfunctions due to our internal systems or those of third parties. Our
contingency plans evaluate reasonably likely worst case scenarios or conditions.
Our year 2000 contingency plans were completed and in place for the end of the
year rollover event. In addition, an early warning and information database was
in place that received input from all our plants and corporate offices worldwide
during the millennium event. As of the filing date of this report, we are not
aware of any material year 2000 problem of our system and services. In
addition, we have not received any notification from any supplier of any year
2000-related disruption in their business. However, the success of our year
2000 efforts and the efforts of our third party suppliers cannot guarantee that
there will not be a material adverse effect on our business should a year 2000
problem manifest or become apparent in the future.
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 133 In June 1998, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities", which,
as amended, will be effective in January 2001. The Statement establishes
accounting and reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured at its
fair value. The Statement requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met. A derivative's gains and losses for qualifying hedges offset related
results on the hedged item in the income statement and a company must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting. The impact of adopting Statement 133 on our financial
statements has not been quantified at this time.
RECENT DEVELOPMENTS 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.
50
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A is filed with this report under Item 7.
"Management's Discussion and Analysis of Results of Operations and Financial
Condition."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements:
Report of Independent Public Accountants.
Consolidated Statements of Income for the years ended December 31, 1999, 1998
and 1997.
Consolidated Balance Sheets at December 31, 1999 and 1998.
Consolidated Statements of Shareholder's Equity for the years ended December
31, 1999, 1998 and 1997.
Consolidated Statements of Cash Flows for the years ended December 31, 1999,
1998 and 1997.
Notes to Consolidated Financial Statements.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
51
EDISON MISSION ENERGY AND SUBSIDIARIES
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Edison Mission Energy:
We have audited the accompanying consolidated balance sheets of Edison Mission
Energy (a California corporation) and subsidiaries as of December 31, 1999 and
1998, and the related consolidated statements of income, shareholder's equity
and cash flows for each of the three years in the period ended December 31,
1999. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Edison
Mission Energy and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999 in conformity with accounting principles
generally accepted in the United States.
Arthur Andersen LLP
Orange County, California
March 28, 2000
52
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands)
Years Ended December 31,
------------------------------------------------------
1999 1998 1997
---------------- ---------------- ----------------
Operating Revenues
Electric revenues $1,360,039 $ 664,055 $ 744,675
Equity in income from energy projects 218,058 171,819 151,306
Equity in income from oil and gas investments 26,286 17,613 38,079
Operation and maintenance services 37,969 40,293 40,931
---------- --------- ---------
Total operating revenues 1,642,352 893,780 974,991
---------- --------- ---------
Operating Expenses
Fuel 449,137 176,954 192,325
Plant operations 291,463 127,711 132,079
Operation and maintenance services 27,501 28,386 29,314
Depreciation and amortization 190,219 87,339 102,794
Administrative and general 251,165 122,925 124,576
---------- --------- ---------
Total operating expenses 1,209,485 543,315 581,088
---------- --------- ---------
Income from operations 432,867 350,465 393,903
---------- --------- ---------
Other Income (Expense)
Interest and other income 41,694 49,785 27,306
Gain on sale of assets 7,627 1,148 26,642
Interest expense (353,154) (182,901) (210,311)
Dividends on preferred securities (22,375) (13,149) (13,167)
Minority interest (2,954) (2,769) (38,858)
---------- --------- ---------
Total other income (expense) (329,162) (147,886) (208,388)
---------- --------- ---------
Income before income taxes 103,705 202,579 185,515
Provision (benefit) for income taxes (40,412) 70,445 57,363
---------- --------- ---------
Income Before Accounting Change and
Extraordinary Loss 144,117 132,134 128,152
---------- --------- ---------
Cumulative effect on prior years of change in
accounting for start-up costs, net of tax (13,840) -- --
Extraordinary loss on early extinguishment
of debt, net of income tax benefit -- -- (13,126)
---------- --------- ---------
Net Income $ 130,277 $ 132,134 $ 115,026
========== ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
53
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
-----------------------------------------
1999 1998
------------------- -------------------
Assets
Current Assets
Cash and cash equivalents $ 398,695 $ 459,178
Accounts receivable - trade, net of allowance: 254,538 74,403
1999, $1,126; 1998, $0
Accounts receivable - affiliates 9,597 13,871
Inventory 258,864 13,000
Prepaid expenses and other 35,665 46,864
----------- ----------
Total current assets 957,359 607,316
----------- ----------
Investments
Energy projects 1,891,703 1,163,597
Oil and gas 49,173 62,949
----------- ----------
Total investments 1,940,876 1,226,546
----------- ----------
Property, Plant and Equipment 12,533,413 3,125,747
Less accumulated depreciation and amortization 411,079 250,934
----------- ----------
Net property, plant and equipment 12,122,334 2,874,813
----------- ----------
Other Assets
Goodwill 290,695 308,051
Deferred financing costs 133,948 39,452
Restricted cash and other 89,009 101,938
----------- ----------
Total other assets 513,652 449,441
----------- ----------
Total Assets $15,534,221 $5,158,116
=========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
54
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
December 31,
-----------------------------------------
1999 1998
------------------- -------------------
Liabilities and Shareholder's Equity
Current Liabilities
Accounts payable - affiliates $ 7,772 $ 8,339
Accounts payable and accrued liabilities 328,057 99,062
Interest payable 89,272 56,708
Short-term obligations 1,122,067 --
Current maturities of long-term obligations 225,679 194,586
----------- ----------
Total current liabilities 1,772,847 358,695
----------- ----------
Long-Term Obligations Net of Current Maturities 7,439,308 2,396,360
----------- ----------
Long-Term Deferred Liabilities
Deferred taxes and tax credits 1,520,490 613,009
Deferred revenue 534,531 490,471
Accrued incentive compensation 253,513 118,652
Other 468,161 73,369
----------- ----------
Total long-term deferred liabilities 2,776,695 1,295,501
----------- ----------
Total Liabilities 11,988,850 4,050,556
----------- ----------
Preferred Securities of Subsidiaries
Company-obligated mandatorily redeemable
security of partnership holding solely
parent debentures 150,000 150,000
Subject to mandatory redemption 208,840 --
Not subject to mandatory redemption 118,054 --
----------- ----------
Total preferred securities of subsidiaries 476,894 150,000
----------- ----------
Commitments and Contingencies
(Notes 7, 12 and 13)
Shareholder's Equity
Common stock, no par value; 10,000 shares
authorized; 100 shares issued and outstanding 64,130 64,130
Additional paid-in capital 2,629,406 629,406
Retained earnings 364,434 234,345
Accumulated other comprehensive income 10,507 29,679
----------- ----------
Total Shareholder's Equity 3,068,477 957,560
----------- ----------
Total Liabilities and Shareholder's Equity $15,534,221 $5,158,116
=========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
55
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(In thousands)
Additional Accumulated Other
Common Paid-in Retained Comprehensive Comprehensive Shareholder's
Stock Capital Earnings Income Income Equity
-------- ------------- ---------- ------------------ -------------- --------------
Balance at December 31, 1996 $64,130 $ 629,289 $ 262,594 $ 63,892 $1,019,905
Comprehensive income
Net income 115,026 $115,026 115,026
Other comprehensive income
Foreign currency translation
adjustment net of income tax
benefit of $3,933 (33,446) (33,446) (33,446)
--------
Total Comprehensive income 81,580
Cash dividends to parent (197,000) (197,000)
Non-cash dividend (78,000) (78,000)
Non-cash contribution 117 117
-------- ------------- --------- --------- ----------
Balance at December 31, 1997 64,130 629,406 102,620 30,446 826,602
Comprehensive income
Net income 132,134 132,134 132,134
Other comprehensive income
Foreign currency translation
adjustment net of income tax
provision of $52 (767) (767) (767)
--------
Total Comprehensive income 131,367
Stock option price appreciation
on options exercised (409) (409)
-------- ------------- --------- --------- ----------
Balance at December 31, 1998 64,130 629,406 234,345 29,679 957,560
Comprehensive income
Net income 130,277 130,277 130,277
Other comprehensive income
Foreign currency translation
adjustment net of income tax
provision of $1,678 (19,172) (19,172) (19,172)
---------
Total Comprehensive income $111,105
========
Contributions 2,000,000 2,000,000
Stock option price appreciation
on options exercised (188) (188)
-------- ------------- --------- -------- ----------
Balance at December 31, 1999 $64,130 $ 2,629,406 $ 364,434 $ 10,507 $3,068,477
======== ============= ========= ======== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
56
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
------------------------------------------------
1999 1998 1997
----------- --------- -----------
Cash Flows From Operating Activities
Net income $ 130,277 $ 132,134 $ 115,026
Adjustments to reconcile net income to net cash provided by
operating activities
Equity in income from energy projects (218,058) (171,819) (151,306)
Equity in income from oil and gas investments (26,286) (17,613) (38,079)
Distributions from energy projects 188,040 165,206 133,643
Dividends from oil and gas 23,423 19,812 47,849
Depreciation and amortization 190,219 87,339 102,794
Deferred taxes and tax credits 67,741 85,138 (7,994)
Gain on sale of assets (7,627) (1,148) (26,642)
Cumulative effect on prior years of change in accounting
for start-up costs, net of tax 13,840 -- --
Extraordinary loss on early extinguishment of debt,
net of tax benefit -- -- 13,126
Decrease (increase) in accounts receivable (178,803) 6,800 (20,259)
Decrease (increase) in inventory (39,692) (473) 1,710
Decrease (increase) in prepaid expenses and other (11,563) (32,375) 42
Increase in interest payable 32,564 14,081 7,857
Increase (decrease) in accounts payable and accrued liabilities 163,589 (8,648) 66,031
Other, net 89,486 (11,846) 15,679
----------- --------- ----------
Net cash provided by operating activities 417,150 266,588 259,477
----------- --------- ----------
Cash Flows From Financing Activities
Borrowing on long-term obligations 5,267,843 102,450 1,140,588
Payments on long-term obligations (255,718) (84,502) (882,446)
Short-term financing, net 1,114,586 -- --
Issuance of preferred securities 326,168 -- --
Capital contributions from parent 2,000,000 -- --
Cash dividends to parent -- -- (197,000)
Financing costs (89,429) -- (5,781)
----------- --------- ----------
Net cash provided by financing activities 8,363,450 17,948 55,361
----------- --------- ----------
Cash Flows From Investing Activities
Investments in energy projects (13,471) (9,997) (62,034)
Loans to energy projects (84,099) (107,219) (63,406)
Purchase of generating stations (7,958,474) -- --
Purchase of common stock of acquired companies (653,499) (221,985) (63,983)
Capital expenditures (216,440) (73,393) (87,706)
Proceeds from loan repayments 31,661 12,790 160,797
Proceeds from sale of assets 34,833 4,100 71,166
Increase in restricted cash (341) (12,507) (46,275)
Other, net 22,070 (32) 91
----------- --------- ----------
Net cash used in investing activities (8,837,760) (408,243) (91,350)
----------- --------- ----------
Effect of exchange rate changes on cash (3,323) (2,998) (21,239)
----------- --------- ----------
Net increase (decrease) in cash and cash equivalents (60,483) (126,705) 202,249
Cash and cash equivalents at beginning of period 459,178 585,883 383,634
----------- --------- ----------
Cash and cash equivalents at end of period $ 398,695 $ 459,178 $ 585,883
=========== ========= ==========
The accompanying notes are an integral part of these consolidated financial
statements.
57
EDISON MISSION ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions)
Note 1. Organization
- ---------------------
Edison Mission Energy is a wholly owned subsidiary of The Mission Group, a
wholly owned, non-utility subsidiary of Edison International, the parent holding
company of Southern California Edison Company. Through our subsidiaries, we are
engaged in the business of developing, acquiring, owning and operating electric
power generation facilities worldwide.
Note 2. Summary of Significant Accounting Policies
- ---------------------------------------------------
Consolidations
The consolidated financial statements include Edison Mission Energy and its
majority owned subsidiaries, partnerships and a special purpose corporation.
All significant intercompany transactions have been eliminated. Certain prior
year reclassifications have been made to conform to the current year financial
statement presentation.
Management's Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires us to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reported period. Actual results
could differ from those estimates.
Investments
Cash equivalents include time deposits and other investments totaling $213.3
million at December 31, 1999, with maturities of three months or less. All
investments are classified as available-for-sale.
Investments in energy projects and oil and gas with 50% or less voting stock
are accounted for by the equity method. The majority of energy projects and all
investments in oil and gas are accounted for under the equity method at December
31, 1999.
Property, Plant and Equipment
Property, plant and equipment, including leasehold improvements and
construction in progress, are capitalized at cost and are principally comprised
of our majority owned subsidiaries' plants and related facilities. Depreciation
and amortization are computed by using the straight-line method over the useful
life of the property, plant and equipment and over the lease term for leasehold
improvements.
As part of the acquisition of the Illinois Plants and the Homer City plant,
we acquired emission allowances under the Environmental Protection Agency's Acid
Rain Program. Although the emission allowances granted under this program are
freely transferable, we intend to use substantially all of the emission
allowances in the normal course of our business to generate electricity.
Accordingly, we have classified emission allowances expected to be used to
generate power as part of property, plant and
58
equipment. Acquired emissionallowances will be amortized over the estimated
lives of the plants on a straight-line basis.
Useful lives for property, plant and equipment are as follows:
Furniture and office equipment 3 - 10 years
Building, plant and equipment 20 - 60 years
Emission allowances 20 - 40 years
Civil works 40 - 80 years
Capitalized leased equipment 25 years
Leasehold improvements Life of lease
Goodwill
Goodwill represents the cost incurred in connection with the purchase of First
Hydro Company in excess of the fair value of the net assets acquired in December
1995. This amount is being amortized over 40 years on a straight-line basis.
Accumulated amortization was $33.2 million and $25.8 million at December 31,
1999 and 1998, respectively.
Impairment of Investments and Long-Lived Assets
We periodically evaluate the potential impairment of our investments in
projects and other long-lived assets, including goodwill, based on a review of
estimated future cash flows expected to be generated. If the carrying amount of
the investment or asset exceeds the amount of the expected future cash flows,
undiscounted and without interest charges, then an impairment loss for our
investments in projects and other long-lived assets is recognized in accordance
with Accounting Principles Board Opinion No. 18 "The Equity Method of Accounting
for Investments in Common Stock" and Statement of Financial Accounting Standards
No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," respectively.
Capitalized Interest
Interest incurred on funds borrowed by us to finance project construction is
capitalized. Capitalization of interest is discontinued when the projects are
completed and deemed operational. Such capitalized interest is included in
investment in energy projects and property, plant and equipment.
Capitalized interest is amortized over the depreciation period of the major
plant and facilities for the respective project.
Years Ended December 31,
---------------------------------------------------
1999 1998 1997
--------------- --------------- ---------------
Interest incurred $380.6 $209.2 $225.3
Interest capitalized (27.4) (26.3) (15.0)
------- ------- -------
$353.2 $182.9 $210.3
====== ====== ======
Income Taxes
We are included in the consolidated federal income tax and combined state
franchise tax returns of Edison International. We calculate our income tax
provision on a separate company basis under a tax sharing arrangement with The
Mission Group, which in turn has an agreement with Edison
59
International. Tax benefits generated by us and used in the Edison International
consolidated tax return are recognized by us without regard to separate company
limitations.
We account for income taxes using the asset-and-liability method, wherein
deferred tax assets and liabilities are recognized for future tax consequences
of temporary differences between the carrying amounts and the tax bases of
assets and liabilities using enacted rates. Investment and energy tax credits
are deferred and amortized over the term of the power purchase agreement of the
respective project. Income tax accounting policies are discussed further in
Note 9.
Maintenance Accruals
Certain of our plant facilities' major pieces of equipment require major
maintenance on a periodic basis. These costs are accrued for on a straight-line
basis over the expected maintenance period. The maintenance accrual is based on
our estimates of what these events will cost at the time the events occur. Due
to fluctuations in prices and changes in the scope and timing of the work to be
performed, the actual amounts expended may differ from the amounts estimated for
these events.
Project Development Costs
We capitalize only the direct costs incurred in developing new projects
subsequent to being awarded a bid. These costs consist of professional fees,
salaries, permits, and other directly related development costs incurred by us.
The capitalized costs are amortized over the life of operational projects or
charged to expense if management determines the costs to be unrecoverable.
Deferred Financing Costs
Bank, legal and other direct costs incurred in connection with obtaining
financing are deferred and amortized as interest expense on a basis which
approximates the effective interest rate method over the term of the related
debt. Accumulated amortization amounted to $9.7 million in 1999 and $3.7
million in 1998.
Revenue Recognition
We record revenue and related costs as electricity is generated or services
are provided. For our long-term power contracts that provide for higher pricing
in the early years of the contract, revenue is recognized in accordance with
Emerging Issues Task Force Issued Number 91-6 "Revenue Recognition of Long-Term
Sales Contract," which results in a deferral and levelization of revenues being
recognized. Also included in deferred revenues is the deferred gain from the
termination of the Loy Yang B power sales agreement. See Note 4. for further
discussion. Revenues are adjusted for price differentials resulting from its
electricity rate swap agreements in the United States, United Kingdom and
Australia. These rate swap agreements are discussed further in Note 7.
Financial Instruments
We engage in price risk management activities for both trading and non-
trading purposes. Derivative financial instruments are mainly utilized by us to
manage exposure to fluctuations in interest rates, foreign exchange rates, oil
and gas prices and energy prices. Hedge accounting is utilized to account for
financial instruments entered into for non-trading purposes so long as there is
a high degree of correlation between price movements in the derivative and the
item designated as being hedged. For example, the differentials to be paid or
received related to interest rate agreements are recorded as adjustments to
interest expense. The differentials to be paid or received related to
electricity rate swap
60
agreements are currently recorded as adjustments to electric revenues or fuel
expenses. An electricity rate swap agreement is an exchange of a fixed price of
electricity for a floating price. Under hedge accounting, gains and losses on
financial instruments used for hedging purposes are recognized in the
Consolidated Income Statement in the same manner as the hedged item.
Derivative financial instruments that are utilized for trading purposes are
accounted for using the mark-to-market method. Under the mark-to-market method,
forwards, options and other financial instruments with third parties are
reflected at market value, net of future physical delivery related costs. Our
results, a $6.6 million loss for the year ended December 31, 1999, are reflected
net in the accompanying Consolidated Income Statement.
Translation of Foreign Financial Statements
Assets and liabilities of most foreign operations are translated at end of
period rates of exchange and the income statements are translated at the average
rates of exchange for the year. Gains or losses resulting from foreign currency
transactions are normally included in other income in the consolidated
statements of income. Foreign currency transaction losses amounted to $1.7
million, $1.2 million and $2.9 million for 1999, 1998 and 1997, respectively.
Gains or losses from translation of foreign currency financial statements are
included in comprehensive income in shareholder's equity.
Stock-based Compensation
We measure compensation expense relative to stock-based compensation by the
intrinsic-value method.
Note 3. Inventory
- ------------------
Inventory is stated at the lower of weighted average cost or market.
Inventory at December 31, 1999 and December 31, 1998 consisted of the following:
1999 1998
---- ----
Coal and fuel oil $190.1 $ --
Spare parts, materials and supplies 68.8 13.0
------ -----
Total $258.9 $13.0
====== =====
Note 4. Acquisitions
- ---------------------
Acquisition of Illinois Plants
On December 15, 1999, we completed a transaction with Commonwealth Edison to
acquire Commonwealth Edison's fossil-fuel power generating assets, which are
commonly referred to as the Illinois Plants. We will operate these plants, which
provide access to Mid-America Interconnected Network and the East Central Area
Reliability Council. In connection with this transaction, we entered into power
purchase agreements with Commonwealth Edison with a term of up to five years,
pursuant to which Commonwealth Edison will purchase capacity and have the right
to purchase energy generated by the plants.
Concurrent 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 this transaction with Commonwealth Edison Company is 9,510
MW.
61
Consideration for the Illinois Plants, excluding $860 million paid by a third
party to acquire the Collins Station, consisted of a cash payment of
approximately $4.1 billion. The acquisition was funded primarily with a
combination of approximately $1.6 billion of non-recourse debt secured by a
pledge of the stock of specified subsidiaries, $1.3 billion of our debt and $1.2
billion in equity contributions from Edison International.
Acquisition of Ferrybridge and Fiddler's Ferry Plants
On July 19, 1999, we completed a transaction with PowerGen UK plc, to acquire
the Ferrybridge and Fiddler's Ferry coal-fired electric generating plants
located in the United Kingdom. Ferrybridge, located in West Yorkshire, and
Fiddler's Ferry, located in Warrington, each has a generating capacity of
approximately 2,000 MW.
Consideration for Ferrybridge and Fiddler's Ferry consisted of approximately
$2.0 billion (1.3 billion pounds Sterling) for the two plants. The acquisition
was funded primarily with a combination of net proceeds of $1.3 billion (830
million pounds sterling) from the Edison First Power Limited Guaranteed Secured
Variable Rate Bonds issued on July 19, 1999 and due 2019, cash and a $500
million equity contribution from Edison International. The Edison First Power
Bonds were issued to a special purpose entity formed by Merrill Lynch
International. Merrill Lynch International sold the variable rate coupons
portion of the bonds to a special purpose entity that borrowed $1.3 billion (830
million pounds sterling) under a Term Loan Facility due 2012 to finance the
purchase.
Acquisition of Interest in Contact Energy
On May 14, 1999, we completed a transaction with the New Zealand government to
acquire 40% of the shares of Contact Energy Limited. The remaining 60% of
Contact Energy's shares were sold in 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 hydroelectric, geothermal and natural gas-fired
power generating plants primarily in New Zealand with a total current generating
capacity of 2,626 MW.
Consideration for Contact Energy consisted of a cash payment of approximately
$635 million (1.2 billion New Zealand dollars), which was financed by $120
million of preferred stock, a $214 million (400 million New Zealand dollars)
credit facility, a $300 million equity contribution from Edison International
and cash. The credit facility was subsequently paid off with proceeds form the
issuance of preferred securities.
Acquisition of Homer City Plant
On March 18, 1999, we completed a transaction with GPU, Inc., New York State
Electric & Gas Corporation and their respective affiliates to acquire the 1,884-
MW Homer City Electric Generating Station. This facility is a coal-fired plant
in the mid-Atlantic region of the United States and has direct, high voltage
interconnections to both the New York Independent System Operator, which
controls the transmission grid and energy and capacity markets for 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.
Consideration for the Homer City plant consisted of a cash payment of
approximately $1.8 billion, which was partially financed by $1.5 billion of new
loans, combined with our revolver borrowings and cash.
62
Acquisition of Interest in EcoElectrica
In December 1998, we acquired 50% of the 540-MW EcoElectrica liquefied natural
gas combined-cycle cogeneration facility under construction in Penuelas, Puerto
Rico for approximately $243 million. The project also includes a desalination
plant and liquefied natural gas storage and vaporization facilities and is
expected to commence commercial operation during the first quarter of 2000.
Acquisition of Loy Yang B Plant
In 1992, we acquired 51% of the 1,000-MW Loy Yang B Power Station from the
State Government of Victoria. In connection with the 1992 acquisition, we
entered into a 30-year power purchase agreement with the State Electricity
Commission of Victoria, under which the State Electricity Commission of Victoria
purchased our share of the plant output. Loy Yang B's principal assets are two
500-MW brown-coal-fired units located near Melbourne, Australia.
In May 1997, we acquired the State Government of Victoria's 49% interest in
Loy Yang B as part of the privatization process in the State of Victoria.
Consideration for the 49% interest consisted primarily of a cash payment of
approximately $64 million (84 million Australian dollars) and termination of an
existing 33-year power purchase agreement and other related agreements. The
transaction value totaled approximately $686 million (900 million Australian
dollars), which was based primarily on the value of the 49% interest in the
power plant using comparable information from sales of other power projects in
the region. As part of the transaction, we entered into a series of new power
related agreements for a 17-year period at market prices. As we previously
consolidated the Loy Yang B project with a minority interest held by the State
Government of Victoria, the acquisition of the remaining 49% resulted in: (1)
an increase to property plant and equipment of approximately $18 million (24
million Australian dollars), (2) elimination of the State of Government of
Victoria's minority interest of approximately $668 million (876 million
Australian dollars) and (3) an increase of approximately $622 million (816
million Australian dollars) in deferred revenues attributable to the deferral of
the gain associated with the termination of the power sales agreement. The
deferred gain is being amortized over the life of the power purchase agreements.
Each of the acquisitions has been accounted for utilizing the purchase method.
