ITEM 1. BUSINESS
THE COMPANY
We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States.
We were formed in 1986 with two domestic operating projects. As of December 31, 2000, we owned interests in 33 domestic and 40 international operating power projects with an aggregate generating capacity of 28,036 megawatts (MW), of which our share was 22,759 MW. At that date, one domestic and one international project, totaling 603 MW of generating capacity, of which our anticipated share will be approximately 462 MW, were in construction. At December 31, 2000, we had consolidated assets of $15.0 billion and total shareholder's equity of $2.9 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 includes forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events based upon our knowledge of facts as of the date of this annual report and our assumptions about future events. These forward-looking statements are subject to various risks and uncertainties that may be outside our control, including, among other things:
- the direct and indirect effects of the current California power crisis on us and our investments, as well as the measures adopted and being contemplated by federal and state authorities to address the crisis;
- general political, economic and business conditions in the countries in which we do business;
- governmental, statutory, regulatory or administrative changes or initiatives affecting us or the electricity industry generally;
- political and business risks of international projects, including uncertainties associated with currency exchange rates, currency repatriation, expropriation, political instability, privatization efforts and other issues;
- supply, demand and price for electric capacity and energy in the markets served by our generating units;
- competition from other power plants, including new plants and technologies that may be developed in the future;
- operating risks, including equipment failure, dispatch levels, availability, heat rate and output;
- the cost, availability and pricing of fuel and fuel transportation services for our generating units;
- our ability to complete the development or acquisition of current and future projects;
- our ability to maintain an investment grade rating; and
- our ability to refinance short-term debt or raise additional financing for our future cash requirements.
We use words like "believe," "expect," "anticipate," "will," "estimate," "project," "plan" and similar expressions to help identify forward-looking statements in this annual report.
For additional factors that could affect the validity of our forward-looking statements, you should read "--Project Development--Risk Factors Associated with the California Power Crisis," "--Project Development--Risk Factors Associated with our Liquidity," "--Project Development--Risk Factors Associated with Project Development, Finance and Operation," "Management's Discussion and Analysis of Results of Operations and Financial Condition" and 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 us with the Securities and Exchange Commission. In light of these and other risks, uncertainties and assumptions, actual events or results may be very different from those expressed or implied in the forward-looking statements in this annual report or may not occur. We have no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
SEGMENT INFORMATION
We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific and Europe, Central Asia, Middle East and Africa. 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 "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements, Note 17. Business Segments."
DESCRIPTION OF BUSINESS
GENERAL OVERVIEW
We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States. We were formed in 1986 with two domestic operating projects. As of December 31, 2000, we owned interests in 33 domestic and 40 international operating power projects with an aggregate generating capacity of 28,036 MW, of which our share was 22,759 MW. One domestic and one international project totaling 603 MW of generating capacity, of which our anticipated share was approximately 462 MW, were then in construction stage. At December 31, 2000, we had consolidated assets of $15.0 billion and total shareholder's equity of $2.9 billion.
Until the enactment of the Public Utility Regulatory Policies Act of 1978, utilities were the only producers of bulk electric power intended for sale to third parties in the United States. The Public Utility Regulatory Policies Act encouraged the development of independent power by removing regulatory constraints relating to the production and sale of electric energy by certain non-utilities and requiring electric utilities to buy electricity from certain types of non-utility power producers, qualifying facilities, under certain conditions. The passage of the Energy Policy Act of 1992 further encouraged the development of independent power by significantly expanding the options available to independent power producers with respect to their regulatory status and by liberalizing transmission access. As a result, a significant market for electric power produced by independent power producers, such as us, has developed in the United States since the enactment of the Public Utility Regulatory Policies Act. In
1998, utility deregulation in several states led utilities to divest generating assets, which has created new opportunities for growth of independent power in the United States.
The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity in developing countries have also led to the development of significant new markets for independent power producers outside the United States. We believe that we are well-positioned to continue to realize opportunities in these new foreign markets. See "--Strategic Overview".
RECENT DEVELOPMENTS
THE CALIFORNIA POWER CRISIS
Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of the three major utilities, Southern California Edison and Pacific Gas and Electric Co., have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers and others. Given these and other payment defaults, creditors of Southern California Edison and Pacific Gas and Electric could file involuntary bankruptcy petitions against these companies. For more information on the current regulatory situation in California, see "--Regulatory Matters-- California Deregulation." For more information on how the current California power crisis affects our investments in energy projects in California, see "--Project Development--Risk Factors Associated with the California Power Crisis."
