ITEM 1. BUSINESS
The Company - -----------
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 - --------------------------
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 - -------------------
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".
Description of Business - -----------------------
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.
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
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
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.
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
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
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.
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.
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
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.
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
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.
Description of Domestic Operating Projects
We have ownership interests in the following domestic operating projects:
(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:
(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.
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:
(1) Operated by an Edison Mission Energy international operating affiliate. (2) Electric purchaser abbreviations are as follows:
(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
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
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
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
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
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
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
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
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
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.
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.
ITEM 2.
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
ITEM 3.
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.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Inapplicable.
PART II
ITEM 5.
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
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
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
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
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.
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.
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
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.
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
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.
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.
Firm Commitments to Contribute Project Equity
(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
(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
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
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,
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.
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
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
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
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
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.
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.
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.
ITEM 7A.
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.
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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
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:
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.
Income Taxes
We are included in the consolidated federal income tax and combined state franchise tax returns of Edison International. We calculate our income tax provision on a separate company basis under a tax sharing arrangement with The Mission Group, which in turn has an agreement with Edison
International. Tax benefits generated by us and used in the Edison International consolidated tax return are recognized by us without regard to separate company limitations.
We account for income taxes using the asset-and-liability method, wherein deferred tax assets and liabilities are recognized for future tax consequences of temporary differences between the carrying amounts and the tax bases of assets and liabilities using enacted rates. Investment and energy tax credits are deferred and amortized over the term of the power purchase agreement of the respective project. Income tax accounting policies are discussed further in Note 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
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:
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.
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.
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
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.
The table below summarizes additional acquisitions by Edison Mission Energy or its wholly owned subsidiaries from 1997 through 1999.
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:
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:
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.
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:
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:
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
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:
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
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
(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
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
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:
Fair values of financial instruments were:
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
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.
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
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:
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:
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:
The components of the deferred tax provision (credit), which arise from tax credits and timing differences between financial and tax reporting, are presented below:
Variations from the 35% federal statutory rate are as follows:
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.
Information on plan assets and benefit obligations is shown below:
Components of pension expense were:
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:
The components of postretirement benefits other than pensions expense were:
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
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:
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
$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
(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
(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 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 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, 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
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
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:
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.
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 - -----------------------------------------------------------
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.
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.
(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.
Note 17. Quarterly Financial Data (unaudited) - --------------------------------------------------
(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.
PART III
ITEM 10.
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.
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.
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.
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
ITEM 11.
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.
(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
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.
(*) Less than
(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
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
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.
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
(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
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.
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)
(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.
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
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.
ITEM 12.
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.
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.
(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.
(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.
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.
PART IV
ITEM 14.
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
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.
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.
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.
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.
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.
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
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
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.
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.*
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.
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
THE COGENERATION GROUP COMBINED STATEMENTS OF INCOME (In Thousands)
The accompanying notes are an integral part of these combined financial statements.
THE COGENERATION GROUP COMBINED BALANCE SHEETS (In Thousands)
The accompanying notes are an integral part of these combined financial statements.
THE COGENERATION GROUP COMBINED BALANCE SHEETS (In Thousands)
The accompanying notes are an integral part of these combined financial statements.
THE COGENERATION GROUP COMBINED STATEMENTS OF PARTNERS' EQUITY (In Thousands)
The accompanying notes are an integral part of these combined financial statements.
THE COGENERATION GROUP COMBINED STATEMENTS OF CASH FLOWS (In Thousands)
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.
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
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:
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).
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.
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.
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.
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)
SCHEDULE II
EDISON MISSION ENERGY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS (In thousands)