The purchase price was allocated to the assets acquired and liabilities assumed
based on their respective fair market values. The financial statements of the
Homer City plant and Illinois Plants reflect the preliminary allocation of the
purchase price. The allocation has not been finalized relative to specified
valuations and related intangibles. Our consolidated statement of income
reflects the operations of the Homer City Plan beginning March 18, 1999, Contact
Energy beginning May 1, 1999, Ferrybridge and Fiddler's Ferry plants beginning
July 19, 1999, and the Illinois Plants beginning December 15, 1999. The
consolidated statement of income for 1997 reflects the operations under the new
contracts and the elimination of the minority interest of the Loy Yang B plant
beginning on May 9, 1997.
Pro Forma Data
The following unaudited pro forma data summarizes the consolidated results of
operations for the periods indicated as if the acquisition of the Ferrybridge
and Fiddler's Ferry plants had occurred at the beginning of 1999 and 1998 and
the acquisition of the 49% interest in the Loy Yang B plant had occurred at the
beginning of 1997. The pro forma data gives effect to certain adjustments
including electric revenues, fuel expense, plant operations, depreciation and
amortization, interest expense and related income tax adjustments. These
results have been prepared for comparative purposes only and do not purport to
be indicative of what would have occurred had the acquisitions been made at the
beginning of 1999, 1998, 1997 or of the results which may occur in the future.
Pro forma data has not
63
been provided for the acquisitions of the Homer City plant and the Illinois
Plants because these plants were previously operated as part of an integrated,
regulated utility whose primary business was the sale of power bundled with
transmission, distribution and customer support to retail customers.
Accordingly, historical financial results of these plants would not be
meaningful and are not required due to the acquisitions not being considered
business combinations.
(Unaudited)
Years Ended December 31,
------------------------
1999 1998 1997
---- ----- ----
Operating revenues $1,889.9 $1,447.9 $939.9
Income before accounting change and extraordinary loss 126.2 95.7 143.9
Net income 112.4 95.7 130.8
The table below summarizes additional acquisitions by Edison Mission Energy or
its wholly owned subsidiaries from 1997 through 1999.
Percentage Purchase
Date Acquisition Acquired Price
- ---- ----------- ----------- -----------
Energy Projects
October 5, 1999 Pride Hold Limited 20.0% $16.0
July 10, 1998 Tri Energy Company Limited 25.0% 1.5
Oil and Gas
December 17, 1999 Four Star Oil & Gas Company 0.6% 2.3
January 1, 1998 Four Star Oil & Gas Company 3.2% 4.1
Note 5. Investments
- -------------------
Investments in Energy Projects
Investments in energy projects, generally 50% or less owned partnerships and
corporations, are accounted for by the equity method. The difference between
the carrying value of energy project investments and the underlying equity in
the net assets amounted to $656.1 million at December 31, 1999. The differences
are being amortized over the life of the projects. The following table presents
summarized financial information of the investments in energy projects:
December 31,
---------------------------------------------
1999 1998
--------------------- ---------------------
Domestic energy projects
Equity investment $ 413.6 $ 618.0
Loans receivable 163.0 160.2
-------- --------
Subtotal 576.6 778.2
International energy projects
Equity investment 1,079.1 233.4
Loans receivable 236.0 152.0
-------- --------
Subtotal 1,315.1 385.4
-------- --------
Total $1,891.7 $1,163.6
======== ========
64
Our subsidiaries have provided loans or advances related to certain projects.
Domestic loans at December 31, 1999 consist of the following: a $97.5 million,
10% interest loan; a $26.3 million, 5% interest promissory note, payable
semiannually, due April 2008; a $11.1 million, 8.8% interest loan; and a $28.1
million, 12% interest loan. International loans at December 31, 1999 consists
of a $236 million, LIBOR + 2.25% interest loan (8.5% at December 31, 1999).
The undistributed earnings of investments accounted for by the equity method
were $223.9 million in 1999 and $176.4 million in 1998.
The following table presents summarized financial information of the
investments in energy projects accounted for by the equity method:
Years Ended December 31,
------------------------------------------
1999 1998 1997
-------- -------- --------
Revenues $2,031.8 $1,585.7 $1,593.4
Expenses 1,590.2 1,255.6 1,294.7
-------- -------- --------
Net income $ 441.6 $ 330.1 $ 298.7
======== ======== ========
December 31,
-------------------------
1999 1998
-------- --------
Current assets $ 722.3 $ 520.6
Noncurrent assets 7,728.2 5,315.0
-------- --------
Total assets $8,450.5 $5,835.6
======== ========
Current liabilities $1,584.8 $1,028.6
Noncurrent liabilities 4,769.7 3,540.8
Equity 2,096.0 1,266.2
-------- --------
Total liabilities and equity $8,450.5 $5,835.6
======== ========
The majority of noncurrent liabilities are comprised of project financing
arrangements that are non-recourse to us.
The following table presents, as of December 31, 1999, the energy projects
accounted for by the equity method that represent at least five percent (5%) of
our income before tax or in which we have an investment balance greater than $50
million.
Ownership
Energy Project Location Investment Interest Operating Status
- -------------- -------- ---------- ---------- ----------------
Contact Energy New Zealand $616.8 40% Operating hydro, natural
gas and geothermal facilities
Paiton East Java, Indonesia 418.6 40% Operating coal-fired facility
EcoElectrica Penuelas, Puerto Rico 266.3 50% Liquefied natural gas
facility under construction
Watson Carson, CA 110.8 49% Operating cogeneration facility
Brooklyn Navy Yard Brooklyn, NY 77.3 50% Operating cogeneration facility
Sycamore Bakersfield, CA 66.7 50% Operating cogeneration facility
Midway-Sunset Fellows, CA 54.5 50% Operating cogeneration facility
Kern River Bakersfield, CA 48.6 50% Operating cogeneration facility
Harbor Wilmington, CA 30.6 30% Operating merchant facility
March Point Anacortes, WA 19.0 50% Operating cogeneration facility
James River Hopewell, VA 16.3 50% Operating coal-fired
65
Ownership
Energy Project Location Investment Interest Operating Status
- -------------- -------- ---------- ---------- ----------------
cogeneration facility
Saguaro Henderson, NV 14.3 50% Operating cogeneration facility
At December 31, 1999, the quoted market value of our investment in Contact
Energy was $422.5 million. The valuation represents a calculation based on the
closing stock price of Contact Energy on the New Zealand stock exchange and is
not necessarily indicative of the amount that could be realized upon sale.
Investments in Oil and Gas
At December 31, 1999, we had one 34.88% owned (with 33.48% voting stock) and
one 50% owned investment in oil and gas. These investments are accounted for
utilizing the equity method. The difference between the carrying value of one
oil and gas investment and the underlying equity in the net assets amounted to
$12.8 million at December 31, 1999. The difference is being amortized on a unit
of production basis over the life of the reserves. The following table presents
summarized financial information of the investments in oil and gas:
Years Ended December 31,
--------------------------------
1999 1998 1997
------ ------ -------
Operating revenues $224.3 $211.3 $304.7
Operating expenses 144.5 164.1 197.4
------ ------ ------
Operating income 79.8 47.2 107.3
Provision (credit) for income taxes 16.9 (2.3) 18.5
------ ------ ------
Net income (before non-operating items) 62.9 49.5 88.8
Non-operating expense, net (10.4) (13.5) (12.8)
------ ------ ------
Net income $ 52.5 $ 36.0 $ 76.0
====== ====== ======
December 31,
-----------------------
1999 1998
------ ------
Current assets $ 47.0 $ 81.5
Noncurrent assets 377.2 384.7
------ ------
Total assets $424.2 $466.2
====== ======
Current liabilities $ 22.7 $111.4
Noncurrent liabilities 238.6 226.9
Deferred income taxes and other liabilities 48.1 42.0
Equity 114.8 85.9
------ ------
Total liabilities and equity $424.2 $466.2
====== ======
During the fourth quarter of 1999, we completed a sale of a portion of our
interest in Four Star Oil & Gas Company 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 and we recorded a pre-tax gain of approximately six million dollars and
an after-tax gain of approximately $30 million.
Note 6. Property, Plant and Equipment
- --------------------------------------
Property, plant and equipment consist of the following:
66
December 31,
----------------------
1999 1998
--------- --------
Buildings, plant and equipment $ 9,957.1 $1,756.5
Emission allowances 1,310.9 --
Civil works 956.5 1,009.2
Construction in progress 108.8 164.0
Capitalized leased equipment 200.1 196.0
--------- --------
12,533.4 3,125.7
Less accumulated depreciation and amortization 411.1 250.9
--------- --------
Net property, plant and equipment $12,122.3 $2,874.8
========= ========
In connection with the Homer City plant financing and the Loy Yang B plant
financing, lenders have taken a security interest in the respective plant
assets.
Note 7. Financial Instruments
- ------------------------------
Short-Term Obligations
December 31,
----------------------
1999 1998
--------- --------
Commercial Paper $1,130.0 $ --
Unamortized discount (7.9) --
-------- --------
Total $1,122.1 $ --
======== ========
Weighted-average interest rate at 12/31/99 6.9% --
Commercial paper consists of a $700 million facility due March 2000 and a
$500 million facility due November 2000, of which $630 million and $500 million
are outstanding, respectively, at December 31, 1999. Both facilities represent
recourse debt and are indexed to LIBOR.
Long-Term Obligations
Long-term obligations include both corporate debt and non-recourse project
debt, whereby lenders rely on specific project assets to repay such obligations.
At December 31, 1999, recourse debt totaled $1.5 billion and non-recourse
project debt totaled $6.2 billion. Long-term obligations consist of the
following:
December 31,
--------------------
1999 1998
--------- --------
Recourse
Edison Mission Energy (parent only)
Senior Notes, net
due 1999 (7.75%) $ -- $ 99.9
due 2002 (8.125%) 99.6 99.4
due 2009 (7.73%) 596.1 --
Floating Rate Notes, net due 2001
(LIBOR+0.67%) (6.79% at 12/31/99) 499.5 --
Bank of America NT&SA Credit Agreement due 2001
(LIBOR+0.175%) (6.615% at 12/31/99) 215.0 --
67
Non-recourse (unless otherwise noted)
Edison Mission Energy Funding Corp.
Series A Notes, net due 1997-2003 (6.77%) 168.1 198.8
Series B Bonds, net due 2004-2008 (7.33%) 189.0 188.9
Edison Mission Holdings Co.
Senior Secured Bonds - $300 MM due 2019 (8.137%) 300.0 --
Senior Secured Bonds - $530 MM due 2026 (8.734%) 530.0 --
Construction Loan due 2004
(LIBOR+1.0%) (7.131% at 12/31/99) 77.0 --
Edison Mission Midwest Holdings Co.
Tranche A due 2002 (LIBOR+1.0%)
(7.469% at 12/31/99) 840.0 --
Tranche B due 2004 (LIBOR+0.95%)
(7.419% at 12/31/99) 839.0 --
Doga project
Finance Agreement between Doga and OPIC due 2010
(U.S. Treasury Note+3.75%) (9.86% at 12/31/99) 90.9 81.2
NCM Credit Agreement due 2010
(U.S. LIBOR+1.25%) (7.251% at 12/31/99) 33.5 29.9
Ferrybridge and Fiddler's Ferry plants
(Pounds Sterling)830 MM pounds sterling Term Loan
Facility due 2012 (sterling LIBOR+1.5%)
(6.885% at 12/31/99) 1,312.0 --
Pounds sterling Coal and Capex Facility due 2004 -
recourse (sterling LIBOR+0.75%+0.145%)
(6.791% at 12/31/99) 22.6 --
First Hydro plants
First Hydro Finance plc (Pounds)400 MM Guaranteed
Secured Bonds due 2021 (9%) 645.2 665.1
(Pounds Sterling)18 MM Credit Agreement due 2003
(sterling LIBOR+0.5638%) (6.124% at 12/31/99) 29.0 29.9
Iberian Hy-Power plants
Spanish peseta Project Finance Credit Facility due 2012
(MIBOR + 0.75%) (4.089% at 12/31/99) 53.9 79.3
Spanish peseta Subordinated Loan due 2003 (9.408%) 15.3 25.1
Spanish peseta Compagnie Generale Des Eaux due 2003 31.9 22.7
(non-interest bearing)
Kwinana plant
Australian dollar Syndicated Project Facility Agreement
due 2012 (BBR+1.2%) (6.32% at 12/31/99) 62.4 60.6
Loy Yang B plant
Australian dollar Amortizing Term Facility due 2017
(BBR+0.5% to 1.1%) (5.66% at 12/31/99) 321.2 299.3
Australian dollar Interest Only Term Facility due 2012
68
(BBR+0.5% to 0.85%) (5.66% at 12/31/99) 484.6 461.4
Australian dollar Working Capital Facility due 2017
(BBR+0.5% to 1.1%) (5.66% at 12/31/99) 6.6 6.1
Roosecote plant
Pounds sterling Term Loan and Guarantee Facility due 2005
(Sterling LIBOR + 0.6%) (6.678% at 12/31/99) 97.8 92.2
Capital lease obligation (see Note 13) 22.8 48.4
Other long-term obligations - recourse 82.0 102.8
-------- --------
Subtotal $7,665.0 $2,591.0
Current maturities of long-term obligations (225.7) (194.6)
-------- --------
Total $7,439.3 $2,396.4
======== ========
At December 31, 1999, we had available $159.6 million of borrowing capacity
and approximately $125.4 million in letters of credit issued under a $500
million revolving credit facility that expires in 2001.
Financing of the Homer City Plant
In March 1999, Edison Mission Holdings Co., an indirect, wholly owned
affiliate of Edison Mission Energy, closed a $1.1 billion financing in
connection with the acquisition of the Homer City plant. The financing consists
of (1) an $800 million, 364-day term loan facility, (2) a $250 million, five-
year term loan facility and (3) a $50 million, five-year revolving credit
facility. These loans are structured on a limited-recourse basis in which the
lenders look primarily to the cash generated by the Homer City plant to repay
the debt and have taken a security interest in the Homer City plant assets. We
will use amounts available under the $250 million five-year term loan facility
to fund environmental capital improvements at the Homer City plant and use
amounts available under the $50 million five-year revolving credit facility for
general working capital purposes. As of December 31, 1999, there were no
amounts outstanding under the $50 million five-year revolving credit facility.
In May 1999, Edison Mission Holdings Co. completed an $830 million bond
financing. The financing consists of (1) $300 million, 8.137% Senior Secured
Bonds due 2019 and (2) $530 million, 8.734% Senior Secured Bonds due 2026.
These bonds are non-recourse to us apart from the Credit Support Guarantee and
Debt Service Reserve Guarantee entered into by us. The Credit Support Guarantee
requires us to guarantee the payment and performance of the obligations of
Edison Mission Holdings Co. to the bond holders, banks and other secured parties
which financed the acquisition of the Homer City plant in an aggregate amount
not to exceed approximately $42 million. This guarantee is to remain in place
until December 31, 2001. In addition, to satisfy the requirements under the
Edison Mission Holdings Co. financing to have a Debt Service Reserve Requirement
in an amount equal to six months' debt service projected to be due following the
payment of a distribution, we agreed to guarantee the payment and performance of
the obligations of Edison Mission Holdings Co. in the amount of approximately
$35 million pursuant to the Debt Service Reserve Guarantee. The proceeds of the
$830 million bonds were used primarily to repay Edison Mission Holdings Co.'s
$800 million, 364-day interest only term loan.
Financing of the Ferrybridge and Fiddler's Ferry Plants
69
In July 1999, Edison First Power Limited, an indirect, wholly owned affiliate
of Edison Mission Energy, issued Edison First Power Bonds due 2019. The bonds
are guaranteed by us. The Edison First Power Bonds were issued to a special
purpose entity formed by Merrill Lynch International, which sold the variable
rate coupons portion of the bonds to another special purpose entity that
borrowed $1.3 billion (830 million pounds sterling) under a Term Loan Facility
to finance the purchase. The Term Loan Facility accrues interest at sterling
LIBOR plus 1.50 to 1.90% and is repaid in semi-annual installments over a 12-
year period beginning December 1999. As part of the financing of the
Ferrybridge and Fiddler's Ferry plants, we also entered into a $579 million (359
million pounds sterling) Coal and Capex Facility due January 2004 and July 2004,
respectively, and a $32 million (20 million pounds sterling) working capital
facility available through September 2019. As of December 31, 1999, there were
no amounts outstanding under the working capital facility.
We have entered into various undertakings to support financial commitments
related to the acquisition of the Ferrybridge and Fiddler's Ferry plants,
including (1) a guaranty of a letter of credit facility of $228.8 million
entered into by Edison Mission Energy Finance UK Limited, an indirect, wholly
owned affiliate of Edison Mission Energy, to support Edison First Power
Limited's commitments: (a) to make certain construction costs arising from plant
modifications, and (b) under a multi-year coal supply agreement; and (2)
issuance of a $87.2 million letter of credit under our corporate revolving
credit line to serve as a debt service reserve account to support debt service
payments under the Guaranteed Secured Variable Rate Bonds due 2019.
In January 2000, Edison Capital, a wholly owned subsidiary of Edison
International, provided $243 million (150 million pounds sterling) of
subordinated financing to Edison First Power Holdings I, an indirect, wholly
owned affiliate of Edison Mission Energy. The coupon bearing interest sums are
due January 2024 at a coupon rate of 11.79%. The proceeds may be used for
investments in future projects by Edison First Power Holdings I.
Financing of the Illinois Plants
In December 1999, Edison Mission Midwest Holdings Co., an indirect, wholly
owned affiliate of Edison Mission Energy, closed a $1.7 billion financing in
connection with the acquisition of the Illinois Plants. The financing consists
of (1) an $840 million revolving credit facility due 2002, commonly referred to
as Tranche A, and (2) an $839 million revolving credit facility due 2004,
commonly referred to as Tranche B. In addition, at December 31, 1999, there was
$150 million of borrowing capacity available under a working capital revolving
facility, commonly referred to as Tranche C, at LIBOR + 0.95% due 2004. These
credit facilities are structured on a non-recourse basis, in which the debt is
secured by a pledge of stock of specified subsidiaries.
In December 1999, as part of the financing of the Illinois Plants, we also
issued $500 million floating rate notes due 2001 and borrowed $215 million under
our $500 million revolving credit facility that expires in 2001.
Financing of the Loy Yang B Plant
In May 1997, we closed financing of $964 million (1.265 billion Australian
dollars) in connection with the acquisition of the remaining 49% interest in the
Loy Yang B plant. The proceeds received were used to repay Loy Yang B's
existing debt facilities of $713 million (935.5 million Australian dollars) with
the balance used to finance the acquisition and to return funds to various
affiliates of Edison Mission Energy. The financing consists of (1) a $373
million (490 million Australian dollars) 15-year interest only term facility,
(2) a $583 million (765 million Australian dollars) 20-year amortizing term
facility with principal and interest payments scheduled quarterly commencing
September 30, 1998, and
70
(3) an $8 million (10 million Australian dollars) working capital facility with
a term equal to that of the 20-year amortizing term facility. The financing was
structured on a non-recourse basis. Lenders look solely to the operating cash
proceeds of the Loy Yang B plant to repay the debt and have taken a security
interest in the Loy Yang B plant assets. The early repayment of Loy Yang B's
existing debt facilities of $713 million resulted in an extraordinary loss of
$13.1 million (net of income tax benefit of $8.6 million) attributable to the
write-off of unamortized debt issue costs.
Annual maturities on long-term debt at December 31, 1999, for the next five
years, excluding capital leases (see Note 13) are summarized as follows: 2000 -
$203.6 million; 2001 - $688.1 million; 2002 - $1,123.5 million; 2003 - $244.8
million; 2004 - $1,136.8 million. The current portion of Roosecote debt is
included in long-term debt, as proceeds from future borrowings will exceed the
current portion under terms of the Term Loan and Guarantee Facility.
Certain cash balances are restricted primarily to pay amounts required for
debt payments and letter of credit expenses. The total restricted cash in
Restricted cash and other assets was $69.9 million at December 31, 1999 and
$72.1 million at December 31, 1998.
Debt service reserves classified in Restricted cash and other assets
(including reserves for interest on annual lease payments) were $69.7 million at
December 31, 1999 and $66.2 million at December 31, 1998.
Each of our direct or indirect subsidiaries is organized as a legal entity
separate and apart from Edison Mission Energy and its other subsidiaries. Any
asset of any such subsidiary may not be available to satisfy our obligations or
any of our other such subsidiaries; provided, however, that unrestricted cash or
other assets which are available for distribution may, subject to applicable law
and the terms of financing arrangements of such parties, be advanced, loaned,
paid as dividends or otherwise distributed or contributed to us or affiliates
thereof.
Other Financial Instruments
Electric power generated at our uncontracted plants is generally sold under
bilateral arrangements with utilities and power marketers under short-term
contracts with terms of two years or less, or in the case of the Homer City
plant, to the PJM or the NYISO. We have developed risk management policies and
procedures which, among other matters, address credit risk. When making sales
under negotiated bilateral contracts, it is our policy to deal with investment
grade counterparties. We hedge a portion of the electric output of our merchant
plants, whose output is not committed to be sold under long term contracts, in
order to lock in desirable outcomes. When appropriate, we manage the "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 plants 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. The First Hydro and Ferrybridge and Fiddler's
Ferry plants 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. In July 1998, the UK Director General of Electricity Supply
proposed to the Minister for Science, Energy and Industry that the current
structure of
71
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
markets. The Minister for Science, Energy and Industry has recommended that the
proposal be implemented by the end of October 2000. 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. As a result of this event and the introduction of a "good
behavior" clause discussed below, 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. 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 large generators to
curb the perceived exercise of market power in the determination of wholesale
electricity prices. After seeking and receiving specific assurances from the
Regulator on the definition of market abuse and the way the clauses will be
interpreted in the future, we have accepted the new clause.
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. At
December 31, 1999, we had entered into a series of power call options in
connection with the Homer City plant. Based on year-end forward prices, we had
a net deferred gain of $3.5 million on those contracts.
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.
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
72
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.
Our risk management policy allows for the use of these contracts and other
derivative financial instruments to limit financial exposure on its investments
and to manage exposure to fluctuations in interest rates, foreign exchange
rates, oil and gas prices and energy prices but prohibits the use of these
instruments for speculative investment purposes.
We had the following derivative financial instruments at December 31, 1999 and
1998, except where noted:
Category Contract Amount/Terms Purpose
- -------- --------------------- -------
Interest rate swaps
Edison Mission Energy $100 million expiring in 2002 Convert fixed-rate debt of 6.22%
(parent only) $100 million expired in June 1999 to a floating rate (LIBOR), such
floating rate capped at 9.0%
$45 million expired in November 1999, Convert fixed-rate debt of
corresponding preferred securities due 9.875% to a floating rate (LIBOR)
2024
Edison Mission Energy $50 million New Zealand dollars Change floating rate (BBR) debt
Taupo Limited (U.S. $26.1 million) expiring 2001 to a fixed rate of 6.5%
Iberian Hy-Power plants 10.8 billion Spanish pesetas Change floating rate (LIBOR)
(U.S. $65 million) expiring in 2007 debt to a fixed rate of 6.07%
Kwinana plant 37.9 million Australian dollars Change floating-rate (BBR) debt
(12/31/99) (U.S. $24.8 million); 39.4 to a fixed rate of 10.98%
million Australian dollars (12/31/98)
(U.S. $24 million), expiring in 2007
Loy Yang B plant 1.2 billion Australian dollars (U.S. $787 Change floating-rate (BBR) debt
million) expiring 2002-2007; 1.2 billion to fixed rates ranging from
Australian dollars (12/31/98) (U.S. $733 7.51% to 7.93%
million), expiring 2002-2008
73
Interest rate collar
Iberian Hy-Power plants 11.7 billion Spanish pesetas (12/31/98) Change interest rate exposure to
(U.S. $82 million), expired December 1999 float within range from 4.5%
minimum to 7.5% maximum
Electricity rate swaps
Ferrybridge and Approximately 2,300 MW related to winter Change the variable market
Fiddler's Ferry plants months (October through March) and 900 MW electricity sales rates to fixed
related to summer months (April through rates
September) of electrical generation under
selling pricing contracts (12/31/99);
expiring at various dates through 2000
First Hydro plants Approximately 1,400 MW related to winter Change the variable market
months (October through March) and 200 MW electricity sales rates to fixed
related to summer months (April through rates
September) of electrical generation under
selling pricing and capacity only
contracts (12/31/99); 2,095 MW related to
winter months and 1,691 MW related to
summer months (12/31/98); expiring at
various dates through 2000 and 2001
Approximately 2,100 MW related to winter
months and 900 MW related to summer Change the variable market
months of electricity under purchasing electricity sales rates to fixed
pricing contracts (12/31/99); 1,120 MW rates
related to winter months and 860 MW
related to summer months (12/31/98);
expiring at various dates through 2000
and 2001
Loy Yang B plant Approximately 920 MW of electrical Change the variable market
generation under selling pricing electricity sales rates to fixed
contracts expiring at various dates rates
through 2000; approximately 723 MW of
electrical generation under selling
pricing contracts expiring at various
dates between 2001 and 2014;
approximately 520 MW of electrical
generation under selling pricing
contracts expiring at various dates
between 2014 and 2016 (12/31/99 and
12/31/98)
Power call options
Homer City plant Approximately 1,872,000 megawatt hours of Change the variable market
electrical generation under selling electricity sales rates to fixed
pricing contracts expiring at various rates
dates through 2001;
74
approximately 648,000 megawatt hours of
electrical generation under purchasing
pricing contracts expiring at various
dates through 2001 (12/31/99)
Fair values of financial instruments were:
December 31,
------------------------------------------
1999 1998
--------------------- -------------------
Carrying Fair Carrying Fair
Instruments Amount Value Amount Value
- ----------- -------- ---------- -------- --------
Long-term receivables $ 7.6 $ 6.4 $ 6.9 $ 6.8
Electricity rate swap agreements -- (37.2) -- 19.2
Power call options 3.5 3.5 -- --
Long-term obligations 7,439.3 7,430.4 2,396.4 2,323.2
Interest rate swap/collar agreements -- (7.2) -- (83.1)
The Ferrybridge and Fiddler's Ferry plants have entered into forward-starting
interest rate caps in order to fix the interest rate on a portion of the long-
term debt outstanding. The cap period commences on March 20, 2000 and matures
on September 20, 2005. The notional amount of the cap is based on an amortizing
loan profile. The notional amount at March 20, 2000 is 388.4 million pounds
sterling (U.S. $626.4 million). As of December 31, 1999, the fair value of this
cap was $12.2 million dollars, which has been reflected in the table above.