Southern California Edison's current financial condition has had, and may continue to have, an adverse impact on Edison International's credit quality and, as previously reported by Edison International, has resulted in cross-defaults under Edison International's credit facilities. Both Standard & Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the credit ratings of Edison International and Southern California Edison to substantially below investment grade levels. The ratings remain under review for potential downgrade by both Standard & Poor's and Moody's.
We have taken measures to isolate ourselves from the credit downgrades of Edison International and Southern California Edison, and to facilitate our ability and the ability of our subsidiaries to maintain their respective investment grade ratings. For more information on our actions, see "Management's Discussion and Analysis of Results of Operations and Financial Conditions--Credit Ratings."
STRATEGIC OVERVIEW
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, our strategy focuses on enhancing the value of existing assets, expanding plant capacity at existing sites and developing new projects in locations where we have an established position or otherwise determine that attractive financial performance can be realized. In addition, because a number of our projects in developed countries, known as merchant plants, sell power into markets without the certainty of long-term contracts, we conduct power marketing, trading, and risk
management activities to stabilize and enhance the financial performance of these projects. We also recognize that our principal customers are regulated utilities. We therefore strive to understand the regulatory and economic environment in which the utilities operate so that we may continue to create mutually beneficial relationships and business dealings.
In developing countries, our strategy focuses on investing with strategic partners, securing limited recourse financing based upon long-term power purchase agreements with state owned utilities and securing government financial support from organizations such as the Export-Import Bank of the United States, the U.S. Overseas Private Investment Corporation and the Japan Bank for International Cooperation. In addition, for some projects, we have obtained political risk insurance from private companies.
In making investment decisions, we evaluate potential project returns against our internally generated rate of return guidelines. We establish these guidelines by identifying a base rate of return and adjusting the base rate by potential risk factors, such as risks associated with project location and stage of project development. We endeavor to mitigate these risks by (i) evaluating all projects and the markets in which they operate, (ii) selecting strategic partners with complementary skills and local experience, (iii) structuring investments through subsidiaries, (iv) managing up front development costs, (v) utilizing limited recourse financing and (vi) linking revenue and expense components where appropriate.
In response to the increasing globalization of the independent power market, we have organized our operation and development activities into three geographic regions: (i) Americas, (ii) Asia Pacific and (iii) Europe, Central Asia, Middle East and Africa. Each region is served by one or more teams consisting of business development, operations, finance and legal personnel, and each team is responsible for all our activities within a particular geographic region. Also, we mobilize personnel from outside a particular region when needed in order to assist in the development of specified projects.
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. For further information regarding our 33 domestic operating projects, see "--Our Operating Projects--Description of Domestic Operating Projects." For further information regarding our 40 international operating projects, see "--Our Operating Projects--Description of International Operating Projects."
AMERICAS
Our Americas region is headquartered in Irvine, California with additional offices located in Chicago, Illinois; Boston, Massachusetts; 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 expand our generation at existing sites, sometimes referred to as "brownfield" development, (iii) to pursue the development of new power projects throughout the region, sometimes referred to as "greenfield" development and (iv) to a lesser extent than we had in the past, to pursue the acquisition and development of existing generating assets from utilities, industrial companies and other independent power producers throughout the region. We currently have 33 operating projects in this region, all of which are presently located in the United States and its territories.
In March 1999, we acquired 100% of the 1,884 MW Homer City Electric Generating Station for approximately $1.8 billion. This facility is a coal fired plant in the mid-Atlantic region of the United States and has direct, high voltage interconnections to both the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly known as the NYISO, and the Pennsylvania-New Jersey-Maryland Power Pool, which is commonly known as the PJM. We operate the plant, which we believe is one of the lowest-cost generation facilities in the region.
In December 1999, we acquired the fossil-fuel generating plants of Commonwealth Edison, a subsidiary of Exelon Corporation, which are collectively referred to as the Illinois Plants, totaling 6,841 MW of generating capacity, for approximately $4.1 billion. We operate these plants, which provide access to the Mid-America Interconnected Network and the East Central Area Reliability Council. In connection with this transaction, we entered into power purchase agreements with Commonwealth Edison with a term of up to five years. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, LLC. Concurrently with this acquisition, we assigned our right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating station located in Illinois, to third party lessors. After this assignment, we entered into a lease of the Collins Station with a term of 33.75 years. The aggregate megawatts either purchased or leased as a result of these transactions is 9,539 MW. See "Management's Discussion and Analysis of Results of Operations and Financial Condition--Acquisitions, Dispositions and Sale-Leaseback Transactions--Sale-Leaseback Transactions" for a description of the Powerton and Joliet sale-leaseback transactions.