In addition, the Loy Yang B plant has entered into forward-starting interest
rate swaps in order to fix the interest rate on a portion of the long-term debt
outstanding. The swaps period commences in May 2002, maturing on various dates
in 2008-2009. The notional amount of the swaps is based on an amortizing loan
profile. The notional amount in May 2002 is 250 million Australian dollars
(U.S. $163.9 million). As of December 31, 1999, the fair value of this swaps
was $11.1 million dollars, which has been reflected in the table above.
The fair values for long-term receivables, interest rate swap/cap agreements,
interest rate collar and long-term obligations are based primarily on quoted
market prices. The carrying amounts reported for cash equivalents, commercial
paper facilities and other short-term debt approximate fair value due to their
short maturities.
The fair value of the electricity rate swaps agreements entered into by
Ferrybridge and Fiddler's Ferry, First Hydro and the Loy Yang B plants has been
estimated by discounting the future cash flows on the difference between the
average aggregate contract price per MW and a forecasted market price per MW,
multiplied by the amount of MW sales remaining under contract.
The fair value of the commodity contracts (power call options) considers
quoted marked prices, time value, volatility of the underlying commodities and
other factors.
Credit Risk
75
Our financial instruments and power sales contracts involve elements of credit
risk. Credit risk relates to the risk of loss that we would incur as a result of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The counterparties to financial instruments and contracts consist
of a number of major financial institutions and domestic and foreign utilities.
Our attempts to mitigate this risk by entering into contracts with
counterparties that have a strong capacity to meet their contractual obligations
and by monitoring the credit quality of these financial institutions and
utilities. The currency crisis in Indonesia has raised concerns over the ability
of the state owned utility to meet its obligations under the current power sales
contract with our Paiton project as discussed further in Note 12. In addition,
we enter into contracts whereby the structure of the contracts minimizes its
credit exposure. Accordingly, we, with the exception of the Paiton project, do
not anticipate any material impact to its financial position or results of
operations as a result of counterparty nonperformance.
The electric power generated by some of our domestic operating projects,
excluding the Homer City plant and the Illinois Plants, is sold to electric
utilities under long-term, typically with terms of 15 to 30-years, power
purchase agreements and is expected to result in consistent cash flow under a
wide range of economic and operating circumstances. To accomplish this, we
structure our long-term contracts so that fluctuations in fuel costs will
produce similar fluctuations in electric and/or steam revenues and enter into
long-term fuel supply and transportation agreements. In addition, we have
plants located in different geographic areas in order to mitigate the effects of
regional markets, economic downturns or unusual weather conditions.
Note 8. Preferred Securities
- ------------------------------
Company-Obligated Mandatorily Redeemable Security of Partnership Holding
Solely Parent Debentures. In November 1994, Mission Capital, L.P., a limited
partnership of which Edison Mission Energy is the sole general partner, issued
3.5 million 9.875% Cumulative Monthly Income Preferred Securities, Series A at a
price of $25 per security. These securities are redeemable at the option of
Mission Capital, in whole or in part, beginning November 1999, with mandatory
redemption in 2024 at a redemption price of $25 per security, plus accrued and
unpaid distributions. No securities 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.
76
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 $100,000 per
share, plus accumulated and unpaid dividends. Pursuant to this right of optional
redemption, we may elect to redeem all or less than all of the shares of a
Series without redeeming shares of any other Series. Notwithstanding the
foregoing, if any dividends on shares of any Series are in arrears, no shares of
any Series shall be redeemed unless all outstanding shares are simultaneously
redeemed, and we shall not purchase or otherwise acquire any shares of any
Series; provided, however, that the foregoing shall not prevent the purchase or
acquisition of shares pursuant to any otherwise lawful purchase or exchange
offer made on the same terms to holders of all outstanding shares of such
Series.
We entered into a support agreement with Edison Mission Energy Global
Management that requires us to make capital contributions to Edison Mission
Energy Global Management in order for it to maintain a positive net worth and to
provide sufficient funds for payment of declared dividends on preferred stock
and any redemption price in respect of the preferred stock. Our maximum
obligation under the support agreement is limited to either (1) an amount equal
to twice the sum of (a) the liquidation preference of the preferred stock,
currently approximately $240 million, and (b) the liquidation preference of all
outstanding shares of stock of the subsidiary ranking on a parity with the
preferred stock, currently zero, or (2) the amount that we could lawfully
distribute to our shareholder under the Corporations Code of the State of
California, approximately $364 million as of December 31, 1999.
Subject to Mandatory Redemption. During June 1999, Edison Mission Energy
Taupo Limited, a New Zealand corporation, an indirect, wholly owned affiliate of
Edison Mission Energy, issued $84 million of Class A Redeemable Preferred Shares
(16,000 shares at a price of 10,000 New Zealand dollars per share). The
dividend rate ranges from 6.19% to 6.86%. The shares are redeemable in June
2003 at 10,000 New Zealand dollars per share. If an event of default occurs at
any time without prejudice to any other remedies which the redeemable preferred
share subscriber may have, the redeemable preferred share subscriber may, by
notice to the issuer, require redemption of, and the issuer must redeem, the
redeemable preferred shares on the date specified in that notice. Each dividend
will rank for payment in priority to the rights in respect of dividends and the
rights, if any, in respect of interest on arrears thereof of all holders of
other classes of shares of ours other than redeemable preferred shares issued by
us. Edison Mission Energy Taupo shall not pay or make, or allow to be paid or
made, any distribution, other than dividends or the redemption amount or similar
amounts payable in respect of the retail shares, if an event of default or
potential event of default has occurred, which remains unremedied, unless the
redeemable preferred share subscriber has given its prior written consent which
may be given on such conditions as the redeemable preferred share subscriber
deems reasonable.
From July through November 1999, Edison Mission Energy Taupo issued $125
million of retail redeemable preferred shares (240 million shares at a price of
one New Zealand dollar per share). The dividend rate ranges from 5.00% to
6.37%. The shares are redeemable at one New Zealand dollar per share in June
2001 (64 million), June 2002 (43 million), and June 2003 (133 million). Edison
Contact Finance is a special purpose company established to raise funds by the
issuance of retail redeemable preferred shares to assist Edison Mission Energy
Taupo to refinance in part the funding used by it for its acquisition of 40% of
the ordinary shares in Contact Energy. Edison Contact Finance and Edison
Mission Energy Taupo are parties to a subscription and indemnity agreement,
which contains the terms of subscription by Edison Contact Finance for Edison
Mission Energy Taupo retail shares. Edison Contact Finance will subscribe for
Edison Mission Energy Taupo retail shares as and when Edison Contact Finance
issues retail shares. The principal terms of issuance of Edison Mission Energy
Taupo retail shares are set out in the Subscription Agreement and are
substantially the same as the terms of
77
issue of the Class A Redeemable Preferred shares. On an event of default under
the terms of issue of the retail shares, early redemption of the shares may be
required by the holders of the shares by special resolution, by 15% of the
holders of shares, in instances of non-payment, by written notice to Edison
Contact Finance, or Edison Contact Finance by written notice to the holders of
shares. If only part of the retail shares are redeemed earlier than their
scheduled redemption date, in some cases, a minimum number of retail shares must
be redeemed, and unless the redemption occurs on a dividend payment date, Edison
Mission Energy Taupo must redeem all Edison Mission Energy Taupo shares in any
class, with the same scheduled redemption date and fixed dividend rate. Edison
Contact Finance will redeem the same shares of a class corresponding to the
redeemed Edison Mission Energy Taupo shares. Not all classes of shares need be
affected by a partial redemption of Edison Mission Energy Taupo retail shares.
Redemption of retail shares can be accelerated if Edison Mission Energy Taupo
exercises its option under the terms of the subscription and indemnity agreement
to redeem any of the Edison Mission Energy Taupo retail shares at its
discretion. Edison Contact Finance will pay fully imputed dividends, in arrears,
to the holder of each retail share on the record date. Edison Contact Finance
may change the annual dividend rates, which will attach to the shares at any
time before acceptance by Edison Contact Finance of an application for those
shares.
We entered into two Deeds of Covenant comprised of a Facility Agreement and a
Subscription Agreement. The Facility Agreement requires us to provide funds to
Edison Mission Energy Taupo (1) of up to 13 million New Zealand dollars annually
in order for Edison Mission Energy Taupo to meet its interest and dividend
payment obligations to Credit Suisse First Boston and (2) to ensure that we
satisfy specified financial ratios. The Subscription Agreement requires us to
provide funds to the preferred stock subscriber to compensate for any shortfall
in attaching tax imputation credits to the dividends on the preferred stock.
Note 9. Income Taxes
- ---------------------
Current and Deferred Taxes
Income tax expense includes the current tax liability from operations and the
change in deferred income taxes during the year. The components of the net
accumulated deferred income tax liability were:
December 31,
-----------------------
1999 1998
-------- ------
Deferred tax assets
Items deductible for book not currently
deductible for tax $ 172.4 $109.4
Loss carryforwards 68.5 41.5
Deferred income 185.3 187.9
Dividends in excess of equity earnings 6.3 22.4
Other 10.6 10.1
-------- ------
Total $ 443.1 $371.3
-------- ------
Deferred tax liabilities
Basis differences $1,943.2 $963.4
Tax credits, net 19.5 20.6
Other 0.9 0.3
-------- ------
Total 1,963.6 984.3
-------- ------
Deferred taxes and tax credits, net $1,520.5 $613.0
======== ======
78
Loss carryforwards, primarily Australian, total $232 million and $135 million
at December 31, 1999 and 1998, respectively, with $11 million expiring in 2005.
State capital loss carryforwards total $107 million at December 31, 1999 with no
expiration date.
The components of income (loss) before income taxes are as follows:
Years Ended December 31,
-----------------------------------------
1999 1998 1997
------ ------ ------
U.S. $(74.7) $ 32.8 $ 39.0
Foreign 178.4 169.8 146.5
------ ------ ------
Total $103.7 $202.6 $185.5
====== ====== ======
United States income taxes have not been provided on unrepatriated foreign
earnings in the amounts of $372 million and $255 million at December 31, 1999
and 1998, respectively. In addition, foreign income taxes have not been
provided on unrepatriated foreign earnings from another foreign jurisdiction in
the amount of $136 million at December 31, 1999.
The provision (benefit) for income taxes is comprised of the following:
Years Ended December 31,
------------------------------------
1999 1998 1997
-------- ------ ------
Current
Federal $ (75.0) $(10.5) $ (2.4)
State (0.5) (19.0) (10.2)
Foreign (34.0) 14.8 78.3
------- ------ ------
Total current (109.5) (14.7) 65.7
------- ------ ------
Deferred
Federal 37.4 28.1 14.3
State 10.1 25.3 9.0
Foreign 21.6 31.7 (31.6)
------- ------ ------
Total deferred 69.1 85.1 (8.3)
------- ------ ------
Provision (benefit) for income taxes $ (40.4) $ 70.4 $ 57.4
======= ====== ======
The components of the deferred tax provision (credit), which arise from tax
credits and timing differences between financial and tax reporting, are
presented below:
Years Ended December 31,
------------------------------
1999 1998 1997
------ ------ -------
Basis differences $160.0 $116.5 $ 102.6
Loss carryforwards (25.5) (32.6) 121.0
Deferred income -- 3.7 (197.9)
State tax deduction (6.0) 4.3 (0.2)
Items deductible for book not currently
deductible for tax (52.9) (17.4) (27.6)
Elimination of book income -- 6.9 (7.0)
Dividends in excess of equity earnings -- -- 0.2
Other (6.5) 3.7 0.6
------ ------ -------
Total deferred provision (credit) $ 69.1 $ 85.1 $ (8.3)
====== ====== =======
Variations from the 35% federal statutory rate are as follows:
79
Years Ended December 31,
---------------------------
1999 1998 1997
------ ------ ------
Expected provision for federal income taxes $ 36.3 $ 70.9 $ 64.9
Increase (decrease) in the provision for
taxes resulting from
State tax - net of federal deduction 3.6 4.1 (0.8)
Dividends received deduction (2.2) (4.0) (8.2)
Amortization of tax credits (1.1) (6.5) (1.7)
Benefit due to foreign tax rate reduction (5.9) (11.0) (20.0)
Taxes payable under anti-deferral regimes 7.0 6.7 7.0
Taxes on foreign operations at different rates 5.9 8.4 12.8
Book and tax basis differences (7.8) 2.3 3.5
Capital loss not previously recognized (29.0) -- --
Non-utilization of foreign losses 6.9 -- --
Permanent reinvestment of earnings of foreign
affiliates located in different foreign tax
jurisdiction (40.3) -- --
Refund of Advance Corporation Tax (15.2) -- --
Other 1.4 (0.5) (0.1)
------- ------ ------
Total provision (benefit) for income taxes $ (40.4) $ 70.4 $ 57.4
======= ====== ======
Effective tax rate (39.0)% 34.8% 30.9%
======= ====== ======
We are, and may in the future be, under examination by tax authorities in
varying tax jurisdictions with respect to positions we take in connection with
the filing of our tax returns. Matters raised upon audit may involve
substantial amounts, which, if resolved unfavorably, an event not currently
anticipated, could possibly be material. However, in our opinion, it is
unlikely that the resolution of any such matters will have material adverse
effect upon our financial condition or results of operations.
Note 10. Employee Benefit Plans
- --------------------------------
United States employees of Edison Mission Energy are eligible for various
benefit plans of Edison International. Several of our Australian, United
Kingdom and Spanish subsidiaries also participate in their own respective
defined benefit pension plans.
Pension Plans
Noncontributory, defined benefit pension plans cover employees who fulfill
minimum service requirements. In April 1999, Edison International adopted a
cash balance feature for its pension plan.
In 1999, we acquired the Homer City plant and the Illinois Plants. The
acquisitions are discussed further in Note 4. The obligations and expenses for
employees at these plants are included below.
In 1998, we adopted a new accounting standard that revises the disclosure
requirements for pension plans. Prior periods have been restated.
80
Information on plan assets and benefit obligations is shown below:
Years Ended December 31,
-------------------------------------------
1999 1998 1999 1998
------ ----- ------- --------
U.S. Plan Non U.S. Plans
---------------- ---------------------
Change in Benefit Obligation
Benefit obligation at beginning of year $ 26.1 $20.5 $36.7 $30.1
Service cost 2.3 2.4 2.0 1.8
Interest cost 2.1 1.4 1.9 1.9
Plan amendment (3.8) -- -- --
Acquisition 10.6 -- -- --
Actuarial loss 0.4 2.0 5.8 3.3
Plan participants' contribution -- -- 0.8 0.6
Benefits paid (0.2) (0.2) (0.6) (1.0)
------ ----- ----- -----
Benefit obligation at end of year $ 37.5 $26.1 $46.6 $36.7
====== ===== ===== =====
Change in Plan Assets
Fair value of plan assets at beginning of year $ 20.9 $16.6 $34.8 $28.3
Actual return on plan assets 5.8 2.3 8.3 3.4
Employer contributions 2.1 2.2 2.5 3.7
Plan participants' contribution -- -- 0.2 0.2
Benefits paid (0.2) (0.2) (0.4) (0.8)
------ ----- ----- -----
Fair value of plan assets at end of year $ 28.6 $20.9 $45.4 $34.8
====== ===== ===== =====
Funded Status $ (8.9) $(5.2) $(1.2) $(1.9)
Unrecognized net loss (gain) (3.4) -- 0.7 2.4
Unrecognized net obligation 1.1 1.4 -- --
Unrecognized prior service cost (3.1) 0.5 0.4 --
------ ----- ----- -----
Pension asset (liability) $(14.3) $(3.3) $(0.1) $ 0.5
====== ===== ===== =====
Discount rate 7.75% 6.75% 4.5-6.0% 4.5-5.5%
Rate of compensation increase 5.0% 5.0% 3.75-4.5% 3.0%
Expected return on plan assets 7.5% 7.5% 6.5-9.0% 6.0-8.0%
Components of pension expense were:
Years Ended December 31,
----------------------------------------------------------------
1999 1998 1997 1999 1998 1997
------- ----- ------- ------ ------ -------
U.S. Plan Non U.S. Plans
------------------------------ -----------------------------
Service cost $ 2.3 $ 2.4 $ 1.8 $ 1.5 $ 1.8 $ 1.5
Interest cost 2.1 1.4 1.1 1.9 1.9 1.9
Expected return on plan assets (1.7) (1.3) (1.1) (2.1) (3.4) (2.9)
Net amortization and deferral -- 0.2 0.2 0.1 1.3 0.9
----- ----- ----- ----- ----- ------
Total pension expense $ 2.7 $ 2.7 $ 2.0 $ 1.4 $ 1.6 $ 1.4
===== ===== ===== ===== ===== ======
81
Postretirement Benefits Other Than Pensions
Most United States employees retiring at or after age 55 with at least 10
years of service are eligible for postretirement health and dental care, life
insurance and other benefits.
In 1999, we acquired the Homer City plant and the Illinois Plants. The
acquisitions are discussed further in Note 4. The obligations and expenses for
employees at these plants are included below.
In 1998, we adopted a new accounting standard that revises the disclosure
requirements for postretirement benefit plans. Prior periods have been
restated.
Information on plan assets and benefit obligations is shown below:
Years Ended December 31,
------------------------
1999 1998
------ ------
Change in Benefit Obligation
Benefit obligation at beginning of year $ 14.9 $ 11.7
Service cost 1.6 1.4
Interest cost 1.3 0.7
Plan amendment (4.1) --
Acquisition 80.7 --
Actuarial loss (gain) (17.0) 1.3
Benefits paid (0.1) (0.2)
------ ------
Benefit obligation at end of year $ 77.3 $ 14.9
====== ======
Change in Plan Assets
Fair value of plant assets at beginning of year $ -- $ --
Employer contributions 0.1 0.2
Benefits paid (0.1) (0.2)
------ ------
Fair value of plan assets at end of year $ -- $ --
====== ======
Funded Status $(77.3) $(14.9)
Unrecognized net loss (gain) (15.5) 2.5
Unrecognized transition obligation -- 2.0
Unrecognized prior service cost ( 2.1) --
------ ------
Recorded liability $(94.9) $(10.4)
====== ======
Discount rate 8.0% 6.75%
Expected return on plan assets 7.5% 7.5%
The components of postretirement benefits other than pensions expense were:
Years Ended December 31,
-----------------------------------
1999 1998 1997
----- ----- -----
Service cost $ 1.6 $ 1.4 $ 1.2
Interest cost 1.3 0.7 0.7
Net amortization 0.1 0.2 0.1
----- ----- -----
Net expense $ 3.0 $ 2.3 $ 2.0
===== ===== =====
82
The assumed rate of future increases in the per-capita cost of health care
benefits is 11.75% for 2000, gradually decreasing to 5.0% for 2008 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 1999, by $19.1 million
and annual aggregate service and interest costs by $0.6 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of December 31, 1999, by $14.7 million and annual
aggregate service and interest costs by $0.5 million.
Employee Stock Plans
- --------------------
A 401(k) plan is maintained to supplement eligible United States employees'
retirement income. The plan received contributions from us of $2.9 million in
1999, $0.8 million in 1998 and $0.7 million in 1997.
In 1999, Ferrybridge and Fiddler's Ferry employees were included as part of
the PowerGen UK Group defined benefit pension plan, Electricity Supply Pension
Scheme, administered by a trustee, which provides pension and other related
benefits. Contributions to the plan are based on a percentage of compensation
for the covered employees and are assessed by a qualified actuary. As a result
of Ferrybridge and Fiddler's Ferry not having a plan separate from the PowerGen
UK Group, amounts were not readily available to provide the information included
in the tables above. During the first quarter of 2000, Ferrybridge and
Fiddler's Ferry employees joined a separate defined benefit pension plan
utilized by First Hydro employees. Pension expense recorded by Ferrybridge and
Fiddler's Ferry totaled $1.0 million for the period from July 1999 through
December 31, 1999.
Doga employees are included in a separate government scheme, Pension Plan of
Social Security Institution. The plan is administered by the officers of the
Turkish Government. Contributions to the plan are based on a percentage of
compensation for the covered employees and are assessed by the Ministry of Labor
and Social Security. The plan is substantially funded at the end of each
month. Pension expense recorded by Doga from May 1999 through December 31, 1999
is $12 thousand.
In addition to the defined benefit plans described above, specified United
Kingdom subsidiaries of us sponsor a defined contribution plan. Annual
contributions are based on eight percent of covered employees' salaries.
Contribution expense for the subsidiaries totaled approximately $0.4 million,
$0.5 million and $0.3 million in 1999, 1998 and 1997, respectively.
Note 11. Stock Compensation Plans
- ----------------------------------
Under the Edison International Equity Compensation Plan, shares of Edison
International common stock were reserved for potential issuance to key Edison
Mission Energy employees in various forms, including the exercise of stock
options. Under these programs, there are currently outstanding to officers of
Edison Mission Energy, options on 479,071 shares of Edison International Common
Stock of which 154,695, 83,000 and 61,300 were granted in 1999, 1998 and 1997,
respectively.
Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. Edison International stock options
include a dividend equivalent feature. Generally, for options issued before
1994, amounts equal to dividends accrue on the options at the same time and at
the same rate as would be payable on the number of shares of Edison
International common stock covered by the options. The amounts accumulate
without interest. For Edison International stock options issued after 1993,
dividend equivalents are subject to reduction unless certain shareholder return
performance criteria are met. Beginning with the 1999 Edison international
stock option awards, only some stock options include a dividend equivalent
feature. Future stock option awards under the plan are not
83
expected to include the dividend equivalent feature. Additionally, awards of
performance shares, comprising a combination of Edison International common
stock and cash are anticipated under the plan.
The new plan's stock options have a 10-year term with one-fourth of the total
award vesting after each of the first four years of the award term. The prior
program's stock options have a 10-year term with one-third of the total award
vesting after each of the first three years of the award term.
We measure compensation expense related to stock-based compensation by the
intrinsic value method. Compensation expense recorded under the stock
compensation program was $0.4 million for 1999, $0.5 million for 1998 and 1997.
The weighted-average fair value of options granted during 1999, 1998 and 1997
was $6.45 per share option, $6.33 per share option and $7.62 per share option,
respectively. The weighted-average remaining life of options outstanding as of
December 31, 1999, 1998 and 1997 was seven years.
The fair value for each option granted during 1999, 1998 and 1997, reflecting
the basis for the pro forma disclosures, was determined on the date of grant
using the Black-Scholes option-pricing model. The following assumptions were
used in determining fair value through the model:
1999 1998 1997
-------- -------- --------
Expected life 7 years 7 years 7 years
Risk-free interest rate 5.5% 5.6% 6.5%
Expected volatility 18% 17% 17%
The recognition of dividend equivalents results in no dividends assumed for
purposes of fair-value determination. Stock-based compensation expense under
the "fair-value" method of accounting prescribed by SFAS No. 123 "Stock-Based
Compensation" would have resulted in pro forma earnings of $131.4 million,
$132.3 million and $112.3 million in 1999, 1998 and 1997, respectively.
Phantom Stock Options
Edison Mission Energy, as a part of the Edison International long-term
incentive compensation program, issued phantom stock option performance awards
to key employees commencing in 1994. Each phantom stock option may be exercised
to realize any appreciation in the value of one hypothetical share of Edison
Mission Energy stock over its exercise price. Compensation expense will be
recognized during the period that the employee has the right to receive this
appreciation. Exercise prices for our phantom stock are escalated on an
annually-compounded basis over the grant price by 9%. The value of the phantom
stock is recalculated annually as determined by a formula linked to the value of
its portfolio of investments less general and administrative costs. The options
have a 10-year term with one-third of the total award vesting in each of the
first three years of the award term, for all awards prior to 1998. Beginning in
1998, one-fourth of the 1998 and future option awards will vest in each of the
first four years of the award term.
Edison International has elected to not issue additional phantom options after
1999. In January 2000, the board of directors preliminarily approved an
exchange offer to the holders of outstanding phantom options and/or future
exercises of phantom options. We recorded a one-time charge in anticipation of
this offer. Compensation expense recorded with respect to phantom stock options
was
84
$136.3 million, $39 million and $70 million in 1999, 1998 and 1997,
respectively. The amount recorded in 1999 includes a one-time charge of $67.5
million, after-tax.
Note 12. Commitments and Contingencies
- ---------------------------------------
Firm Commitments to Contribute Project Equity
Projects Local Currency U.S. Currency
- -------- -------------- -------------
ISAB (i) 244 billion Italian Lira $127
EcoElectrica (ii) 34
Tri Energy (iii) 25
(i) ISAB is a 512-MW integrated gasification combined cycle power plant under
construction near Siracusa in Sicily, Italy. A wholly owned subsidiary of
Edison Mission Energy owns a 49% interest. Equity will be contributed at
commercial operation, which is currently scheduled for the first quarter
of 2000.
(ii) EcoElectrica is a 540-MW liquefied natural gas combined-cycle cogeneration
facility under construction in Penuelas, Puerto Rico. A wholly owned
subsidiary of Edison Mission Energy owns a 50% interest. Equity will be
contributed at commercial operation, which is currently scheduled for the
first quarter of 2000.
(iii) Tri Energy is a 700-MW gas-fired power plant under construction in the
Ratchaburi Province, Thailand. A wholly owned subsidiary of Edison Mission
Energy owns a 25% interest. Equity will be contributed at commercial
operation, which is currently scheduled for mid-2000.
Firm commitments to contribute project equity could be accelerated due to
certain events of default as defined in the non-recourse project financing
facilities. Management has no reason to believe that these events of default
will occur requiring acceleration of the firm commitments.
Contingent Obligations to Contribute Project Equity
Projects U.S. Currency
- -------- -------------
Paiton (i) $111
Tri Energy (ii) 20
All Other 28
(i) Contingent obligations to contribute additional project equity would be
based on events principally related to insufficient cash flow to cover
interest on project debt and operating expenses, project cost overruns
during the plant construction, specified partner obligations or events of
default. In any and all circumstances, our obligation to contribute
contingent equity will not exceed $141 million, of which $30 million was
contributed as of December 31, 1999.
As more fully described below under the caption "Other Commitments and
Contingencies", PT Perusahaan Listrik Negara, the main source of revenue for
the project, has failed to pay the project in respect of its last eight
invoices and paid only a portion of another invoice. In addition, PT
Perusahaan filed a lawsuit, which it subsequently withdrew, contesting the
validity of the power purchase agreement under which it was to purchase
electricity from the project.
85
In response to PT Perusahaan's failure to pay, Paiton Energy entered into
an interim agreement with its lenders which modified the contingent equity
provisions of the Paiton debt documents during the agreed interim period,
which extends from October 15, 1999 through July 31, 2000. The interim
agreement provides, among other things, that contingent equity from us and
the other Paiton Energy shareholders shall be contributed from time to time
as needed to enable Paiton Energy to pay interim project costs. Interim
project costs include interest on project debt and operating costs which
become due and payable during the term of the interim agreement and other
costs related to the construction of the project, provided that in the
latter case no more than an aggregate of $30 million of contingent equity
can be used for this purpose. The interim agreement provides that a portion
of unfunded contingent equity in the original amount of $206 million, of
which our current unfunded share is $85 million, will become due and
payable by the shareholders in the event that certain events of default,
other than those specifically waived under the interim agreement, occur.
The interim agreement further provides that all unfunded contingent equity
in the original amount of $300 million, of which our current unfunded share
is $93 million, will become due and payable by the shareholders in the
event that Paiton Energy fails to make any interest payment during the
pendency of the interim agreement. As of March 14, 2000, Paiton Energy's
shareholders have contributed to Paiton $103 million of contingent equity,
of which our share is $48 million.
The contractor for the Paiton project and Paiton Energy reached a global
settlement in principal, the terms of which are being finalized. The global
settlement deals with all claims, including contractor claims for
retention, costs relating to a dispute involving a slope adjacent to the
Paiton site and other cost overruns related to delays in the completion of
the construction of the project and Paiton Energy's claims under the
construction contract. Terms and conditions of this settlement will require
the approval of Paiton Energy's lenders. We have no reason to believe that
these approvals will not be obtained. As noted, the shareholders'
obligation to contribute contingent equity to Paiton to enable it to pay
the contractor for the finally agreed amount is limited to $30 million.
Paiton's obligations to the contractor may exceed this amount. The
shortfall, if any, will be considered as part of the renegotiation of the
power purchase agreement and the project's debt agreements, as more fully
discussed under the caption, "Other Commitments and Contingencies."
Our contingent equity obligations for the Paiton project are to be
cancelled, if unused, as of the later of the date of term financing by the
Export-Import Bank of the United States and August 1, 2000. Term financing
by the Export-Import Bank of the United States is the subject of a
comprehensive set of conditions. The obligation of the Export-Import Bank
of the United States to provide term financing was initially scheduled to
terminate on October 15, 1999. The Export-Import Bank of the United States
agreed to extend the term financing commitment through December 31, 2000
and has determined that the project will need to meet additional terms and
conditions for take-out of the construction lenders.
(ii) Contingent obligations to contribute additional equity to the project would
be based on events principally related to capital cost overruns during the
plant's construction, specified partner obligations or events of default.
Other than as noted above, we are not aware, at this time, of any other
contingent obligations or obligations to contribute project equity.
86
Other Commitments and Contingencies
Subsidiary Indemnification Agreements
Some of our subsidiaries have entered into indemnification agreements,
under which the subsidiaries agreed to repay capacity payments to the projects'
power purchasers in the event the projects unilaterally terminate their
performance or reduce their electric power producing capability during the term
of the power contracts. Obligations under these indemnification agreements as of
December 31, 1999, if payment were required, would be $280 million. We have no
reason to believe that the projects will either terminate their performance or
reduce their electric power producing capability during the term of the power
contracts.
Paiton
Paiton is a 1,230-MW coal-fired power plant in operation in East Java,
Indonesia. A wholly owned subsidiary of Edison Mission Energy owns a 40%
interest and has a $419 million investment at December 31, 1999. The project's
tariff is higher in the early years and steps down over time. The tariff for
the Paiton project includes infrastructure to be used in common by other units
at the Paiton complex. The plant's output is fully contracted with the state-
owned electricity company, PT Perusahaan Listrik Negara. Payments are in
Indonesian Rupiah, with the portion of such 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 of the power purchase
agreement in February 1994. The project 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. PT Perusahaan's payment
obligations are supported by the Government of Indonesia. The projected rate of
growth of the Indonesian economy and the exchange rate of Indonesian Rupiah into
U.S. dollars have deteriorated significantly since the Paiton project was
contracted, approved and financed. The Paiton project's senior debt ratings have
been reduced from investment grade to speculative grade based on the rating
agencies' determination that there is increased risk that PT Perusahaan might
not be able to honor the electricity sales contract with Paiton. The Government
of Indonesia has arranged to reschedule sovereign debt owed to foreign
governments and has entered into discussions about rescheduling sovereign debt
owed to private lenders. Specified events, including those discussed in the
paragraph below, which, with the passage of time or upon notice, may mature into
defaults of the Project's debt agreements have occurred. On October 15, 1999,
the project entered into an interim agreement with its lenders pursuant to which
the lenders waived such defaults until July 31, 2000. However, this waiver may
expire on an earlier date if additional defaults, other than those specifically
waived, or other specified events occur.
In May 1999, Paiton notified PT Perusahaan 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. Because of the economic downturn, PT Perusahaan is
experiencing low electricity demand and PT Perusahaan has therefore dispatched
the Paiton plant to zero; however, under the terms of the power purchase
agreement, PT Perusahaan is required to continue to pay for capacity and fixed
operating costs once each unit and the plant achieve commercial operation. An
invoice for these charges for May in the amount of $7.8 million was submitted to
PT Perusahaan. The project and PT Perusahaan met to review the invoice and a
partial payment of $2.5 million was subsequently received. The primary reason
for the payment shortage was the use of an arbitrary Indonesian Rupiah/U.S.
dollar exchange rate of 2,450 Indonesian Rupiah to one U.S. dollar by PT
Perusahaan. The use of this exchange rate is not in agreement with the power
purchase agreement, but is the exchange rate on which PT Perusahaan payments to
other independent power producers in Indonesia have been based. Additional
invoices for capacity charges and fixed
87
operating costs in an aggregate amount of $312 million were later submitted to
PT Perusahaan. PT Perusahaan has yet to make any payments in respect of such
latter invoices. In addition, PT Perusahaan filed a lawsuit contesting the
validity of its agreement to purchase electricity from the project. The lawsuit
was withdrawn by PT Perusahaan on January 20, 2000, and on February 21, 2000,
Paiton and PT Perusahaan 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,
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 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 renegotiations with PT
Perusahaan, the Government of Indonesia or the project's creditors on our
expected return on our investment in Paiton is uncertain at this time; however,
we believe that we will ultimately recover our investment in the project.
Brooklyn Navy Yard
Brooklyn Navy Yard is a 286-MW gas-fired cogeneration power plant in Brooklyn,
New York. Our wholly owned subsidiary owns 50% of the project. In February
1997, the construction contractor asserted general monetary claims under the
turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for
damages in the amount of $136.8 million. Brooklyn Navy Yard Cogeneration
Partners has asserted general monetary claims against the contractor. In
connection with a $407 million non-recourse project refinancing in 1997, we
agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner
from all claims and costs arising from or in connection with the contractor
litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration
Partners' lenders. At the present time, we cannot reasonably estimate the
amount that would be due, if any, related to this litigation. Additional
amounts, if any, which would be due to the contractor with respect to completion
of construction of the power plant would be accounted for as an additional part
of its power plant investment. Furthermore, our partner has executed a
reimbursement agreement with us that provides recovery of up to $10 million over
an initial amount, including legal fees, payable from its management and royalty
fees. At December 31, 1999, no accrual has been recorded in connection with
this litigation. We believe that the outcome of this litigation will not have a
material adverse effect on our consolidated financial position or results of
operations.
Fuel Supply Contracts
At December 31, 1999, we had contractual commitments to purchase and/or
transport coal and fuel oil. Based on the contract provisions which consist of
fixed prices, subject to adjustment clauses in certain cases, these minimum
commitments are currently estimated to aggregate $2.5 billion in the next five
years summarized as follows: 2000 - $838 million; 2001 - $637 million; 2002 -
$445 million; 2003 - $326 million; 2004 - $291 million.
Employment Agreements
During the first quarter of 2000, we entered into mutual agreements with two
key officers of Edison Mission Energy terminating their positions with Edison
Mission Energy and related companies. One of the agreements provides for an
officer to be paid $500,000 as a one-time severance payment. The other agreement
provides for an officer to be paid one-year's salary as severance and permitted
to continue his current living arrangements in Europe for one year. In March
2000, we paid the officers $35 million and $12 million, respectively, in
cancellation of their vested Edison Mission Energy phantom stock
88
options. These payments equaled the agreed upon amounts per Edison Mission
Energy phantom stock option over the exercise prices of the officers' vested
phantom stock options and were accrued as of the end of 1999 in anticipation of
a contemplated exchange offer or future phantom stock option exercises. The
amounts are subject to upward adjustment if an exchange offer for similarly
situated individuals is completed at a higher price per share.
The agreement with one of the officers also provides for consulting services
to be rendered by him to Edison Mission Energy for a period of up to 24 months,
subject to earlier termination under certain circumstances. During the
consulting period, we will pay the officer a consulting fee at the rate of
$300,000 per annum and his unvested Edison International stock options will
continue to vest ratably. The unvested phantom stock options will also vest
ratably during the consulting period and be paid out at the same rate per
phantom stock option as was paid in cancellation of his vested phantom stock
options, up to $1.712 million in the aggregate.
Under the agreements with Edison Mission Energy, both officers are subject to
a number of covenants, including confidentiality, non-solicitation, non-
disparagement and non-interference. One of the officers is also subject to a
non-competition covenant.
Litigation
We are routinely involved in litigation arising in the normal course of
business. While the results of such litigation cannot be predicted with
certainty, we, based on advice of counsel, do not believe that the final outcome
of any pending litigation will have a material adverse effect on our financial
position or results of operations.
Environmental Matters or Regulations
We are subject to environmental regulation by federal, state, and local
authorities in the United States and foreign regulatory authorities with
jurisdiction over projects located outside the United States. We believe that
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 position or
results of operation.
We expect that the implementation of Clean Air Act Amendments will result in
increased capital expenditures and operating expenses. 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. 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. We do not expect these increased capital
expenditures and operating expenses to have a material effect on our financial
position or results of operation.
Note 13. Lease Commitments
- ---------------------------
We lease office space, property and equipment under noncancelable lease
agreements that expire in various years through 2063. The primary capital lease
obligation is for a plant located in the United Kingdom denominated in pounds
sterling. A group of banks provides a guarantee on the performance of the
capital lease obligation under a Term Loan and Guarantee Facility agreement.
The facility agreement provides for an aggregate of $185.1 million in a
guarantee to the lessor and in loans to the
89
project. As of December 31, 1999, the loan obligation stands at $97.8 million,
which is secured by the plant assets of $16.7 million owned by the project and
a debt service reserve of $2.1 million.
In connection with the acquisition of the Illinois Plants, we assigned the
right to purchase the Collins gas-fired power plant to a third party. The third
party purchased the Collins Station for $860 million and entered into a lease of
the plant with us. The lease, which is being accounted for as an operating
lease, has an initial term of 33.75 years with payments due on a quarterly
basis. The base lease rent includes both a fixed and variable component; the
variable component of which is impacted by movements in defined short-term
interest rate indexes. Under the terms of the lease, we may request the lessor,
at its option, to refinance the lessor's debt, which if completed would impact
the base lease rent. If the lessor intends to sell the interest in the Collins
Station, we have a first right of refusal to acquire the facility at fair market
value. Minimum lease payments during the next five years are $16.7 million in
2000; $42.3 million in 2001; $50.3 million in 2002; $50.3 million in 2003; and
$50.4 million in 2004. At December 31, 1999, the total remaining minimum lease
payments are $1.5 billion.
Future minimum payments for operating (excluding the Collins Station described
above) and capital leases at December 31, 1999, are:
Years Ending December 31, Operating Capital
Leases Leases
------------ ----------
2000 $ 26.1 $24.4
2001 23.3 0.2
2002 20.4 0.2
2003 18.9 0.2
2004 18.4 0.2
Thereafter 149.7 0.2
------ -----
Total future commitments $256.8 25.4
======
Amount representing interest (10.56%) 2.6
-----
Net Commitments $22.8
=====
Operating lease expense amounted to $10.4 million, $6.9 million and $6.7
million in 1999, 1998 and 1997, respectively.
Note 14. Related Party Transactions
- ------------------------------------
Specified administrative services such as payroll and employee benefit
programs, all performed by Edison International or Southern California Edison
Company employees, are shared among all affiliates of Edison International and
the costs of these corporate support services are allocated to all affiliates,
including us. Costs are allocated based on one of the following formulas:
percentage of time worked, equity in investment and advances, number of
employees, or multi-factor (operating revenues, operating expenses, total assets
and number of employees). In addition, services of Edison International or
Southern California Edison Company employees are sometimes directly requested by
us and such services are performed for our benefit. Labor and expenses of these
directly requested services are specifically identified and billed at cost. We
believe the allocation methodologies utilized are reasonable. We made monthly
reimbursements for the cost of these programs and other services, which amounted
to $34.6 million, $29.7 million and $23.4 million in 1999, 1998 and 1997,
respectively.
90
We record accruals for tax liabilities and/or tax benefits which are settled
quarterly according to a series of tax sharing agreements as described in Note
2. Under these agreements, we recognized tax benefits of $75.5 million, $29.5
million and $12.6 million for 1999, 1998 and 1997, respectively. See Note 9.
Specified Edison Mission Energy subsidiaries have ownership in partnerships
that sell electricity generated by their project facilities to Southern
California Edison Company and others under the terms of long-term power purchase
agreements. Sales by such partnerships to Southern California Edison Company
under these agreements amounted to $512.6 million, $534.8 million and $579.6
million in 1999, 1998 and 1997, respectively.
Note 15. Supplemental Statements of Cash Flows Information
- -----------------------------------------------------------
Years Ended December 31,
-------------------------------------------------
1999 1998 1997
--------------- -------------- --------------
Cash paid
Interest (net of amount capitalized) $ 327.6 $171.5 $218.1
Income taxes (receipts) $ (41.5) $ 8.8 $ 62.3
Years Ended December 31,
-------------------------------------------------
1999 1998 1997
--------------- -------------- --------------
Details of assets acquired
Fair value of assets acquired $9,151.1 $248.4 $667.1
Liabilities assumed 539.1 -- 603.1
-------- ------ ------
Net cash paid for acquisitions $8,612.0 $248.4 $ 64.0
======== ====== ======
Non-Cash Investing and Financing Activities
In June 1997, we made a noncash dividend of $78 million to our parent
company, The Mission Group, a wholly owned, non-utility subsidiary of Edison
International. The noncash dividend is in the form of a promissory note with
interest at LIBOR plus 0.275% (6.04% at December 31, 1999) paid on a quarterly
basis and principal is due on June 30, 2007.
Note 16. Business Segments
- ---------------------------
We operate predominately in one line of business, electric power generation,
with reportable segments organized by geographic region: United States, Asia
Pacific and Europe, Central Asia, Middle East and Africa. Our plants are
located in different geographic areas, which mitigate the effects of regional
markets, economic downturns or unusual weather conditions.
Electric power and steam generated in the United States is sold primarily
under (1) long-term contracts, with terms of 15 to 30-years, to domestic
electric utilities and industrial steam users, (2) through a centralized power
pool, or (3) under a power purchase agreement with a term of up to five years.
Plants located in the United Kingdom and a plant in Australia sell their energy
and capacity production through a centralized power pool. The plants that sell
through a centralized power pool enter into short and/or long-term contracts to
hedge against the volatility of price fluctuations in the pool. Other electric
power generated overseas is sold under long-term contracts to electric utilities
located in the country where the power is generated. Intercompany transactions
have been eliminated in the following segment information.
91
For the years ended December 31, 1999, 1998 and 1997, our share of revenues
from our only major customer, Southern California Edison Company, was $131.2
million, $108.9 million and $122.2 million, respectively. These revenues
represent eight percent in 1999 and 12% in 1998 and 1997 of our consolidated
revenues and are included in the Americas region shown below.
Europe,
Central Asia,
Asia Middle East Corporate/
Americas Pacific and Africa Other(i) Total
--------------- ------------- ------------- ------------- ------------
1999
- ----
Electric & operating revenues $ 378.6 $ 213.6 $ 805.8 $ -- $ 1,398.0
Equity in income from investments 224.9 18.1 1.4 -- 244.4
-------- -------- -------- ------ ---------
Total operating revenues $ 603.5 $ 231.7 $ 807.2 $ -- $ 1,642.4
======== ======== ======== ============ =========
Depreciation and amortization $ 58.9 $ 41.6 $ 89.7 $ -- $ 190.2
Interest and other income $ (0.5) $ 15.9 $ 13.1 $ 13.2 $ 41.7
Interest expense $ 65.1 $ 80.7 $ 128.6 $ 78.8 $ 353.2
Net income (loss) $ 52.8 $ (10.5) $ 135.5 $ (47.5) $ 130.3
======== ======== ======== ============ =========
Identifiable assets $6,789.4 $1,848.3 $4,955.6 $ -- $13,593.3
Equity investments and advances 862.2 1,063.1 15.6 -- 1,940.9
-------- -------- -------- ------------ ---------
Total assets $7,651.6 $2,911.4 $4,971.2 $ -- $15,534.2
======== ======== ======== ============ =========
Additions to property and plant $6,179.7 $ 6.1 $2,124.3 $ -- $ 8,310.1
1998
- ----
Electric & operating revenues $ 29.9 $ 205.1 $ 469.4 $ -- $ 704.4
Equity in income from investments 184.6 1.3 3.5 -- 189.4
-------- -------- -------- ------------ ---------
Total operating revenues $ 214.5 $ 206.4 $ 472.9 $ -- $ 893.8
======== ======== ======== ============ =========
Depreciation and amortization $ 13.5 $ 32.5 $ 41.3 $ -- $ 87.3
Interest and other income $ -- $ 4.3 $ 26.3 $ 19.2 $ 49.8
Interest expense -- $ 71.0 $ 77.3 $ 34.6 $ 182.9
Net income (loss) $ 63.5 $ 28.0 $ 58.0 $ (17.4) $ 132.1
======== ======== ======== ============ =========
Identifiable assets $ 358.0 $1,334.3 $2,239.6 $ (0.3) $ 3,931.6
Equity investments and advances 841.2 361.2 23.8 0.3 1,226.5
-------- -------- -------- ------------ ---------
Total assets $1,199.2 $1,695.5 $2,263.4 $ -- $ 5,158.1
======== ======== ======== ============ =========
Additions to property and plant $ 5.1 $ 2.2 $ 66.1 $ -- $ 73.4
1997
- ----
Electric & operating revenues $ 31.3 $ 302.0 $ 452.3 $ -- $ 785.6
Equity in income from investments 182.7 3.5 0.2 3.0 189.4
-------- -------- -------- ------------ ---------
Total operating revenues $ 214.0 $ 305.5 $ 452.5 $ 3.0 $ 975.0
======== ======== ======== ============ =========
Depreciation and amortization $ 14.8 $ 46.4 $ 41.6 $ -- $ 102.8
Interest and other income $ -- $ 2.9 $ 10.5 $ 13.9 $ 27.3
Interest expense $ -- $ 82.2 $ 84.8 $ 43.3 $ 210.3
92
Net income (loss) $ 72.8 $ 11.1 $ 47.8 $ (16.7) $ 115.0
======== ======== ======== ============ =========
Identifiable assets $ 306.8 $1,468.0 $2,288.9 $ 1.6 $ 4,065.3
Equity investments and advances 623.9 252.7 42.9 0.3 919.8
-------- -------- -------- ------------ ---------
Total assets $ 930.7 $1,720.7 $2,331.8 $ 1.9 $ 4,985.1
======== ======== ======== ============ =========
Additions to property and plant $ 4.0 $ 7.1 $ 76.6 $ -- $ 87.7
(i) Includes corporate net interest expense and Mexico and Canada investments.
Geographic Information
Foreign operating revenues and assets by country included in the table above
are shown below.