In September 2000, we completed a transaction with P&L Coal Holdings Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading operations of Citizens Power LLC and a minority interest in structured transaction investments relating to long-term power purchase agreements. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. By the end of the third quarter of 2000, we merged our own marketing operations with the Citizens trading operations under Edison Mission Marketing & Trading, Inc.
In November 2000, we completed a transaction with Texaco Inc. to purchase a proposed 560 MW gas fired combined cycle project to be located in Kern County, California, referred to as the Sunrise Project. The acquisition includes all rights, title and interest held by Texaco in the Sunrise Project, except that Texaco has an option to repurchase a 50% interest in the project prior to its commercial operation. As part of this transaction, we also: (i) acquired from Texaco an option to purchase two gas turbines which we plan to utilize in the project, (ii) provided Texaco an option to purchase two of the turbines available to us under the Edison Mission Energy Master Turbine Lease and (iii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future power plant projects we designate. For more information on the Edison Mission Energy Master Turbine Lease, see "Management's Discussion and Analysis of Results of Operations and Financial Condition--Commitments and Contingencies--Edison Mission Energy Master Turbine Lease." The Sunrise Project consists of two phases, with Phase I, construction of a single-cycle gas fired facility (320 MW), currently scheduled to be completed in August 2001, and Phase II, conversion to a combined-cycle gas fired facility (560 MW), currently scheduled to be completed in June 2003. In December 2000, we received the Energy Commission Certification and a permit to construct the Sunrise plant, which allowed us to commence construction of Phase I. We are negotiating with the California Department of Water Resources the detailed terms and conditions of a long-term, cost-based-type rate power purchase agreement. We cannot assure you that we will be successful in reaching a final agreement.
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. We currently have 14 operating projects in this region that are located in Australia, Indonesia, Thailand and New Zealand.
The Paiton project is a 1,230 MW coal fired power plant in operation in East Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a $490 million investment in the Paiton project at December 31, 2000. The project's tariff under the power purchase agreement with PT PLN is higher in the early years and steps down over time. The tariff for the Paiton project includes costs relating to infrastructure to be used in common by other units at the Paiton complex. The plant's output is fully contracted with the state-owned electric company, PT PLN. Payments are in Indonesian Rupiah, with the portion of the payments intended to cover non-Rupiah project costs, including returns to investors, adjusted to account for exchange rate fluctuations between the Indonesian Rupiah and the U.S. dollar. The project received substantial finance and insurance support from the Export-Import Bank of the United States, the Japan Bank for International Cooperation, the U.S. Overseas Private Investment Corporation and the Ministry of Economy, Trade and Industry of Japan. PT PLN'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 PLN might not be able to honor the power purchase agreement with P.T. Paiton Energy, the project company. 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.
In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the Paiton project had achieved commercial operation under the terms of the power purchase agreement and, in July 1999, that the second 615 MW unit of the plant had similarly achieved commercial operation. Because of the economic downturn, PT PLN was then experiencing low electricity demand and PT PLN, through February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a lawsuit contesting the validity of its agreement to purchase electricity from the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in connection with this withdrawal, the parties entered into an interim agreement for the period through December 31, 2000, under which dispatch levels and fixed and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made all fixed payments due under the interim agreement totaling $115 million and all payments due for energy delivered by the plant to PT PLN. As part of the continuing negotiations on a long-term restructuring of the tariff, Paiton Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provides for fixed monthly payments aggregating $108 million over its six month duration and for the payment for energy delivered to PT PLN from the plant during this period. Paiton Energy and PT PLN intend to complete the negotiations of the further phases of a new long-term tariff during the six month duration of the Phase I Agreement. To date, PT PLN has made all fixed and energy payments due under the Phase I Agreement.