Years Ended December 31,
------------------------------------------------
1999 1998 1997
-------------- -------------- --------------
Operating revenues
Australia $208.5 $199.3 $295.9
Other Asia Pacific 23.2 7.1 9.6
------ ------ ------
Total Asia Pacific $231.7 $206.4 $305.5
====== ====== ======
United Kingdom $746.8 $448.8 $427.7
Turkey 38.0 -- --
Spain 22.4 24.1 24.8
------ ------ ------
Total Europe, Central Asia, Middle East and Africa $807.2 $472.9 $452.5
====== ====== ======
December 31,
------------------------------------------------
1999 1998 1997
-------------- -------------- --------------
Assets
Australia $1,397.5 $1,326.2 $1,460.7
New Zealand 616.8 -- --
Indonesia 442.5 358.2 252.4
Other Asia Pacific 454.6 11.1 7.6
-------- -------- --------
Total Asia Pacific $2,911.4 $1,695.5 $1,720.7
======== ======== ========
United Kingdom $4,162.8 $1,787.1 $1,759.5
Turkey 191.2 161.8 92.9
Spain 167.2 195.7 187.1
Other Europe, Central Asia, Middle East and Africa 450.0 118.8 292.3
-------- -------- --------
Total Europe, Central Asia, Middle East and Africa $4,971.2 $2,263.4 $2,331.8
======== ======== ========
Note 17. Quarterly Financial Data (unaudited)
- --------------------------------------------------
1999 First(i) Second Third(i) Fourth(i) Total
-------------- --------------- --------------- --------------- --------------
Operating revenues $269.8 $269.4(ii) $537.1(iii) $566.1(iv) $1,642.4
Income from operations 114.2 73.1(ii) 222.7(iii) 22.9(iv, v) 432.9
93
First(i) Second Third(i) Fourth(i) Total
1999 -------------- --------------- --------------- --------------- --------------
Income (loss) before 57.9 5.5(ii) 86.6(iii) (5.9)(iv, v) 144.1
accounting change
Net income (loss) 44.1 5.5(ii) 86.6(iii) (5.9)(iv, v) 130.3
1998 First(i) Second Third(i) Fourth(i) Total
-------------- --------------- --------------- --------------- --------------
Operating revenues $231.9 $207.3 $227.5 $227.1 $893.8
Income from operations 99.3 71.1 103.4 76.7 350.5
Net income 37.7 18.6 44.8 31.0 132.1
(i) Reflects our seasonal pattern, in which the majority of earnings from
domestic projects are recorded in the third quarter of each year and
higher electric revenues from specified international projects are
recorded during the winter months of each year.
(ii) Reflects the operations of the Homer City plant acquired in March 1999.
(iii) Reflects the operations of the Homer City plant, the Doga project, which
commenced commercial operations in May 1999, and the Ferrybridge and
Fiddler's Ferry plants acquired in July 1999.
(iv) Reflects the operations of the Homer City plant, the Doga project, the
Ferrybridge and Fiddler's Ferry plants and the Illinois Plants acquired in
December 1999.
(v) Reflects a one-time charge of $67.5 million, after-tax, in anticipation of
an exchange offer to holders of outstanding phantom options.
94
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Positions with Edison Mission Energy
Listed below are our directors and executive officers and their positions as
of March 6, 2000.
Director Position Held
Continuously Term Continuously Term
Name, Position and Age Since Expires Since Expires
- ---------------------- ------------ ------- ------------ -------
Alan J. Fohrer, 49...................................................... 1992 2000 2000 2000
Director, President and Chief Executive Officer
John E. Bryson, 56...................................................... 2000 2000 -- --
Chairman of the Board
Bryant C. Danner, 62.................................................... 1993 2000 -- --
Director
Thomas R. McDaniel, 50.................................................. 2000 2000 -- --
Director
Robert M. Edgell, 53.................................................... 1993 2000 1988 2000
Director, Executive Vice President and
Division President of Edison Mission Energy, Asia Pacific
William J. Heller, 43................................................... 1999 2000 2000 2000
Senior Vice President and Division President of
Edison Mission Energy, Europe, Central Asia, Middle East and Africa
James V. Iaco, Jr., 55.................................................. -- -- 1998 2000
Senior Vice President and Division President of
Edison Mission Energy, Americas
Ronald L. Litzinger, 40................................................. -- -- 1999 2000
Senior Vice President, Worldwide Operations
Georgia R. Nelson, 50................................................... -- -- 1999 2000
Senior Vice President and President of
Midwest Generation EME, LLC
Kevin M. Smith, 41...................................................... -- -- 1999 2000
Senior Vice President and Chief Financial Officer
Raymond W. Vickers, 57.................................................. -- -- 1999 2000
Senior Vice President and General Counsel
Business Experience
Below is a description of the principal business experience during the past
five years of each of the individuals named above and the name of each public
company in which any director named above is a director.
Mr. Fohrer has been President and Chief Executive Officer of Edison Mission
Energy since January 2000. From 1998 to 2000, Mr. Fohrer served as Chairman of
the Board. From 1993 to 1998, Mr. Fohrer served as Vice Chairman of the Board.
Mr. Fohrer was Executive Vice President and Chief Financial Officer of Edison
International and was Executive Vice President and Chief Financial Officer of
Southern California Edison Company from June 1995 until January 2000. Effective
February 1996 and June 1995, Mr. Fohrer also served as Treasurer of Southern
California Edison Company and Edison International, respectively, until August
1996. Mr. Fohrer was Senior Vice President, Treasurer and Chief Financial
Officer of Edison International, and Senior Vice President and Chief Financial
Officer of Southern California Edison Company from January 1993 until May 1995.
Mr. Fohrer was Edison Mission Energy's interim Chief Executive Officer between
May 1993 and August 1993. From 1991 until 1993, Mr. Fohrer was Vice President,
Treasurer and Chief Financial Officer of Edison International and Southern
California Edison Company.
95
Mr. Bryson has been Chairman of the Board of Edison Mission Energy since
January 2000. Mr. Bryson has been President of Edison International since
January 2000 and Chairman of the Board and Chief Executive Officer of Edison
International since 1990. Mr. Bryson served as Chairman of the Board, Chief
Executive Officer and a Director of Southern California Edison Company from 1990
to January 2000. Mr. Bryson is a director of The Boeing Company, The Times
Mirror Company, and Pacific American Income Shares, Inc. and LM Institutional
Fund Advisors I, Inc.
Mr. Danner has been Executive Vice President and General Counsel of Edison
International since June 1995. Mr. Danner was ExecutiveVice President and
General Counsel of Southern California Edison Company from June 1995 until
January 2000. Mr. Danner was Senior Vice President and General Counsel of
Edison International and Southern California Edison Company from July 1992 until
May 1995.
Mr. McDaniel has been President, Chief Executive Officer and a director of
Edison Capital, a wholly owned subsidiary of Edison International, since
September 1987.
Mr. Edgell has been Executive Vice President of Edison Mission Energy since
April 1988. Mr. Edgell was named Division President of Edison Mission Energy's
Asia Pacific region in January 1995.
Mr. Heller has been Senior Vice President and Division President of Edison
Mission Energy, Europe, Central Asia, Middle East and Africa since February
2000. Mr. Heller was elected Director of Edison Mission Energy's Board,
effective December 9, 1999, and subsequently resigned effective February 7,
2000. Mr. Heller was Senior Vice President of Strategic Planning and New
Business Development for Edison International from January 1996 until February
2000. Prior to joining Edison International, Mr. Heller was with McKinsey and
Company, Inc. from 1982 to 1995, serving as principal and head of McKinsey's Los
Angeles Energy Practice from 1991 to 1995.
Mr. Iaco has been Senior Vice President of Edison Mission Energy since January
1994 and Division President of Edison Mission Energy's Americas region since
January 1998. Mr. Iaco served as Chief Financial Officer from January 1994 to
May 1999. From September 1993 until December 1993, Mr. Iaco was self-employed
and provided consulting services, specializing in restructuring, finance, crisis
management and other management services. From October 1992 until September
1993, Mr. Iaco served as senior vice president and chief financial officer of
Phoenix Distributors, Inc., a distributor of industrial gas and welding
supplies.
Mr. Litzinger has been Senior Vice President, Worldwide Operations, since June
1999. Mr. Litzinger served as Vice President-O&M Business Development from
December 1998 to May 1999. Mr. Litzinger has been with Edison Mission Energy
since November 1995 serving as both Regional Vice President, O&M Business
Development and Manager, O&M Business Development until December 1998. Prior to
joining Edison Mission Energy, Mr. Litzinger was a Reliability Supervisor with
Texaco Refining and Marketing, Inc. from March 1995 to October 1995 and prior to
that held numerous management positions with Southern California Edison Company
since June 1986.
Ms. Nelson has been President of Midwest Generation EME, LLC since May 1999.
From January 1996 until June 1999, Ms. Nelson was Senior Vice President,
Worldwide Operations. Ms. Nelson was Division President of Edison Mission
Energy's, Americas region from January 1996 to January 1998. Prior to joining
Edison Mission Energy, Ms. Nelson served as Senior Vice President of Southern
California Edison Company from June 1995 until December 1995 and Vice President
of Southern California Edison Company from June 1993 until May 1995. From 1992
to 1993, Ms. Nelson served as a Special Assistant to the Chairman of Edison
International.
96
Mr. Smith has been Senior Vice President and Chief Financial Officer of
Edison Mission Energy since May 1999. Mr. Smith served as Treasurer of Edison
Mission Energy from 1992 to 2000 and was elected a Vice President in 1994.
During March 1998 until September 1999, Mr. Smith also held the position of
Regional Vice President, Americas region.
Mr. Vickers has been Senior Vice President and General Counsel of Edison
Mission Energy since March 1, 1999. Prior to joining Edison Mission Energy, Mr.
Vickers was a partner with the law firm of Skadden, Arps, Slate, Meagher & Flom
LLP concentrating on international business transactions, particularly cross-
border capital markets and investment transactions, project implementation and
finance. Mr. Vickers originally joined Skadden, Arps, Slate, Meagher & Flom LLP
in 1989 as resident partner in the Hong Kong office.
Section 16 (a) Beneficial Ownership Reporting Compliance
- --------------------------------------------------------
Pursuant to Item 405 of Regulation S-K, Edison Mission Energy is required to
disclose the following recently elected officers who each had one delinquent
Form 3 "Initial Statement of Beneficial Ownership of Securities" filing which is
required to be filed within 10 days of being elected for fiscal year 1999:
Name Date Elected
---- ------------
John P. Finneran, Vice President September 13, 1999
William J. Heller, Director December 9, 1999
John Long, Vice President December 15, 1999
Nigel Petrie, Vice President December 15, 1999
97
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table provides information concerning compensation paid by
Edison Mission Energy to each of the named executive officers during the years
1999, 1998 and 1997 for services rendered by such persons in all capacities to
Edison Mission Energy and its subsidiaries.
SUMMARY COMPENSATION TABLE
Long-Term
Compensation
ANNUAL COMPENSATION Awards
---------------------------------------------------- --------------
Other Annual Securities All Other
Name and Principal Salary Bonus Compensation Underlying Compensation
Position Year ($) ($) ($) Options (#)(3) ($)(4)
- ------------------ ------- ----------- ---------- ------------- -------------- ------------
Edward R. Muller(1) 1999 463,000 347,250 2,147 33,780 35,797(6)
President and 1998 432,000 390,000 2,624 21,160 40,172
Chief Executive Officer 1997 400,000 456,000 3,478 33,300 28,587
Robert M. Edgell 1999 387,000 276,500 -- 23,580 93,224(5)
Executive Vice President 1998 362,000 265,000 -- 14,760 56,474(5)
1997 317,000 325,000 -- 23,300 33,600(5)
S. Linn Williams(2) 1999 355,000 177,500 20 14,500 64,244(5)/(6)
Senior Vice President 1998 325,000 186,000 2,197 9,520 25,841
1997 300,000 240,000 1,643 15,400 18,568
Georgia R. Nelson 1999 330,000 178,200 3,532 13,610 28,478
Senior Vice President and 1998 310,000 170,000 3,125 8,580 29,233
President of Midwest 1997 290,000 206,000 7,125 15,400 17,829
Generation EME, LLC
James V. Iaco, Jr. 1999 330,000 184,800 6,647 13,610 20,776
Senior Vice President and 1998 300,000 180,000 5,167 8,830 17,648
Division President of 1997 280,000 224,000 4,913 15,400 14,962
Edison Mission Energy,
Americas
(1) Mr. Muller resigned as President and Chief Executive Officer effective
January 17, 2000.
(2) Mr. Williams resigned as Senior Vice President and President of Edison
Mission Energy's Europe, Central Asia, Middle East and Africa divisions,
effective February 7, 2000.
(3) No Stock Appreciation Rights were granted. Amounts shown are comprised of
Edison International nonqualified stock options and Edison Mission Energy
phantom stock options. For 1999, Mr. Muller, Mr. Edgell, Mr. Williams, Ms.
Nelson and Mr. Iaco received 23,100; 16,100; 9,900; 9,300 and 9,300 Edison
International stock options, respectively, and 10,680; 7,480; 4,600; 4,310;
and 4,310 Edison Mission Energy phantom stock options, respectively. For
1998, Mr. Muller, Mr. Edgell, Mr. Williams, Ms. Nelson and Mr. Iaco received
13,300; 8,700; 6,300; 5,400; and 5,900 Edison International stock options,
respectively; and 7,860; 6,060; 3,220; 3,180; and 2,930 Edison Mission
Energy phantom stock options, respectively. For 1997, Mr. Muller, Mr.
Edgell, Mr. Williams, Ms. Nelson and Mr. Iaco received 10,500; 7,500; 5,500;
5,500; and 5,500 Edison International stock options, respectively; and
22,800; 15,800; 9,900; 9,900; and 9,900 Edison Mission Energy phantom stock
options, respectively. Each Edison International nonqualified stock option
gives the named executive officer the right to purchase one share of Edison
International Common Stock, and each Edison Mission Energy phantom stock
option may be exercised to realize any appreciation in the value of one
hypothetical share of Edison
98
Mission Energy stock over annually escalated exercise prices, on the terms
described in the notes to the Option Grants in the 1999 Option Grant Table
below.
(4) Includes the following company contributions to a defined contribution plan,
Stock Savings Plus Plan and a supplemental plan for eligible participants
who are affected by Stock Savings Plus Plan participation limits imposed on
higher-paid individuals by federal tax law: For 1999, Mr. Muller, $30,374;
Mr. Edgell, $16,384; Mr. Williams, $21,016; Ms. Nelson, $19,779; and Mr.
Iaco, $20,069. For 1998, Mr. Muller, $26,373; Mr. Edgell $14,550; Mr.
Williams, $16,796; Ms. Nelson, $15,461; and Mr. Iaco, $15,701. For 1997, Mr.
Muller, $25,305; Mr. Edgell $13,000; Mr. Williams, $15,599; Ms. Nelson,
$14,384; and Mr. Iaco, $14,376.
Also includes the following amounts of interest accrued on deferred
compensation of the named individuals, which is considered under the rules
of the Securities and Exchange Commission to be at an above-market rate: For
1999, Mr. Muller, $5,272; Mr. Edgell, $338; Mr. Williams, $3,048; Ms.
Nelson, $2,353; and Mr. Iaco, $683. For 1998, Mr. Muller, $13,520; Mr.
Edgell $1,116; Mr. Williams, $9,005; Ms. Nelson, $7,812; and Mr. Iaco,
$1,902. For 1997, Mr. Muller, $3,283; Mr. Edgell $458; Mr. Williams, $2,969;
Ms. Nelson, $3,445; and Mr. Iaco, $586.
(5) Includes the following amounts for an overseas service allowance: For 1999,
Mr. Edgell, $68,644 and Mr. Williams, $40,150. For 1998 and 1997, Mr.
Edgell, $33,693 and $20,142, respectively.
(6) Subsequent to the end of the fiscal year, Edison Mission Energy entered into
separate agreements with Messrs. Muller and Williams in connection with the
end of their employment that are discussed below in the section entitled
"Employment Contracts and Termination of Employment Arrangements."
Executive Stock Options
The following table sets forth certain information concerning Edison
International stock options and Edison Mission Energy phantom stock options
granted pursuant to the Edison International Equity Compensation Plan to the
executive officers named in the Summary Compensation Table above during 1999.
OPTION GRANTS IN 1999(1)
Individual Grants
---------------------------------------------------------------
Exercise
--------
Options Percent of Total or Base Grant Date
Granted Options Granted to Price Expiration Present
Name (#) Employees in 1999 ($/Sh) Date Value ($)
- ------------- ------- ------------------ -------- ---------- ----------
(2)(3) (4)(5) (6)
Edward R. Muller
Edison International 23,100 1% 28.125 01/02/2009 101,033
Edison Mission Energy 10,680 8% 306.825 01/02/2009 278,855
Robert M. Edgell
Edison International 16,100 1% 28.125 01/02/2009 70,418
Edison Mission Energy 7,480 6% 306.825 01/02/2009 195,303
S. Linn Williams
Edison International 9,900 1% (*) 28.125 01/02/2009 43,299
Edison Mission Energy 4,600 4% 306.825 01/02/2009 120,106
Georgia R. Nelson
Edison International 9,300 1% (*) 28.125 01/02/2009 40,675
Edison Mission Energy 4,310 3% 306.825 01/02/2009 112,534
James V. Iaco, Jr.
Edison International 9,300 1% (*) 28.125 01/02/2009 40,675
Edison Mission Energy 4,310 3% 306.825 01/02/2009 112,534
(*) Less than
99
(1) No Stock Appreciation Rights were granted. This table reflects all awards
made under the Edison International Equity Compensation Plan during 1999.
In addition to Edison International stock options, it includes Edison
Mission Energy phantom stock options.
(2) Each Edison International nonqualified stock option granted in 1999 may be
exercised to purchase one share of common stock of Edison International.
One-half of the value granted in the form of Edison International stock
options includes dividend equivalents equal to the dividends that would have
been paid on that number of shares of Edison International Common Stock.
Dividend equivalents will be credited following the first three years of the
option term if certain Edison International performance criteria discussed
below are met. Dividend equivalents accumulate without interest. Once
earned and vested, the dividend equivalents are payable in cash (i) upon the
request of the holder prior to the final year of the option term, (ii) upon
the exercise of the related option, or (iii) at the end of the option term
regardless of whether the related option is exercised. After such payment,
however, no additional dividend equivalents will accrue on the related
option.
The dividend equivalent performance criteria is measured by Edison
International Common Stock total shareholder return. If the average
quarterly percentile ranking is less than the 60th percentile of that of the
companies comprising the Dow Jones Electric Utilities Index, the dividend
equivalents are reduced; if the Edison International total shareholder
return ranking is less than the 25th percentile, the dividend equivalents
are canceled. For rankings between the 60th and 25th percentiles, the
dividend equivalents are prorated. The total shareholder return is measured
at the end of the initial three-year period and will set the percentage
payable for the entire term. If less than 100% of the dividend equivalents
are earned, the unearned portion may be restored later in the option term if
Edison International's cumulative total shareholder return ranking for the
option term attains at least the 60th percentile.
(3) Each Edison Mission Energy phantom stock option represents a right to
exercise an option to realize any appreciation in the value of one
hypothetical share of Edison Mission Energy stock. The value of the stock
is determined by a formula linked to project values, which are determined
annually, and is based on 10 million hypothetical shares. Project values
are determined based on economic models whose assumptions are approved by
the Net Present Value Committee and the Edison International Affiliate
Option Plan Management Committee. Subject to review by these committees,
including their judgment on how projects that operate in a competitive or
"merchant" environment should be valued for phantom option purposes, the
valuation is consistent with the bases on which Edison Mission Energy
invests, acquires, finances, refinances and otherwise makes capital
decisions for new investments and value-maximizing decisions for existing
investments. The exercise price is initially set equal to the value of the
stock on the date of grant escalated on a compound basis, 9% per year,
thereafter by a factor reflecting the approximate cost of capital during the
year as determined by the Compensation and Executive Personnel Committee of
Edison International. The annual escalation factor will be adjusted
prospectively by the Compensation and Executive Personnel Committee for
significant changes in the cost of capital. If the value of a share of
Edison Mission Energy stock exceeds the exercise price for any subsequent
year, the executive may exercise the vested portion of the options during
the 60-day annual exercise window and be paid in cash the difference between
the exercise price and the value of the shares.
When the Edison Mission Energy phantom stock options were first issued in
1994, the Edison International Compensation and Executive Personnel
Committtee believed that the awards were an appropriate incentive program
for executives of Edison Mission Energy. By the end of 1999, however, it was
the view of the Edison International Compensation and Executive Personnel
Committee that the phantom stock options had fulfilled their original
purpose. While the phantom stock options had been an important contributor
to the expansion of the business of Edison Mission Energy, they were no
longer regarded as an optimal means of providing incentives to the managers
and employees of Edison Mission Energy. Instead, the Edison International
Compensation and Executive Personnel Committee concluded that it was more
appropriate that the key employees of Edison Mission Energy have a common
interest with Edison International shareholders in the integrated operations
of Edison International reflected by the value of Edison International
Common Stock.
The operations of Edison Mission Energy contributed about 21% of Edison
International's earnings in 1999 and are sufficiently large to be reflected
in the value of its stock in the future. Because of this, the Edison
100
International Compensation and Executive Personnel Committee determined it
was no longer appropriate to maintain a separate form of long-term incentive
award at the subsidiary level. Accordingly, there will be no further grants
of Edison Mission Energy phantom stock options after 1999.
(4) The Edison International stock options become exercisable in four equal
installments beginning on the first anniversary of their date of grant.
Each option has a term of 10 years, subject to earlier expiration upon
termination of employment as described below. The options are not
transferable except upon death. Effective January 1, 1998, outstanding
Edison International stock options were amended to allow certain senior
officers to transfer Edison International stock options to a spouse, child
or grandchild. If an executive retires, dies, or is permanently and totally
disabled during the four-year vesting period, the unvested Edison
International stock options will vest and be exercisable to the extent of
1/48 of the grant for each full month of service during the vesting period.
Unvested Edison International stock options of any person who has served in
the past on the Southern California Edison Company Management Committee will
vest and be exercisable upon the member's retirement, death, or permanent
and total disability. None of the named officers have served on the
committee. Upon retirement, death or permanent and total disability, the
vested Edison International stock options may continue to be exercised
within their original term by the recipient or beneficiary. If an executive
is terminated other than by retirement, death or permanent and total
disability, Edison International stock options which had vested as of the
prior anniversary date of the grant are forfeited unless exercised within
180 days of the date of termination in the case of Edison International
stock options, or during the next 60-day exercise window in the case of
Edison Mission Energy phantom stock options. All unvested Edison
International stock options are forfeited on the date of termination.
Appropriate and proportionate adjustments may be made by the Edison
International Compensation and Executive Personnel Committee to outstanding
Edison International stock options to reflect any impact resulting from
various corporate events such as reorganizations, stock splits and so forth.
If Edison International is not the surviving corporation in such a
reorganization, all Edison International stock options then outstanding will
become vested and be exercisable unless provisions are made as part of the
transaction to continue the Edison International Equity Compensation Plan or
to assume or substitute stock options of the successor corporation with
appropriate adjustments as to the number and price of the options.
Notwithstanding the foregoing, upon a change of control of Edison
International after the occurrence of a Distribution Date under the Rights
Agreement approved by the Edison International Board of Directors on
November 21, 1996, and amended on September 16, 1999, the options will vest
and will remain exercisable for at least two years following the
Distribution Date. A Distribution Date is generally the date a person
acquires 20% or more of the Common Stock of Edison International, or a date
specified by the Edison International Board of Directors after commencement
of a tender offer for 20% or more of such stock.
The Edison International Compensation and Executive Personnel Committee
administers the Edison International Equity Compensation Plan and has sole
discretion to determine all terms and conditions of any grant, subject to
plan limits. It may substitute cash equivalent in value to the Edison
International stock options and, with the consent of the executive, may
amend the terms of any award agreement, including the price of any option,
the post-termination term, and the vesting schedule.
(5) The expiration date of the Edison International stock options is January 2,
2009; however, the final 60-day exercise period of Edison Mission Energy
phantom stock options will occur during the second quarter of that year.
The Edison International stock options are subject to earlier expiration
upon termination of employment as described in footnote (4) above.
(6) The grant date present value of each Edison International stock option was
calculated as the sum of (i) the option value and (ii) the dividend
equivalent value. The option value was calculated to be approximately $3.30
per option share using the Black-Scholes stock option pricing model. For
purposes of this calculation, it was assumed that options would be
outstanding for an average of seven years prior to exercise, the volatility
rate was assumed to be 18%, the risk-free rate of return was assumed to be
4.75%, the historic average dividend yield was assumed to be 5.38% and the
stock price and exercise price were $28.125.
The dividend equivalent value of each Edison International stock option
granted in 1999 was calculated to be $3.37. The grant date value of the
dividend equivalent rights included with respect to each Edison
101
International stock option was determined by (i) adding the dividends,
without reinvestment, over the assumed seven-year duration of the related
stock option based on the annual dividend rate at grant of $1.04 per share
in effect on January 1, 1999, and (ii) discounting that amount to its
present value assuming a discount rate of 11.60%, which was Southern
California Edison Company's authorized return on common equity in 1999. This
calculation does not reflect any reduction in value for the risk that Edison
International performance measures may not be met. The calculation of the
present value of the dividend equivalents is not a prediction of future
dividends or dividend policy, and there is no assurance that the value of
the dividend equivalents realized by an executive will be at or near the
value calculated as described above. Only a portion of the Edison
International stock options granted in 1999 was associated with dividend
equivalents.
The value of an Edison Mission Energy option was calculated to be $26.11
using the Black-Scholes stock option pricing model assuming an average
exercise period of seven years, a volatility rate of 17.58%, a risk-free
rate of return of 4.43%, a dividend yield of 0% and an exercise price of
$560.89. These assumptions are based on average values of a group of peer
companies adjusted for differences in capital structure.
The actual value that an executive may realize will depend on various
factors on the date the option is exercised, so there is no assurance the
value realized by an executive will be at or near the grant date value
estimated by the Black-Scholes model. The estimated values under that model
are based on certain assumptions and are not a prediction as to future stock
price.
102
The following table sets forth selected information with respect to the
exercise during 1999 by the executive officers named in the Summary Compensation
Table above of options to purchase shares of common stock of Edison
International and hypothetical shares of stock of Edison Mission Energy and
option values as of December 31, 1999.
AGGREGATED OPTION EXERCISES IN 1999
AND YEAR-END OPTION VALUES
Number of Value of Unexercised
Unexercised Options in-the-Money Options
at Fiscal Year-End (#) at Fiscal Year-End ($)(1)
---------------------- -------------------------
Shares Acquired Exercisable/ Exercisable/
Name on Exercise (#) Value Realized ($) Unexercisable Unexercisable
---- --------------- ------------------ ------------- -------------
Edward R. Muller
Edison International -- -- 64,625/36,575 368,250/22,531
Edison Mission Energy -- -- 108,975/24,175 15,714,488/862,909
Robert M. Edgell
Edison International 16,150 268,345(2) 38,875/25,125 207,843/16,094
Edison Mission Energy -- -- 67,939/17,291 9,685,218/606,616
S. Linn Williams
Edison International -- -- 15,142/16,458 122,156/11,800
Edison Mission Energy -- -- 41,995/10,315 6,024,531/371,947
Georgia R. Nelson
Edison International -- -- 6,183/15,183 37,487/11,800
Edison Mission Energy -- -- 18,295/9,995 2,201,274/371,379
James V. Iaco, Jr.
Edison International -- -- 5,008/15,558 26,356/11,800
Edison Mission Energy -- -- 37,943/9,807 5,365,163/367,822
(1) Edison International options are treated as in-the-money if the fair market
value of the underlying shares at December 31, 1999, exceeded the exercise
price of the options. The dollar amounts shown for Edison International
options are the differences between (i) the fair market value of the Edison
International Common Stock underlying all unexercised in-the-money options
at year-end 1999 and (ii) the exercise prices of those options. The
aggregate value at year-end 1999 of all accrued dividend equivalents,
exercisable and unexercisable, for Mr. Muller, Mr. Edgell, Mr. Williams, Ms.
Nelson and Mr. Iaco was $308,870/$0, $235,486/$0, $45,090/$0, $12,300/$0 and
$6,970/$0, respectively.
Edison Mission Energy phantom stock options are for hypothetical shares
outstanding that are non-transferable and are considered in-the-money if the
value of Edison Mission Energy phantom stock, which is determined annually by
a formula linked to project values, exceeds prescribed exercise prices.
Values at year-end are not established for purposes of an annual window
period for exercising the options until the following year. Therefore,
amounts shown reflect values at fiscal year-end for 1998, the most recent
valuation date for phantom stock option exercise purposes. See footnote (3)
to the table entitled "Option Grants in 1999" above for further information.
Edison International and Edison Mission Energy have been considering an
exchange offer of cash and stock equivalent units, relating to Edison
International Common Stock, for outstanding Edison Mission Energy phantom
stock options. Such an exchange offer was reviewed and approved by the
Edison International Board of Directors at its meetings in January and
February of 2000, subject to final approval by the Edison International
Compensation and Executive Personnel Committee of the offer terms and
documentation. In anticipation of the exchange offer and/or future exercises
of the Edison Mission Energy phantom stock options, Edison Mission Energy
accrued an additional $110 million ($67.5 million after-tax) at the end of
103
the fourth quarter of 1999, which, in combination with previously planned
accruals, resulted in an accrued balance of $254 million as of December 31,
1999.
Edison Mission Energy made payments in settlement of the phantom stock
options held by Messrs. Muller and Williams who resigned by mutual agreement
earlier this year. See the section entitled "Employment Contracts and
Termination of Employment Arrangements" below for further information
regarding the terms of these agreements.
Although the Edison International Compensation and Executive Personnel
Committee has not made a final decision on whether such an offer should be
made or on the terms of any such offer, management does not believe that an
exchange offer will be made on the schedule and terms that were reviewed by
the Committee and Board in January - February 2000. There will be an
opportunity for exercises of phantom options in an exercise window at some
time in 2000, if phantom options then remain outstanding. The determination
of the values that eligible optionees could obtain by exercising their
options in 2000 has not been completed. There can be no assurance that these
values would be the same as the values that have been considered for an
exchange offer; but management believes that the amounts previously accrued
for an exchange offer and/or future exercises of the phantom options would be
adequate to cover amounts that may be paid out in 2000 under an exchange
offer (if one is made) and/or phantom option exercises.
If the values in the exchange offer reviewed by the Edison International
Board of Directors were substituted for the deemed values at fiscal year-end
1998 in the above table, then the value of exercisable/unexercisable Edison
Mission Energy phantom stock options would be as follows:
$ / $
------------------------------------------------
Edward R. Muller 34,548,620 / 1,712,354
Robert M. Edgell 21,619,712 / 1,242,930
S. Linn Williams 13,394,484 / 724,527
Georgia R. Nelson 5,977,713 / 691,598
James V. Iaco, Jr. 12,100,852 / 671,942
Neither the deemed values at fiscal year-end 1998 nor the value accrued for
the exchange offer and/or future exercise of phantom options are necessarily
indicative of actual values as of year-end 1999 or values that an employee
might realize were the employee to exercise in the next exercise window.
(2) Includes $137,270 of value realized from dividend equivalents.
104
Retirement Benefits
- -------------------
The following table sets forth estimated gross annual benefits payable upon
retirement at age 65 to the executive officers named in the Summary Compensation
Table above in the remuneration and years of service classifications indicated.
PENSION PLAN TABLE(1)
YEARS OF SERVICE
---------------------------------------------------------------------------------------
Remuneration 10 15 20 25 30 35 40
------------ -------- -------- -------- -------- -------- -------- --------
$ 100,000 $ 25,000 $ 33,750 $ 42,500 $ 51,250 $ 60,000 $ 65,000 $ 70,000
150,000 37,500 50,625 63,750 76,875 90,000 97,500 105,000
200,000 50,000 67,500 85,000 102,500 120,000 130,000 140,000
250,000 62,500 84,375 106,250 128,125 150,000 162,500 175,000
300,000 75,000 101,250 127,500 153,750 180,000 195,000 210,000
350,000 87,500 118,125 148,750 179,375 210,000 227,500 245,000
400,000 100,000 135,000 170,000 205,000 240,000 260,000 280,000
450,000 112,500 151,875 191,250 230,625 270,000 292,500 315,000
500,000 125,000 168,750 212,500 256,250 300,000 325,000 350,000
550,000 137,500 185,625 233,750 281,875 330,000 357,500 385,000
600,000 150,000 202,500 255,000 307,500 360,000 390,000 420,000
(1) Estimates are based on the provisions of the retirement plan, a qualified
defined benefit employee retirement plan, and the executive retirement plan,
a non-qualified supplemental executive retirement plan, currently covering
Edison Mission Energy's executive officers with the following assumptions:
(i) the qualified retirement plan will be maintained, (ii) optional forms of
payment that reduce benefit amounts have not been selected, and (iii) any
benefits in excess of limits contained in the Internal Revenue Code of 1986
and any incremental retirement benefits attributable to consideration of the
annual bonus or participation in Edison Mission Energy's deferred
compensation plans will be paid out of the executive retirement plan as
unsecured obligations of Edison Mission Energy. Amounts in the Pension Plan
Table include neither the Income Continuation Plan nor the Survivor
Income/Retirement Income plans, which provide postretirement death benefits
and supplemental retirement income benefits. These plans are discussed in
"Other Retirement Benefits."
The retirement plan and the executive retirement plan provide monthly
benefits at normal retirement age, 65 years, based on a unit benefit for each
year of service plus a benefit determined by a percentage, which is commonly
referred to as the service percentage, of the executive's average highest 36
consecutive months of regular salary and, in the case of the executive
retirement plan, the average highest three bonuses in the last five years prior
to attaining age 65. Compensation used to calculate combined benefits under the
retirement plan and executive retirement plan is based on base salary and bonus
as reported in the Summary Compensation Table. The service percentage is based
on 1-3/4% per year for the first 30 years of service (52-1/2% upon completion of
30 years' service) and 1% for each year in excess of 30. The actual benefit
determined by the service percentage would take into account the unit benefit
and be offset by up to 40% of the executive's primary Social Security benefits.
105
The normal form of benefit is a life annuity with a 50% survivor benefit
following the death of the participant. Retirement benefits are reduced for
retirement prior to age 61. The amounts shown in the Pension Plan Table above
do not reflect reductions in retirement benefits due to the Social Security
offset or early retirement.
Mr. Edgell has elected to retain coverage under a previous benefit program.
This program provided, among other benefits, the post-retirement benefits
discussed in the following section. The executive retirement plan benefits
provided in the previous program are less than the benefits shown in the Pension
Plan Table. To determine these reduced benefits, multiply the dollar amounts
shown in each column by the following factors: 10 years of service -- 70%, 15
years -- 78%, 20 years -- 82%, 25 years -- 85%, 30 years -- 88%, 35 years --
88%, and 40 years -- 89%.
At December 31, 1999, Mr. Muller had completed 6 years of service; Mr.
Edgell, 29 years; Mr. Williams, 5 years; Ms. Nelson, 29 years; Mr. Iaco, 5
years.
Other Retirement Benefits
Additional post-retirement benefits are provided pursuant to the Survivor
Income Continuation Plan and the Survivor Income/Retirement Income Plan under
the Executive Supplemental Benefit Program.
The Survivor Income Continuation Plan provides a post-retirement survivor
benefit payable to the beneficiary of the executive officer following his or her
death. The benefit is approximately 24% of final compensation (salary at
retirement and the average of the three highest bonuses paid in the five years
prior to retirement) payable for ten years certain. If a named executive
officer's final annual compensation were $600,000 (the highest compensation
level in the Pension Plan Table above), the beneficiary's estimated annual
survivor benefit would be approximately $138,000. Mr. Edgell has elected
coverage under this program.
The Supplemental Survivor Income/Retirement Income Plan provides a post-
retirement survivor benefit payable to the beneficiary of the executive officer
following his or her death. The benefit is 25% of final compensation (salary at
retirement and the average of the three highest bonuses paid in the five years
prior to retirement) payable for ten years certain. At retirement, an executive
officer has the right to elect the retirement income benefit in lieu of the
survivor income benefit. The retirement income benefit is 10% of final
compensation (salary at retirement and the average of the three highest bonuses
paid in the five years prior to retirement) payable to the executive officer for
ten years certain immediately following retirement. If a named executive
officer's final annual compensation were $600,000 (the highest compensation
level in the Pension Plan Table above), the beneficiary's estimated annual
survivor benefit would be approximately $150,000. If a named executive officer
were to elect the retirement income benefit in lieu of survivor income and had
final annual compensation of approximately $600,000 (the highest compensation
level in the Pension Plan Table above), the named executive officer's estimated
annual benefit would be approximately $60,000. Mr. Edgell has elected coverage
under this program.
Employment Contracts and Termination of Employment Arrangements
Edward R. Muller. Mr. Muller served as the President and Chief Executive
officer of Edison Mission Energy beginning on August 23, 1993. On January 17,
2000, Mr. Muller resigned by mutual agreement from all positions with Edison
Mission Energy and related companies. Pursuant to the agreement, Mr. Muller was
paid $500,000 as a one-time severance payment. In addition, Edison
106
Mission Energy made a further payment to Mr. Muller in cancellation of his
vested Edison Mission Energy phantom stock options of $34.548 million in the
aggregate. This payment equaled an agreed upon amount per phantom stock option
over the exercise prices of Mr. Muller's vested phantom stock options and was
accrued as of the end of 1999 in anticipation of a contemplated exchange offer
or future phantom stock option exercises. The amount is subject to upward
adjustment if an exchange offer to similarly situated individuals is completed
at a higher price per Edison Mission Energy phantom stock option before July 18,
2000. See footnote (1) to the table above entitled "Aggregated Option Exercises
in 1999 and Year-End Option Values."
The agreement with Mr. Muller also provides for consulting services to be
rendered by him to Edison Mission Energy for a period of up to 24 months,
subject to earlier termination under certain circumstances. During the
consulting period, Edison Mission Energy will pay Mr. Muller a consulting fee at
the rate of $300,000 per annum and his unvested Edison International stock
options will continue to vest ratably. Mr. Muller's unvested Edison Mission
Energy phantom stock options will also vest ratably during the consulting period
and be paid out at the same rate per phantom stock option as was paid in
cancellation of his vested phantom stock options, up to $1.712 million in the
aggregate.
Under the agreement with Edison Mission Energy, Mr. Muller is subject to a
number of covenants, including non-competition, confidentiality, non-
solicitation, non-disparagement and non-interference.
S. Linn Williams. Mr. Williams served as Senior Vice President of Edison
Mission Energy beginning in November 1994. He was named Division President of
Edison Mission Energy's Europe, Central Asia, Middle East and Africa region in
November 1998. Mr. Williams served as General Counsel of Edison Mission Energy
from November 1994 until being named as Division President. On February 8,
2000, Mr. Williams resigned by mutual agreement from all positions with Edison
Mission Energy and related companies. Pursuant to the agreement, Mr. Williams
was paid one year's salary as severance and permitted to continue his current
living arrangements in Europe for one year. Edison Mission Energy made a
further payment to him of $11.974 million in the aggregate, in cancellation of
his vested Edison Mission Energy phantom stock options. This payment equaled an
agreed upon amount per phantom stock option over the exercise prices of Mr.
Williams' vested phantom stock options and was accrued as of the end of 1999 in
anticipation of a contemplated exchange offer or future phantom stock option
exercises. The amount is subject to upward adjustment if the exchange offer for
similarly situated individuals is completed at a higher price per share. See
footnote (1) to the table above entitled "Aggregated Option Exercises in 1999
and Year-End Option Values."
Under the agreement with Edison Mission Energy, Mr. Williams is subject to a
number of covenants, including confidentiality, non-solicitation, non-
disparagement and non-interference.
107
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
Certain Beneficial Owners
- --------------------------
Set forth below is certain information regarding each person who is known to
us to be the beneficial owner of more than five percent of our common stock.
Name and Address of Amount and Nature of Percent of
Title of Class Beneficial Owner Beneficial Ownership Class
-------------- ------------------- ---------------------- ---------------
Common Stock, no par value The Mission Group 100 shares held directly and 100%
18101 Von Karman with exclusive voting and
Avenue, Suite 1700 investment power
Irvine, California
92612
Management
- ----------
Set forth below is certain information about the beneficial ownership in
equity securities of Edison International by all directors of Edison Mission
Energy, the executive owners of Edison Mission Energy named in the Summary
Compensation Table in Item 6 and all directors and executive officers of Edison
Mission Energy as a group as of December 31, 1999. The table includes shares
that can be acquired through February 29, 2000; through the exercise of stock
options. Unless otherwise indicated, each named person has sole voting and
investment power.
Amount and Nature of
Beneficial Ownership as of
Name Company and Class of Stock December 31, 1999(a)
----- ---------------------------- ----------------------
Alan J. Fohrer Edison International Common Stock 238,900(b)
Bryant C. Danner Edison International Common Stock 221,302(c)
William J. Heller(p) Edison International Common Stock 100,606(d)
Robert M. Edgell Edison International Common Stock 65,183(e)
Edward R. Muller(n) Edison International Common Stock 79,025(f)
Mission Capital Preferred Securities 2,478(g)
S. Linn Williams(o) Edison International Common Stock 21,156(h)
Georgia R. Nelson Edison International Common Stock 16,290(i)
James V. Iaco, Jr. Edison International Common Stock 10,642(j)
Mission Capital Preferred Securities 1,950(k)
All directors and executive Edison International Common Stock 764,415(l)
officers as a group Mission Capital Preferred Securities 4,428(m)
(a) No named person or group owns more than 1% of the outstanding shares of the
class.
(b) Includes 27,374 shares credited under the Stock Savings Plus Plan and
211,026 shares that can be acquired through the exercise of options.
(c) Includes 2,576 shares credited under the Stock Savings Plus Plan and 216,726
shares that can be acquired through the exercise of options.
(d) Includes 1,006 shares credited under the Stock Savings Plus Plan and 99,600
shares that can be acquired through the exercise of options.
(e) Includes 17,607 shares credited under the Stock Savings Plus Plan and 47,576
shares that can be acquired through the exercise of options.
108
(f) Includes 77,225 shares that can be acquired through the exercise of options.
(g) Includes 280 shares held by spouse with shared voting and investment power,
and 8 shares held as co-trustee and co-beneficiary with shared voting and
investment power.
(h) Includes 130 shares credited under the Stock Savings Plus Plan and 21,026
shares that can be acquired through the exercise of options.
(i) Includes 4,598 shares credited under the Stock Savings Plus Plan and 11,692
shares that can be acquired through the exercise of options.
(j) Includes 10,642 shares that can be acquired through the exercise of options.
(k) Includes 750 shares held by spouse with shared voting and investment power.
(l) Includes 54,025 shares credited under the Stock Savings Plus Plan and
706,090 shares that can be acquired through the exercise of options. Stock
Savings Plus Plan shares for which instructions are not received from any
plan participant may be voted by the Stock Savings Plus Plan Trustee in its
discretion.
(m) Includes 1,030 shares held by spouse with shared voting and investment
power, and 8 shares held as co-trustee and co-beneficiary with shared voting
and investment power.
(n) Mr. Muller resigned as President and Chief Executive Officer, effective
January 17, 2000.
(o) Mr. Williams resigned as Senior Vice President and President of Edison
Mission Energy's Europe, Central Asia, Middle East and Africa divisions,
effective February 7, 2000.
(p) Mr. Heller resigned as a Director of Edison Mission Energy's Board,
effective February 7, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In July 1999, we made an interest-free loan to Georgia R. Nelson, Senior Vice
President and President of Midwest Generation EME, LLC, in the amount of
$179,800 in exchange for a note executed by Ms. Nelson and payable to us 365
days following the conclusion of her assignment in Chicago, Illinois.
109
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) (1) List of Financial Statements
See Index to Consolidated Financial Statements at Item 8 of this
report.
(2) List of Financial Statement Schedules
The following item is filed as a part of this report pursuant to
Item 14(d) of Form 10-K: The Cogeneration Group Combined Financial
Statements as of December 31, 1999, 1998, and 1997.
Schedule II - Valuation and Qualifying Accounts
All other schedules have been omitted since the required information
is not present in amounts sufficient to require submission of the
schedule, or because the required information is included in the
consolidated financial statements or notes thereto.
(b) Reports on Form 8-K
The registrant filed the following report on Form 8-K during the quarter
ended December 31, 1999.
Date of Report Date Filed Item Reported
--------------- ----------- --------------
December 15, 1999 December 23, 1999 2,7
(c) Exhibits
Exhibit No. Description
- ------------ -----------
2.1 Agreement for the sale and purchase of shares in First Hydro
Limited, dated December 21, 1995 between PSB Holding Limited and
First Hydro Finance Plc, incorporated by reference to Exhibit 2.1
to Edison Mission Energy's Current Report on Form 8-K, No. 1-13434
dated December 21, 1995.
2.2 Transaction Implementation Agreement, dated March 29, 1997 between
The State Electricity Commission of Victoria, Edison Mission
Energy Australia Limited, Loy Yang B Power Station Pty Ltd, Loy
Yang Power Limited, The Honourable Alan Robert Stockdale, Leanne
Power Pty Ltd and Edison Mission Energy, incorporated by reference
to Exhibit 2.2 to Edison Mission Energy's Current Report on Form
8-K, No. 1-13434 dated May 22, 1997.
2.3 Stock Purchase and Assignment Agreement dated December 23, 1998
between KES Puerto Rico, L.P., KENETECH Energy Systems, Inc., KES
Bermuda, Inc. and Edison Mission Energy del Caribe for the (i)
sale and purchase of KES Puerto Rico, L.P.'s shares in
EcoElectrica Holdings Ltd.; (ii) assignment of KENETECH Energy
Systems' rights and interests in that certain Project Note from
the Partnership; and (iii) assignment
110
Exhibit No. Description
- ------------ -----------
of KES Bermuda, Inc.'s rights and interests in that certain
Administrative Services Agreement dated October 31, 1997,
incorporated by reference to Exhibit 2.3 to Edison Mission
Energy's Annual Report on Form 10-K for the year ended December
31, 1998.
2.4 Asset Purchase Agreement, dated August 1, 1998 between
Pennsylvania Electric Company, NGE Generation, Inc., New York
State Electric & Gas Corporation and Mission Energy Westside,
Inc., incorporated by reference to Exhibit 2.4 to Edison Mission
Energy 's Annual Report for Form 10-K for the year ended December
31, 1998.
2.5 Asset Sale Agreement, dated March 22, 1999 between Commonwealth
Edison Company and Edison Mission Energy as to the Fossil Fuel
Generating Assets, incorporated by reference to exhibit 2.5 to
Edison Mission Energy's Annual Report for Form 10-K for the year
ended December 31, 1998.
2.6 Agreement for the Sale and Purchase of Shares in Contact Energy
Limited, dated March 10, 1999, between Her Majesty the Queen in
Right of New Zealand, Edison Mission Energy Taupo Limited and
Edison Mission Energy, incorporated by reference to Exhibit 2.6 to
Edison Mission Energy's Form 10-Q for the quarter ended March 31,
1999.
2.7 Sale, Purchase and Leasing Agreement between PowerGen UK plc and
Edison First Power Limited for the purchase of the Ferrybridge C
Power Station, incorporated by reference to Exhibit 2.7 to Edison
Mission Energy's Current Report on Form 8-K/A, No. 1-13434 dated
July 19, 1999.
2.8 Sale, Purchase and Leasing Agreement between PowerGen UK plc and
Edison First Power Limited for the purchase of the Fiddler's Ferry
Power Station, incorporated by reference to Exhibit 2.8 to Edison
Mission Energy's Current Report on Form 8-K/A, No. 1-13434 dated
July 19, 1999.
3.1 Amended and Restated Articles of Incorporation of Edison Mission
Energy incorporated by reference to Exhibit 3.1 to Edison Mission
Energy's Current Report on Form 8-K, No. 1-13434 dated January 30,
1996. Originally filed with Edison Mission Energy's Registration
Statement on Form 10 to the Securities and Exchange Commission on
September 30, 1994 and amended by Amendment No. 1 thereto dated
November 19, 1994 and Amendment No. 2 thereto dated November 21,
1994 (as so amended, the "Form 10").
3.2 By-Laws of Edison Mission Energy, incorporated by reference to
Exhibit 3.2 to Edison Mission Energy's Form 10.
4.1 Copy of the Global Debenture representing Edison Mission Energy's
9-7/8% Junior Subordinated Deferrable Interest Debentures, Series
A, Due 2024, incorporated by reference to exhibit 4.1 to Edison
Mission Energy's Form 10-K for the year ended December 31, 1994.
4.2 Conformed copy of the Indenture dated as of November 30, 1994
between Edison Mission Energy and The First National Bank of
Chicago, as trustee, incorporated by reference to exhibit 4.2 to
Edison Mission Energy's Form 10-K for the year ended December 31,
1994.
111
Exhibit No. Description
- ------------ -----------
4.2.1 First Supplemental Indenture dated as of November 30, 1994 to
Indenture dated as of November 30, 1994 between Edison Mission
Energy and The First National Bank of Chicago, as trustee,
incorporated by reference to exhibit 4.2.1 to Edison Mission
Energy's Form 10-K for the year ended December 31, 1994.
4.3 Indenture, dated as of June 28, 1999, between Edison Mission
Energy and The Bank of New York, as Trustee, incorporated by
reference to Exhibit 4.1 to Edison Mission Energy's Registration
Statement on Form S-4 to the Securities and Exchange Commission on
February 18, 2000.
4.3.1 First Supplemental Indenture, dated as of June 28, 1999, to
Indenture dated as of June 28, 1999, between Edison Mission Energy
and The Bank of New York, as Trustee, incorporated by reference to
Exhibit 4.2 to Edison Mission Energy's Registration Statement on
Form S-4 to the Securities and Exchange Commission on February 18,
2000.
10.1 Registration Rights Agreement, dated as of June 23, 1999, between
Edison Mission Energy and the Initial Purchasers specified
therein, incorporated by reference to Exhibit 10.1 to Edison
Mission Energy's Registration Statement on Form S-4 to the
Securities and Exchange Commission on February 18, 2000.
10.2 Power Purchase Contract between Southern California Edison Company
and Champlin Petroleum Company, dated March 8, 1985, incorporated
by reference to Exhibit 10.2 to Edison Mission Energy's Form 10.
10.2.1 Amendment to Power Purchase Contract between Southern California
Edison Company and Champlin Petroleum Company, dated July 29,
1985, incorporated by reference to Exhibit 10.2.1 to Edison
Mission Energy's Form 10.
10.2.2 Amendment No. 2 to Power Purchase Contract between Southern
California Edison Company and Champlin Petroleum Company, dated
October 29, 1985, incorporated by reference to Exhibit 10.2.2 to
Edison Mission Energy's Form 10.
10.4 Power Purchase Contract between Southern California Edison Company
and Imperial Energy Company, dated February 22, 1984,
incorporated by reference to Exhibit 10.4 to Edison Mission
Energy's Form 10.
10.4.1 Amendment to Power Purchase Contract between Southern California
Edison Company and Imperial Energy Company, dated November 13,
1984, incorporated by reference to Exhibit 10.4.1 to Edison
Mission Energy's Form 10.
10.6 Power Purchase Contract between Southern California Edison Company
and Imperial Energy Company Niland No. 2, dated April 16, 1985,
incorporated by reference to Exhibit 10.6 to Edison Mission
Energy's Form 10.
10.7 Power Purchase Contract between Southern California Edison Company
and Chevron U.S.A. Inc., dated November 9, 1984, incorporated by
reference to Exhibit 10.7 to Edison Mission Energy's Form 10.
10.7.1 Amendment No. 1 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated March 29,
1985, incorporated by reference to Exhibit 10.7.1 to Edison
Mission Energy's Form 10.
112
Exhibit No. Description
- ------------ -----------
10.7.2 Amendment No. 2 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated November
21, 1985, incorporated by reference to Exhibit 10.7.2 to Edison
Mission Energy's Form 10.
10.7.3 Amendment No. 3 to Power Purchase Contract between Southern
California Edison Company and Chevron U.S.A. Inc., dated November
21, 1985, incorporated by reference to Exhibit 10.7.3 to Edison
Mission Energy's Form 10.
10.8 Power Purchase Contract between Southern California Edison Company
and Arco Petroleum Products Company (Watson Refinery),
incorporated by reference to Exhibit 10.8 to Edison Mission
Energy's Form 10.
10.9 Power Supply Agreement between State Electricity Commission of
Victoria, Loy Yang B Power Station Pty. Ltd. and the Company
Australia Pty. Ltd., as managing partner of the Latrobe Power
Partnership, dated December 31, 1992, incorporated by reference to
Exhibit 10.9 to Edison Mission Energy's Form 10.
10.10 Power Purchase Agreement between P.T. Paiton Energy Company as
Seller and Perusahaan Umum Listrik Negara as Buyer, dated February
12, 1994, incorporated by reference to Exhibit 10.10 to Edison
Mission Energy's Form 10.
10.11 Amended and Restated Power Purchase Contract between Southern
California Energy Company and Midway-Sunset Cogeneration Company,
dated May 5, 1988, incorporated by reference to Exhibit 10.11 to
Edison Mission Energy's Form 10.
10.12 Parallel Generation Agreement between Kern River Cogeneration
Company and Southern California Energy Company, dated January 6,
1984, incorporated by reference to Exhibit 10.12 to Edison Mission
Energy's Form 10.
10.13 Parallel Generation Agreement between Kern River Cogeneration
(Sycamore Project) Company and Southern California Energy Company,
dated December 18, 1984, incorporated by reference to Exhibit
10.13 to Edison Mission Energy's Form 10.
10.14 Amendment No. 2 to Power Purchase Agreement between Southern
California Energy Company and Vulcan/BN Geothermal Power Company,
dated April 1, 1986, incorporated by reference to Exhibit 10.14 to
Edison Mission Energy's Form 10.
10.15 U.S. $325 million Bank of Montreal Revolver, dated October 29,
1993, incorporated by reference to Exhibit 10.15 to Edison Mission
Energy's Form 10.
10.15.1 U.S. $400 million Bank of America National Trust and Savings
Association Credit Agreement, dated October 27, 1994, incorporated
by reference to Exhibit 10.15.1 to Edison Mission Energy's Form
10.
10.15.2 Conformed copy of the Amended and Restated U.S. $400 million Bank
of America National Trust and Savings Association Credit
Agreement, dated as of November 17, 1994, incorporated by
reference to Exhibit 10.15.2 to Edison Mission Energy's Annual
Report on Form 10-K for the year ended December 31, 1994.
10.15.3 Conformed copy of the Second Amended and Restated U.S. $400
million Bank of America National Trust and Savings Association
Credit Agreement, dated as of October 11, 1996, incorporated by
reference to Exhibit 10.15.3 to Edison Mission Energy's Annual
Report on Form 10-K for the year ended December 31, 1996.
113
Exhibit No. Description
- ------------ -----------
10.16 Amended and Restated Ground Lease Agreement between Texaco
Refining and Marketing Inc. and March Point Cogeneration Company,
dated August 21, 1992, incorporated by reference to Exhibit 10.16
to Edison Mission Energy's Form 10.
10.16.1 Amendment No. 1 to Amended and Restated Ground Lease Agreement
between Texaco Refining and Marketing Inc. and March Point
Cogeneration Company, dated August 21, 1992, incorporated by
reference to Exhibit 10.16 to Edison Mission Energy's Form 10.
10.17 Memorandum of Agreement between Atlantic Richfield Company and
Products Cogeneration Company, dated September 17, 1987,
incorporated by reference to Exhibit 10.17 to Edison Mission
Energy's Form 10.
10.18 Memorandum of Ground Lease between Texaco Producing Inc. and
Sycamore Cogeneration Company, dated January 19, 1987,
incorporated by reference to Exhibit 10.18 to Edison Mission
Energy's Form 10.
10.19 Amended and Restated Memorandum of Ground Lease between Get Oil
Company and Ken River Cogeneration Company, dated November 14,
1984, incorporated by reference to Exhibit 10.19 to Edison Mission
Energy's Form 10.
10.20 Memorandum of Lease between Sun Operating Limited Partnership and
Midway-Sunset Cogeneration Company, incorporated by reference to
Exhibit 10.20 to Edison Mission Energy's Form 10.
10.21 Executive Supplemental Benefit Program, incorporated by reference
to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.22 1981 Deferred Compensation Agreement, incorporated by reference to
Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.23 1985 Deferred Compensation Agreement for Executives, incorporated
by reference to Exhibits to Forms 10-K filed by SCEcorp (File No.
1-2313).
10.24 1987 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
2313).
10.25 1988 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
2313).
10.26 1989 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
9936).
10.27 1990 Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
9936).
10.28 Annual Deferred Compensation Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
9936).
10.29 Executive Retirement Plan for Executives, incorporated by
reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-
2313).
10.31 Estate and Financial Planning Program for Executive Officers,
incorporated by reference to Exhibits to Forms 10-K filed by
SCEcorp (File No. 1-9936).
10.32 Letter Agreement with Edward R. Muller, incorporated by reference
to Exhibit 10.32 to Edison Mission Energy's Form 10.
114
Exhibit No. Description
- ------------ -----------
10.33 Agreement with James S. Pignatelli, incorporated by reference to
Exhibit 10.33 to Edison Mission Energy's Form 10.
10.34 Conformed copy of the Guarantee Agreement dated as of November 30,
1994, incorporated by reference to Exhibit 10.34 to Edison Mission
Energy's Form 10.
10.35 Indenture of Lease between Brooklyn Navy Yard Development
Corporation and Cogeneration Technologies, Inc., dated as of
December 18, 1989, incorporated by reference to Exhibit 10.35 to
Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 1994.
10.35.1 First Amendment to Indenture of Lease between Brooklyn Navy Yard
Development Corporation and Cogeneration Technologies, Inc., dated
November 1, 1991, incorporated by reference to Exhibit 10.35.1 to
Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 1994.
10.35.2 Second Amendment to Indenture of Lease between Brooklyn Navy Yard
Development Corporation and Cogeneration Technologies, Inc., dated
June 3, 1994, incorporated by reference to Exhibit 10.35.2 to
Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 1994.
10.35.3 Third Amendment to Indenture of Lease between Brooklyn Navy Yard
Development Corporation and Cogeneration Technologies, Inc., dated
December 12, 1994, incorporated by reference to Exhibit 10.35.3 to
Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 1994.
10.36 Conformed copy of A$200 million Bank of America National Trust and
Savings Association Credit Agreement dated November 22, 1994,
incorporated by reference to Exhibit 10.36 to Edison Mission
Energy's Annual Report on Form 10-K for the year ended December
31, 1994.
10.36.1 Conformed copy of the Amended and Restated A$200 million Bank of
America National Trust and Savings Associated Credit Agreement
dated December 12, 1994, incorporated by reference to Exhibit
10.36.1 to Edison Mission Energy's Annual Report on Form 10-K for
the year ended December 31, 1994.
10.36.2 Conformed copy of First Amendment to Amended and Restated A$200
million Bank of America National Trust and Savings Associated
Credit Agreement dated June 7, 1995, incorporated by reference to
Exhibit 10.36.2 to Edison Mission Energy's Form 10-Q for the
quarter ended September 30, 1995.
10.37 Amended and Restated Limited Partnership Agreement of Mission
Capital, L.P. dated as of November 30, 1994, incorporated by
reference to Exhibit 10.37 to Edison Mission Energy's Annual
Report on Form 10-K for the year ended December 31, 1994.
10.38 Action of General Partner of Mission Capital, L.P. creating the 9-
7/8% Cumulative Monthly Income Preferred Securities, Series A,
dated as of November 30, 1994, incorporated by reference to
Exhibit 10.38 to Edison Mission Energy's Annual Report on Form 10-
K for the year ended December 31, 1994.
10.39 Action of General Partner of Mission Capital, L.P. creating the 8-
1/2% Cumulative Monthly Income Preferred Securities, Series B,
dated as of August 8, 1995, incorporated by reference to Exhibit
10.39 to Edison Mission Energy's Form 10-Q for the quarter ended
June 30, 1995.
115
Exhibit No. Description
- ------------ -----------
10.40 Power Purchase Contract between ISAB Energy, S.r.l. as Seller and
Enel, S.p.A. as Buyer, dated June 9, 1995, incorporated by
reference to Exhibit 10.40 to Edison Mission Energy's Form 10-Q
for the quarter ended June 30, 1995.
10.41 400 million sterling pounds Barclays Bank Plc Credit Agreement,
dated December 18, 1995, incorporated by reference to Exhibit
10.41 to Edison Mission Energy's Current Report on Form 8-K,
No. 1-13434, dated December 21, 1995.
10.42 Guarantee by Edison Mission Energy dated December 1, 1995
supporting Letter of Credit issued by Bank of America National
Trust and Savings Association to secure payment of bonds issued
pursuant to the Brooklyn Navy Yard project tax-exempt bond
financing, incorporated by reference to Exhibit 10.42 to Edison
Mission Energy's Annual Report on Form 10-K for the year ended
December 31, 1995.
10.43 Guarantee by Edison Mission Energy dated December 1, 1995
supporting Letter of Credit issued by Bank of America National
Trust and Savings Association to secure Brooklyn Navy Yard's
indemnity to the New York City Industrial Development Agency
pursuant to the Brooklyn Navy Yard project tax-exempt bond
financing, incorporated by reference to Exhibit 10.43 to Edison
Mission Energy's Annual Report on Form 10-K for the year ended
December 31, 1995.
10.44 Guarantee by Edison Mission Energy dated December 20, 1996 in
favor of The Fuji Bank, Limited, Los Angeles Agency, to secure
Camino Energy Company's payments pursuant to Camino Energy
Company's Credit Agreement and Defeasance Agreement, incorporated
by reference to Exhibit 10.44 to Edison Mission Energy's Annual
Report on Form 10-K for the year ended December 31, 1996.
10.45 Power Purchase Agreement between National Power Corporation and
San Pascual Cogeneration Company International B.V., dated
September 10, 1997, incorporated by reference to Exhibit 10.45 to
Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 1997.
10.46 Power Purchase Agreement between Gulf Power Generation Co., LTD.,
and Electricity Generating Authority of Thailand, dated December
22, 1997, incorporated by reference to Exhibit 10.46 to Edison
Mission Energy's Annual Report on Form 10-K for the year ended
December 31, 1997.
10.47 Guarantee by Edison Mission Energy dated June 30, 1998 in favor of
Tri Energy Company Limited and the Sanwa Bank, Limited to
guarantee payment of 25% of Tri Energy Company Limited's aggregate
capital contributions under the Equity Bridge Loan, incorporated
by reference to Exhibit 10.47 to Edison Mission Energy's Form 10-Q
for the quarter ended September 30, 1998.
10.48 Guarantee by Edison Mission Energy dated June 30, 1998 in favor of
Tri Energy Company Limited and the Sanwa Bank, Limited to
guarantee payment of 37.5% of Tri Energy Company Limited's
aggregate capital contributions attributable to Banpu Gas and
BANPU, incorporated by reference to Exhibit 10.48 to Edison
Mission Energy's Form 10-Q for the quarter ended September 30,
1998.
10.49 Equity Support Guarantee by Edison Mission Energy dated December
23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan
Bank to guarantee certain equity funding obligations of
EcoElectrica Ltd. and EcoElectrica Holdings Ltd. pursuant to
116
Exhibit No. Description
- ------------ -----------
EcoElectrica Ltd.'s Credit Agreement dated as of October 31, 1997,
incorporated by reference to Exhibit 10.49 to Edison Mission
Energy's Annual Report on Form 10-K for the year ended December
31, 1998.
10.50 Master Guarantee and Support Instrument by Edison Mission Energy
dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the
Chase Manhattan Bank to guarantee the availability of funds to
purchase fuel for the EcoElectrica project pursuant to
EcoElectrica Ltd.'s Credit Agreement dated as of October 31, 1997
and Intercreditor Agreement dated as of October 31, 1997,
incorporated by reference to Exhibit 10.50 to Edison Mission
Energy's Annual Report on Form 10-K for the year ended December
31, 1998.
10.51 Guarantee Assumption Agreement from Edison Mission Energy, dated
December 23, 1998, under Edison Mission Energy assumed all of the
obligations of KENETECH Energy Systems, Inc. to Union Carbide
Caribe Inc., under the certain Guaranty dated November 25, 1997,
incorporated by reference to Exhibit 10.51 to Edison Mission
Energy's Annual Report on Form 10-K for the year ended December
31, 1998.
10.52 Transition Power Purchase Agreement, dated August 1, 1998 between
New York State Electric & Gas Corporation and Mission Energy
Westside, Inc., incorporated by reference to Exhibit 10.52 to
Edison Mission Energy's Annual Report on Form 10-K for the year
ended December 31, 1998.
10.53 Transition Power Purchase Agreement, dated August 1, 1998 between
Pennsylvania Electric Company and Mission Energy Westside, Inc.,
incorporated by reference to Exhibit 10.53 to Edison Mission
Energy's Annual Report on Form 10-K for the year ended December
31, 1998.
10.54 Guarantee, dated August 1, 1998 between Edison Mission Energy,
Pennsylvania Electric Company, NGE Generation, Inc. and New York
State Electric & Gas Corporation, incorporated by reference to
Exhibit 10.54 to Edison Mission Energy's Annual Report on Form 10-
K for the year ended December 31, 1998.
10.55 Credit Agreement dated as of March 18, 1999, among Edison Mission
Holdings Co. and Certain Commercial Lending Institutions, and
Citicorp USA, Inc., incorporated by reference to Exhibit 10.55 to
Edison Mission Energy's Current Report on Form 8-K, No. 1-13434
dated March 18, 1999.
10.56 Guarantee and Collateral Agreement made by Edison Mission Holdings
Co., Edison Mission Finance Co., Homer City Property Holdings,
Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc.,
Edison Mission Energy Homer City Generation L.P. and Edison
Mission Energy in favor of United States Trust Company of New
York, dated as of March 18, 1999, incorporated by reference to
Exhibit 10.56 to Edison Mission Energy's Current Report on Form 8-
K, No. 1-13434 dated March 18, 1999.
10.56.1 Amendment No. 1 to the Guarantee and Collateral Agreement, dated
May 27, 1999, between Edison Mission Holdings, Edison Mission
Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge
Energy Company, Mission Energy Westside, Inc., EME Homer City
Generation L.P. and Edison Mission Energy in favor of United
States Trust Company of New York, incorporated by reference to
Exhibit 10.56.1 to Amendment
117
Exhibit No. Description
- ------------ -----------
No. 1 of Edison Mission Holdings Co.'s Registration Statement on
Form S-4 to the Securities and Exchange Commission on February 8,
2000.
10.56.2 Open-End Mortgage, Security Agreement and Assignment of Leases and
Rents, dated March 18, 1999 from EME Homer City Generation L.P. to
United States Trust Company of New York, incorporated by reference
to Exhibit 10.56.2 to Amendment No. 1 of Edison Mission Holdings
Co.'s Registration Statement on Form S-4 to the Securities and
Exchange Commission on February 8, 2000.
10.56.3 Amendment No. 1 to the Open-End Mortgage, Security Agreement and
Assignment of Leases and Rents, dated May 27, 1999, from EME Homer
City Generation L.P. to United States Trust Company of New York,
incorporated by reference to Exhibit 10.56.3 to Amendment No. 1 of
Edison Mission Holdings Co.'s Registration Statement on Form S-4
to the Securities and Exchange Commission on February 8, 2000.
10.57 Collateral Agency and Intercreditor Agreement among Edison Mission
Holdings Co., Edison Mission Finance Co., Homer City Property
Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy
Westside, Inc., Edison Mission Energy Homer City Generation L.P.,
The Secured Parties' Representatives, Citicorp USA, Inc. as
Administrative Agent, and United States Trust Company of New York
as Collateral Agent dated as of March 18, 1999, incorporated by
reference to Exhibit 10.57 to Edison Mission Energy's Current
Report on Form 8-K, No. 1-13434 dated March 18, 1999.
10.58 Security Deposit Agreement among Edison Mission Holdings Co.,
Edison Mission Finance Co., Homer City Property Holdings, Inc.,
Chestnut Ridge Energy Co., Mission Energy Westside, Inc., Edison
Mission Energy Homer City Generation L.P., and United States Trust
Company of New York as Collateral Agent dated as of March 18,
1999, incorporated by reference to Exhibit 10.58 to Edison Mission
Energy's Current Report on Form 8-K, No. 1-13434 dated March 18,
1999.
10.58.1 Amendment No. 1 to the Security Deposit Agreement, dated May 27,
1999, between Edison Mission Holdings, Edison Mission Finance Co.,
Homer City Property Holdings, Inc., Chestnut Ridge Energy Company,
Mission Energy Westside, Inc., EME Homer City Generation L.P. and
United States Trust Company of New York, as Collateral Agent,
incorporated by reference to Exhibit 10.58.1 to Amendment No. 1 of
Edison Mission Holdings Co.'s Registration Statement on Form S-4
to the Securities and Exchange Commission on February 8, 2000.
10.59 Credit Support Guarantee, dated as of March 18, 1999, made by
Edison Mission Energy in favor of United States Trust Company of
New York, incorporated by reference to Exhibit 10.59 to Edison
Mission Energy's Current Report on Form 8-K, No. 1-13434 dated
March 18, 1999.
10.59.1 Amendment No. 1 to the Credit Support Guarantee, dated May 27,
1999, made by Edison Mission Energy in favor of United States
Trust Company of New York, incorporated by reference to Exhibit
10.59.1 to Amendment No. 1 of Edison Mission Holdings Co.'s
Registration Statement on Form S-4 to the Securities and Exchange
Commission on February 8, 2000.
118
Exhibit No. Description
- ------------ -----------
10.60 Debt Service Reserve Guarantee, dated as of March 18, 1999, made
by Edison Mission Energy in favor of United States Trust Company
of New York on behalf of the various financial institutions
(Lenders) as are or may become parties to the Credit Agreement,
dated as of March 18, 1999, among Edison Mission Holdings Co., the
Lenders, and Citicorp USA, Inc., incorporated by reference to
Exhibit 10.60 to Edison Mission Energy's Current Report on Form 8-
K, No. 1-13434 dated March 18, 1999.
10.60.1 Amendment No. 1 to the Debt Service Reserve Guarantee, dated May
27, 1999, made by Edison Mission Energy in favor of United States
Trust Company of New York, incorporated by reference to Exhibit
10.60.1 to Amendment No. 1 of Edison Mission Holdings Co.'s
Registration Statement on Form S-4 to the Securities and Exchange
Commission on February 8, 2000.
10.60.2 Bond Debt Service Reserve Guarantee, dated May 27, 1999, made by
Edison Mission Energy in favor of United States Trust Company of
New York, incorporated by reference to Exhibit 10.60.2 to
Amendment No. 1 of Edison Mission Holdings Co.'s Registration
Statement on Form S-4 to the Securities and Exchange Commission on
February 8, 2000.
10.61 Credit Agreement dated March 18, 1999, among Edison Mission
Energy, Certain Commercial Lending Institutions and Citicorp USA,
Inc., incorporated by reference to exhibit 10.61 to Edison Mission
Energy's Current Report on Form 8-K, No. 1-13434 dated March 18,
1999.
10.62 Edison First Power Limited (Pounds sterling) 1,150,000,000
Guaranteed Secured Variable Rate Bonds due 2019 Guaranteed by
Maplekey UK Limited, incorporated by reference to Exhibit 10.62 to
Edison Mission Energy's Current Report on Form 8-K/A, No. 1-13434
dated July 19, 1999.
10.63 Indenture and the First Supplemental Indenture dated as of June
28, 1999, between Edison Mission Energy and The Bank of New York,
as Trustee, 7.73% Senior Notes Due June 15, 2009, incorporated by
reference to Exhibit 10.63 to Edison Mission Energy's Form 10-Q
for the quarter ended June 30, 1999.
10.64 Coal and Capex Facility Agreement, dated July 16, 1999 between EME
Finance UK Limited; Barclays Capital and Credit Suisse First
Boston; The Financial Institutions named as Banks; and Barclays
Bank PLC as Facility Agent, incorporated by reference to Exhibit
10.64 to Edison Mission Energy's Form 10-Q for the quarter ended
September 30, 1999.
10.65 Guarantee by Edison Mission Energy dated July 16, 1999 supporting
the Coal and Capex Facility Agreement (Facility Agreement) issued
by Barclays Bank PLC to secure EME Finance UK Limited obligations
pursuant to the Facility Agreement, incorporated by reference to
Exhibit 10.65 to Edison Mission Energy's Form 10-Q for the quarter
ended September 30, 1999.
10.66 Debt Service Reserve Guarantee, dated as of July 16, 1999 made by
Edison Mission Energy in favor of Bank of America National Trust
and Savings Association.*
119
Exhibit No. Description
- ------------ -----------
10.71 Indenture, dated as of May 27, 1999, between Edison Mission
Holdings Co. and United States Trust Company of New York, as
Trustee, incorporated by reference to Exhibit 10.71 to Edison
Mission Holdings Co.'s Registration Statement on Form S-4 to the
Securities and Exchange Commission on December 3, 1999.
10.75 Exchange and Registration Rights Agreement, dated as of May 27,
1999, by and among the Initial Purchasers named therein, the
Guarantors named therein and Edison Mission Holdings Co.,
incorporated by reference to Exhibit 10.1 to Edison Mission
Holdings Co.'s Registration Statement on Form S-4 to the
Securities and Exchange Commission on December 3, 1999.
21 List of Subsidiaries.*
27 Financial Data Schedule.*
*Filed herewith
(d) Financial Statement Schedules
The financial statement schedules filed with this report are listed in
Section 14(a)(2) above.
Financial information for the Cogeneration Group for the years ended December
31, 1999, 1998, and 1997. The financial statements of the Cogeneration Group
present the combination of those entities that are 50% or less owned by Edison
Mission Energy and that met the requirements of Rule 3-09 of Regulation S-X in
1999. There were no entities which were 50% or less owned by Edison Mission
Energy that met the requirements of Rule 3-09 of Regulation S-X in 1998 and
1997.
120
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Edison Mission Energy:
We have audited the accompanying combined balance sheets of Kern River
Cogeneration Company (a general partnership between Getty Energy Company and
Southern Sierra Energy Company), Sycamore Cogeneration Company (a general
partnership between Texaco Cogeneration Company and Western Sierra Energy
Company) and Watson Cogeneration Company (a general partnership between Camino
Energy Company and Products Cogeneration Company), (collectively the
Cogeneration Group) as of December 31, 1999, and the related combined statements
of income, partners' equity and cash flows for the year then ended. These
financial statements are the responsibility of the Group's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the financial position of the Cogeneration
Group as of December 31, 1999, and the results of its operations and its cash
flows for the year then ended, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN, LLP
Los Angeles, California
March 14, 2000
121
THE COGENERATION GROUP
COMBINED STATEMENTS OF INCOME
(In Thousands)
Years Ended December 31,
-----------------------------
1999 1998 1997
---- ---- ----
(Unaudited) (Unaudited)
Operating Revenues
Sales of energy to Southern California Edison $432,989 $379,852 $402,839
Sales of energy to Texaco Exploration and Production 13,797 11,755 11,715
Sales of energy to ARCO Products Company 28,961 26,229 26,423
Sales of steam to Texaco Exploration and Production 67,357 68,441 89,682
Sales of steam to ARCO Products Company 51,831 46,943 48,216
-------- -------- --------
Total operating revenues 594,935 533,220 578,875
-------- -------- -------
Operating Expenses
Fuel 276,297 264,521 294,277
Plant operations 39,800 40,944 53,377
Depreciation and amortization 24,626 24,487 24,194
Administrative and general 20,712 19,884 8,014
------- ------- -------
Total operating expenses 361,435 349,836 379,862
------- ------- -------
Income from operations 233,500 183,384 199,013
------- ------- -------
Other Income (Expense)
Interest and other income 2,078 2,742 5,041
Interest expense (2,699) (3,327) (4,197)
------- ------- -------
Total other income (expense) (621) (585) 844
------- ------- -------
Net Income $232,879 $182,799 $199,857
======== ======== ========
The accompanying notes are an integral part of these combined financial
statements.
122
THE COGENERATION GROUP
COMBINED BALANCE SHEETS
(In Thousands)
December 31,
-------------------
1999 1998
---- ----
(Unaudited)
Assets
Current Assets
Cash and cash equivalents $ 16,026 $ 6,537
Trade receivables - affiliates 70,461 68,749
Other receivables 510 375
Inventories 19,274 18,876
Prepaid expenses and other assets 2,480 2,550
-------- -------
Total current assets 108,751 97,087
-------- -------
Property, Plant and Equipment 683,744 678,623
Less accumulated depreciation and amortization 298,914 278,520
------- -------
Net property, plant and equipment 384,830 400,103
------- -------
Other Assets
Emission credits, net 13,298 15,393
Intangible assets, net 20,568 21,699
-------- ------
Total other assets 33,866 37,092
-------- ------
Total Assets $527,447 $534,282
======== ========
The accompanying notes are an integral part of these combined financial
statements.
123
THE COGENERATION GROUP
COMBINED BALANCE SHEETS
(In Thousands)
December 31,
------------
1999 1998
---- ----
(Unaudited)
Liabilities and Partners' Equity
Current Liabilities
Accounts payable - affiliates $ 44,497 $ 37,417
Accounts payable and accrued liabilities 13,493 11,661
Current maturities of loans payable -- 2,233
------- -------
Total current liabilities 57,990 51,311
------- -------
Loans Payable, net of current maturities 53,733 53,733
-------- --------
Maintenance Accrual 23,039 20,282
-------- --------
Total liabilities 134,762 125,326
-------- --------
Commitments and Contingencies (Note 6)
Partners' Equity 392,685 408,956
-------- --------
Total Liabilities and Partners' Equity $527,447 $534,282
======== ========
The accompanying notes are an integral part of these combined financial
statements.
124
THE COGENERATION GROUP
COMBINED STATEMENTS OF PARTNERS' EQUITY
(In Thousands)
Edison Mission
Energy Texaco ARCO Total
Affiliates Affiliates Affiliates Equity
------------------- ------------- ------------- -------------
Balances at December 31, 1996 $ 205,893 $112,384 $ 97,324 $ 415,601
Cash distributions (Unaudited) (94,326) (53,900) (42,075) (190,301)
Net income (Unaudited) 99,139 60,466 40,252 199,857
--------- -------- -------- ---------
Balances at December 31, 1997 (Unaudited) 210,706 118,950 95,501 425,157
Cash distributions (Unaudited) (98,630) (56,000) (44,370) (199,000)
Net income (Unaudited) 90,677 55,261 36,861 182,799
--------- -------- -------- ---------
Balances at December 31, 1998 (Unaudited) 202,753 118,211 87,992 408,956
Cash distributions (123,510) (71,325) (54,315) (249,150)
Net income 115,461 67,540 49,878 232,879
--------- -------- -------- ---------
Balances at December 31, 1999 $ 194,704 $114,426 $ 83,555 $ 392,685
========= ======== ======== =========
The accompanying notes are an integral part of these combined financial
statements.
125
THE COGENERATION GROUP
COMBINED STATEMENTS OF CASH FLOWS
(In Thousands)
Years Ended December 31,
---------------------------------------------------------
1999 1998 1997
---------------- ---------------- ---------------
(Unaudited) (Unaudited)
Cash Flows From Operating Activities
Net income $ 232,879 $ 182,799 $ 199,857
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 24,626 24,487 24,194
Loss on disposal of assets 51 -- --
Increase in receivables (1,847) (5,721) (5,527)
Decrease (increase) in inventories (138) (2,255) 1,305
(Decrease) increase in payables 7,299 (12,335) (5,572)
(Decrease) increase in maintenance accrual 2,757 3,100 (3,750)
Other, net (41) (146) 47
--------- --------- ---------
Net cash provided by operating activities 265,586 189,929 210,554
--------- --------- ---------
Cash Flows From Investing Activities
Capital expenditures (4,835) (7,962) (19,548)
Proceeds from disposal of assets 9 -- --
--------- --------- ---------
Net cash used in investing activities (4,826) (7,962) (19,548)
--------- --------- ---------
Cash Flows From Financing Activities
Proceeds from escrow account 112 670 670
Loan repayments (2,233) (13,404) (13,404)
Distribution to partners (249,150) (199,000) (190,301)
--------- --------- ---------
Net cash used in financing activities (251,271) (211,734) (203,035)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 9,489 (29,767) (12,029)
Cash and Cash Equivalents at Beginning of Year 6,537 36,304 48,333
--------- --------- ---------
Cash and Cash Equivalents at End of Year $ 16,026 $ 6,537 $ 36,304
========= ========= =========
Supplemental Cash Flow Information
Interest paid $ 2,712 $ 3,378 $ 4,257
--------- --------- ---------
Capital expenditures accrued in accounts payable $ 1,613 $ -- $ --
--------- --------- ---------
The accompanying notes are an integral part of these combined financial statements.
126
THE COGENERATION GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 (UNAUDITED), AND 1997 (UNAUDITED)
Note 1. General
- ---------------
Principles of Combination
Edison Mission Energy, a wholly owned subsidiary of The Mission Group, a
wholly owned non-utility subsidiary of Edison International, the parent holding
company of Southern California Edison Company, has a general partnership
interest in Kern River Cogeneration Company, Sycamore Cogeneration Company, and
Watson Cogeneration Company (jointly referred to herein as the Cogeneration
Group). Southern Sierra Energy Company, Western Sierra Energy Company, and
Camino Energy Company are separate legal entities from Edison Mission Energy.
The accompanying combined financial statements have been prepared for purposes
of Edison Mission Energy complying with certain requirements of the Securities
and Exchange Commission.
Kern River Cogeneration Company, which is commonly referred to as Kern River,
is a general partnership between Getty Energy Company, a wholly owned subsidiary
of Texaco, Inc., and Southern Sierra Energy Company, a wholly owned subsidiary
of Edison Mission Energy. Kern River owns and operates a 300-MW natural gas-
fired cogeneration facility located near Bakersfield, California, which sells
electricity to Southern California Edison Company and which sells electricity
and steam to Texaco Exploration and Production, Inc., a wholly owned subsidiary
of Texaco, for use in Texaco Exploration and Production, Inc.'s enhanced oil
recovery operations in the Kern River Oil Field. Partnership income (loss) is
allocated equally to the partners.
Sycamore Cogeneration Company, which is commonly referred to as Sycamore, is
a general partnership between Texaco Cogeneration Company, a wholly owned
subsidiary of Texaco, and Western Sierra Energy Company, a wholly owned
subsidiary of Edison Mission Energy. Sycamore owns and operates a 300-MW
natural gas-fired cogeneration facility located near Bakersfield, California,
which sells electricity to Southern California Edison Company and which sells
steam to Texaco Exploration and Production, Inc. for use in Texaco Exploration
and Production, Inc.'s enhanced oil recovery operations in the Kern River Oil
Field. Partnership income (loss) is allocated equally to the partners.
Watson Cogeneration Company, which is commonly referred to as Watson, is a
general partnership between Carson Cogeneration Company, a wholly owned
subsidiary of CH-Twenty, Inc., a majority owned subsidiary of Atlantic Richfield
Company, which is commonly referred to as ARCO, Products Cogeneration Company, a
wholly owned subsidiary of ARCO and Camino Energy Company, a wholly owned
subsidiary of Edison Mission Energy. Carson Cogeneration Company, Products
Cogeneration Company and Camino Energy Company own 49 percent, 2 percent, and 49
percent, respectively. Watson owns and operates a 385-MW natural gas-fired
cogeneration facility located in Carson, California, which sells electricity to
Southern California Edison Company and which sells electricity and steam to ARCO
Products Company for use at ARCO Products Company's refinery. Partnership
income (loss) is allocated based upon the partners' respective ownership
percentage.
127
Note 2. Summary of Significant Accounting Policies
- ---------------------------------------------------
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
Inventories
Inventories are comprised of materials and supplies, and are stated at their
lower of average cost or market.
Property, Plant and Equipment
All costs, including interest and field overhead expenses, incurred during
construction and the precommission phase of the facilities were capitalized as
part of the cost of the facilities. Revenue earned during the precommission
phase was offset against the cost of the facilities. The facilities and related
equipment are being depreciated on a straight-line basis over approximately 30
years, which are the estimated useful lives of the facilities.
Emission Credits
Two of the Cogeneration Group's facilities were required to obtain
assignments of emission offset credits in order to be certified by the
California Energy Commission. These credits were required to meet the current
environmental regulations as they relate to the emissions being produced from
the operation of these facilities. The cost of these emission credits are
stated net of accumulated amortization of $27.4 million and $25.3 million at
December 31, 1999 and 1998, respectively (see Note 5). The emission credits are
being amortized on a straight-line basis over their 19-year license period.
Intangible Assets
Intangible assets are stated net of accumulated amortization of $15.2 million
and $14.1 million at December 31, 1999 and 1998, respectively, and consist of
outside boundary limit facilities, refinery infrastructure, environment permits
and land use, as outlined in the various partnership agreements, contributed to
the Cogeneration Group. All of the intangible assets relate to the operations
of the various facilities, and as a result, are being amortized on a straight-
line basis over the estimated useful life of the facilities.
Statements of Cash Flows
For the purposes of reporting cash flows, the Cogeneration Group considers
short-term temporary cash investments with an original maturity of three months
or less to be cash equivalents.
Maintenance Accruals
The Cogeneration Group follows the turbine manufacturer's recommended
maintenance intervals which call for a hot gas path inspection approximately
every 24,000 - 30,000 operating hours and a major overhaul approximately every
48,000 - 60,000 operating hours. Expenses for these events are
128
accrued for on a straight-line basis over the expected operating-hour interval
between each like maintenance event. Expenditures for minor maintenance, repairs
and renewals are charged to expense as incurred. Expenditures for additions and
improvements are capitalized.
The accruals for repair and maintenance events are based on management's
estimates of what these events will cost at the time the events occur. Due to
fluctuations in prices and changes in the timing of the scheduled events, the
estimated costs of these events can differ from actual costs incurred.
Fair Value of Financial Instruments
The carrying amount of the short-term investments approximates fair value due
to the short maturities of such investments. The estimated fair value of loans
payable is discussed in Note 4.
Income Taxes
The Cogeneration Group is treated as a partnership for income tax purposes
and the income or loss of the Cogeneration Group is included in the income tax
returns of the individual partners. Accordingly, no recognition has been given
to income taxes in the financial statements.
Note 3. Property, Plant and Equipment
- --------------------------------------
Plant and equipment consist of the following:
December 31,
------------------------------------
1999 1998
----------------- ----------------
(in millions)
Plant and equipment (Unaudited)
Power plant facilities $676.5 $672.3
Building, furniture and office equipment 6.1 6.1
Construction in process 1.1 0.2
------ ------
683.7 678.6
Less -- Accumulated depreciation and amortization 298.9 278.5
------ ------
$384.8 $400.1
====== ======
Note 4. Loans Payable
- ---------------------
December 31,
------------------------------------
1999 1998
----------------- ----------------
(in millions)
Watson project: (Unaudited)
Note payable to ARCO (5%) $27.4 $27.4
Note payable to Camino Energy Company (5%) 26.3 26.3
Sycamore project:
$165 million Loan and Credit Agreement due 1999
(Eurodollar rate + 0.625%) (6.625% at 12/31/98) -- 2.2
----- -----
Subtotal 53.7 55.9
Current maturities of loans payable -- (2.2)
----- -----
Total $53.7 $53.7
===== =====
129
The above agreement for the Sycamore project is secured by certain assets of
Sycamore, and places certain restrictions on capital distributions. In
addition, this agreement requires Sycamore to maintain escrow deposits based
upon outstanding loan amounts. Based upon borrowing rates currently available
to Sycamore for long-term debt with similar terms and maturity, the fair value
of the amount outstanding at December 31, 1998 under this agreement approximates
the carrying value.
The fair value of the two Watson project notes was approximately $52.5
million and $55.4 at December 31, 1999 and 1998, respectively.
The Watson project notes matures in 2008.
Note 5. Related-Party Transactions/Contractual Obligations
- ----------------------------------------------------------
Operating and Other Costs
The amounts incurred by us, Texaco and their respective affiliates for
operating and other costs charged to the Cogeneration Group, which are not
disclosed elsewhere, were as follows:
(In Millions)
------------------------------------
1999 1998 1997
-------- -------- --------
(Unaudited) (Unaudited)
Texaco and affiliates $ 3.8 $ 4.1 $ 4.4
Edison Mission Energy and affiliates $ 1.3 $ 1.3 $ 1.2
Emission Credits
Certain affiliates of Texaco assigned their rights to certain emission offset
credits to certain partnerships within the Cogeneration Group for a period of 21
years. These emission offset credits were earned by the Texaco affiliates by
reducing specified emissions at other of their operations. Such credits are
used by the Cogeneration Group to allow certain partnerships' facilities to
operate under current environmental regulations. The credits were required by
those facilities in order to be certified by the California Energy Commission
and are required to be maintained throughout the period of operations of those
facilities. The credits were reflected as a capital contribution by such
entities at the fair market value of $40.8 million.
Interconnection Facilities Agreement
Under the terms of an Interconnection Facilities Agreement, one of the
partnerships within the Cogeneration Group pays a monthly charge of 1.7 percent
of the added investment, as defined, for a portion of the Interconnection
Facilities which are owned, operated and maintained by Southern California
Edison Company. Amounts paid under this agreement were $1.6 million for the
three years ended December 31, 1999, 1998, and 1997.
Fuels Management Agreement
Certain partnerships of the Cogeneration Group are party to agreements with
Texaco Natural Gas, Inc., whereby Texaco Natural Gas, Inc. is to procure and
manage all fuel-gas supplies and transportation for two of the facilities
(except fuel-gas supplies procured and delivered under tariff-gas contracts,
provided under an excepted contract or otherwise excluded from these agreements
by the mutual consent of the partners).
130
As of January 1, 1996, the Amended and Restated Fuel Management Agreement,
terminating on October 1, 2002, was entered into such that Texaco Natural Gas,
Inc. will receive a fixed service fee of $.0375 per MMBtu of fuel gas supplied
to certain of partnerships within the Cogeneration Group, subject to escalation
as defined in the agreement. As of December 31, 1999, Texas Natural Gas, Inc.
received a fixed service fee of $.0386 per MMBtu. The amounts incurred under
the amended agreements were $177.4 million, $168.8 million and $183.5 million,
which included fees earned by Texaco Natural Gas, Inc. of $2.5 million, $2.5
million and $0.4 million, for the three years ended December 31, 1999, 1998, and
1997, respectively.
One of the partnerships within Cogeneration Group has entered into a fuel,
refinery gas and butane, purchase agreement with a subsidiary of ARCO. This
partnership's purchases under this agreement amounted to $32.4 million, $39.9
million and $40.9 million for the three years ended December 31, 1999, 1998, and
1997, respectively.
Operation and Maintenance Agreement
Two of the partnerships within the Cogeneration Group have agreements with
Edison Mission Operation & Maintenance, Inc., a wholly owned subsidiary of
Edison Mission Energy, whereby Edison Mission Operation & Maintenance, Inc.
shall perform all operation and maintenance activities necessary for the
production of electricity and steam by these partnerships' facilities. The
agreements will continue until terminated by either party. Edison Mission
Operation & Maintenance, Inc. is paid for all costs incurred in connection with
operating and maintaining the facility. Edison Mission Operation & Maintenance,
Inc. may also earn incentive compensation as set forth in the agreements. The
amounts incurred by the Cogeneration Group under these agreements were $6.1
million, $6.1 million, and $6.3 million, which included incentive compensation
earned by Edison Mission Operation & Maintenance, Inc. of $0.9 million for each
of the three years ended December 31, 1999, 1998, and 1997, respectively.
One partnership within the Cogeneration Group has an agreement with a
subsidiary of ARCO, whereby the subsidiary shall perform all operation and
maintenance activities necessary for the production of electricity and steam by
this Cogeneration Group's facility. The agreement will continue until
termination of the Power Purchase Agreement in April 2008. The ARCO subsidiary
is reimbursed for all costs incurred in connection with operating and
maintaining the facility. The amounts incurred under this agreement were $5.6
million, $4.8 million, and $5 million for the three years ended December 31,
1999, 1998, and 1997, respectively. Additionally, ARCO provides other ancillary
services under a service contract for a fee. Total service fees earned by ARCO
were $1.4 million for the three years ended December 31, 1999, 1998, and 1997.
Steam Purchase and Sale Agreements
Certain partnerships within the Cogeneration Group have agreements with
Texaco Exploration and Production, Inc. for the sale of steam generated by these
partnerships' facilities. The agreements terminate 20 years from the date of
the first sale of steam thereunder. Texaco Exploration and Production, Inc.
pays this group a steam fuel charge based upon the quantity and quality of steam
delivered during the month, which is priced at the lesser of the current
Southern California Gas Company Border Gas Price, or the weighted average posted
price of Kern River Crude, less any severance, excise or windfall profit taxes,
and a processing charge per MMBtu as defined in the agreements. The quantity of
steam sold under this contract is expected to be sufficient for the Cogeneration
Group to maintain qualifying facility status.
131
These agreements have been amended whereby the partnerships will reduce a
portion of steam prices in 1999 and to a limited extent 1998. Reductions in
steam revenues based upon these agreements totaled $20.9 and $2.2 million for
the two years ended December 31, 1999 and 1998, respectively.
Parallel Generation Agreements
The Cogeneration Group has two Parallel Generation Agreements with Southern
California Edison Company for the sale of net energy and contract capacity
generated by the Cogeneration Group. The Parallel Generation Agreements will
remain in effect 20 years from the firm operation date, August 9, 1985 and
January 1, 1998, respectively. The Parallel Generation Agreements were amended
to contain energy pricing terms that maintain the intent of the Parallel
Generation Agreements' original pricing terms. Energy payments are currently
based on an energy rate that is calculated using a short-run-avoided-cost, which
is commonly referred to as SRAC, based formula, that contains a prescribed
energy rate indexed to the Southern California Border Spot Price of natural gas,
and the quantity of kilowatts delivered during on-peak, mid-peak, off-peak and
super off-peak hours. Southern California Edison Company also pays the
Cogeneration Group for firm capacity based upon a contracted amount per kilowatt
year, as defined in the Parallel Generation Agreements.
Pursuant to the amendment, on and after the date on which SRAC energy
payments are based on the clearing price paid by the independent Power Exchange
the energy pricing shall be the greater of (i) the price obtained from the SRAC-
based formula, or (ii) the average Power Exchange prices during the month for
the delivery period which are equal to the "day ahead" market clearing prices
published by the Power Exchange, or (iii) the average Power Exchange prices
during the month for the delivery period which Southern California Edison
Company uses to establish its retail rates. The SRAC-based formula energy price
will be compared to the energy price posted by the California Power Exchange
price, which will be discounted by 4%. The higher of the two prices will be used
to calculate energy payments due the partnership.
Pursuant to the amendment, the Cogeneration Group received a one-time payment
from Southern California Edison Company in the amount of $35.3 million during
1999 that adjusted for the difference between the sum of payments made to the
Partnership for the deliveries of energy after October 14, 1996, through March
1999, and the sum of payments for such energy determined by the SRAC-based
formula. The amount of the payment is included in 1999 sales of energy to
Southern California Edison Company.
The Parallel Generation Agreements require the Cogeneration Group to make
repayment of capacity payments to Southern California Edison Company, the power
purchaser for the project, in the event the Partnership unilaterally terminates
its Parallel Generation Agreements prior to the term of the Parallel Generation
Agreements, or reduces its electric power output below contract capacity during
the term of the Parallel Generation Agreements. Obligations that the
Partnership could be exposed to in the event of early termination under the
Parallel Generation Agreements as of December 31, 1999, would be approximately
$106.7 million. We have no reason to believe that the Partnership will either
terminate its Parallel Generation Agreements or reduce its electric power output
below contract capacity during the term of the Parallel Generation Agreements.
Natural Gas Supply and Transportation Agreement
The Cogeneration Group purchases gas on the spot market. As such, the
Cogeneration Group may be exposed, in the short-term, to fluctuations in the
price of natural gas, however, fluctuations in the prices paid for gas are
implicitly tied to the revenues received for either power or steam under the
agreements.
132
Note 6. Commitments and Contingencies
- --------------------------------------
Ship or Pay
Pursuant to the Master Agreement, entered into as of December 1, 1994,
certain partnerships of the Cogeneration Group executed a Security of Supply
Agreement with an affiliated partnership of Edison Mission Energy and Texaco.
As such the Cogeneration Group has agreed to accept and underwrite, on a pro-
rata basis, a portion of Texaco's commitment pursuant to the Transportation
Agreement between Texaco, the Mojave Pipeline Company and the El Paso Pipeline
Company, dated February 15, 1989 and extending through March 31, 2008. The
Cogeneration Group has agreed that Mojave Pipeline Company and El Paso Pipeline
Company shall be the exclusive means of delivery for certain partnerships within
the Cogeneration Group of the lesser of 75 percent of the annual total natural
gas fuel requirements for such Cogeneration Group and 52,012,500 MMBtu per year.
Except upon the occurrence of certain permissible events, two of the
partnerships within the Cogeneration Group are subject to certain terms and
conditions, whereby failure to transport the required quantity of natural gas on
the Mojave Pipeline Company's pipeline will result in the Cogeneration Group
paying $0.63 per deficit MMBtu. Such Cogeneration Group will share any ship-or-
pay liabilities on a pro-rata basis, as defined in the Transportation Agreement,
with the affiliated partnership.
For each of the years in the three-year period ended December 31, 1999, the
transportation quantities required under the Transportation Agreement were met.
It is the opinion of the relevant Cogeneration Group's management that these
commitments will continue to be met upon current projections for the operations
of such Cogeneration Group's facilities.
133
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Edison Mission Energy
(Registrant)
By: /s/ Kevin M. Smith
----------------------------------------------------------------------------
KEVIN M. SMITH, SENIOR VICE PRESIDENT and CHIEF FINANCIAL OFFICER
Date: March 30, 2000
--------------------------------------------------------------------------
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
Principle Executive Officer:
Alan J. Fohrer President and Chief Executive Officer March 30, 2000
Controller or Principal Accounting Officer:
Thomas E. Legro Vice President and Controller March 30, 2000
Majority of Board of Directors:
John E. Bryson Chairman of the Board March 30, 2000
Bryant C. Danner Director March 30, 2000
Thomas R. McDaniel Director March 30, 2000
134
SCHEDULE II
EDISON MISSION ENERGY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
Additions
----------------------------------
Balance at Charged to Charged to
Beginning Costs and Other Balance at End
Description of Year Expenses Accounts Deductions of Year
- ----------- ------- -------- -------- ---------- -------
Year Ended December 31, 1999
Allowance for doubtful accounts -- $ 1,126 -- -- $ 1,126
Maintenance Accruals $26,053 $37,673 $ 54 $38,116 $25,664
Year Ended December 31, 1998
Allowance for doubtful accounts -- -- -- -- --
Maintenance Accruals $21,209 $10,663 $263 $ 6,082 $26,053
Year Ended December 31, 1997
Allowance for doubtful accounts -- -- -- -- --
Maintenance Accruals $17,178 $11,149 -- $ 7,118 $21,209
135