Events, including those discussed above, have occurred which may mature into defaults of the project's debt agreements following the passage of time, notice or lapse of waivers granted by the project's lenders. On October 15, 1999, the project entered into an interim agreement with its lenders pursuant to which the lenders waived defaults during the term of the agreement and effectively agreed to defer payments of principal until July 31, 2000. In July, the lenders agreed to extend the term of the lender interim agreement through December 31, 2000. In December 2000, the lenders agreed to an additional extension of the lender interim agreement through December 31, 2001. Paiton Energy has received lender approval of the Phase I Agreement.
Under the terms of the power purchase agreement, PT PLN has been required to pay for capacity and fixed operating costs once each unit and the plant achieved commercial operation. As of December 31, 2000, PT PLN had not paid invoices amounting to $814 million for capacity charges and
fixed operating costs under the power purchase agreement. All arrears under the power purchase agreement continue to accrue, minus the fixed monthly payments actually made under the year 2000 interim agreement and under the recently agreed Phase I Agreement, with the payment of these arrears to be dealt with in connection with the overall tariff long-term restructuring of the tariff. In this regard, under the Phase I Agreement, Paiton Energy has agreed that, so long as the Phase I Agreement is complied with, it will seek to recoup no more than $590 million of the above arrears, the payment of which is to be dealt with in connection with the overall tariff restructuring.
Any material modifications of the power purchase agreement could require a renegotiation of the Paiton project's debt agreements. The impact of any renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is uncertain at this time; however, we believe that we will ultimately recover our investment in the project.
In May 1999, we completed a transaction with the government of New Zealand to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of Contact Energy's shares were sold in an overseas public offering resulting in widespread ownership among the citizens of New Zealand and offshore investors. These shares are publicly traded on stock exchanges in New Zealand and Australia. During 2000, we increased our share of ownership in Contact Energy to 42%. 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 2,449 MW, of which our share is 940 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."
In February 2001, we completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project has been completed with equity contributions of $117 million (our 50% share is $58.5 million) required to be made upon completion of the rehabilitation and expansion, currently scheduled in 2003, and debt financing has been arranged for the remainder of the cost for this project.
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 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. We currently have 26 operating projects in this region that are located in the U.K., Turkey, Spain and Italy.
In July 1999, we acquired 100% of the Ferrybridge and Fiddler's Ferry coal fired power plants located in the U.K. with a total generating capacity of 3,984 MW from PowerGen UK plc for approximately $2.0 billion. Ferrybridge, located in West Yorkshire, and Fiddler's Ferry, located in Warrington, are in the middle of the order in which plants are called upon to dispatch electric power. The plants complement the pumped-storage hydroelectric power plants we already own in the U.K.
The current electricity trading mechanism in the U.K. is in the process of being abolished and replaced with trading arrangements using bilateral contracts. The current system provides for the sale of energy to a pool. Under the new trading arrangements, our U.K. subsidiary, Edison First Power Limited, is required to contract with specific purchasers for the sales of energy produced by its Ferrybridge and Fiddler's Ferry stations. Under the new system, a generator must deliver, and a consumer must take delivery, in accordance with their contracted agreements or face the volatility of
market prices. Edison First Power believes that a consequence of this will be to increase greatly the motivation of parties to contract in advance in order to lock in an agreed upon price for, and quantity of, energy. The U.K. Utilities Act, which was approved on July 28, 2000, allows for implementation of the new trading arrangements, which are to commence on March 27, 2001. As a result of the introduction of the new electricity trading arrangements, forecasts of future electricity prices in the markets into which Edison First Power sells its power vary significantly. Recent experience by Edison First Power has shown that this arrangement has placed significant downward pressure on prices to be paid by purchasers of energy in the future, although it is uncertain how the new trading arrangements will affect prices in the long-term.
The financial performance of the Fiddler's Ferry and Ferrybridge power plants has not matched our expectations, largely due to lower energy prices resulting primarily from increased competition, warmer-than-average weather and uncertainty surrounding the new electricity trading arrangements discussed above. As a result, Edison First Power has decided to defer some environmental capital expenditures originally planned to increase plant utilization and therefore is currently in breach of milestone requirements for the implementation of the capital expenditures program set forth in the financing documents relating to the acquisition of the plants. In addition, due to this reduced financial performance, Edison First Power's debt service coverage ratio during 2000 declined below the threshold set forth in the financing documents.
Edison First Power is currently in discussions with the relevant financing parties to revise the required capital expenditure program, to waive: (i) the breach of the financial ratio covenant for 2000, (ii) a technical breach of requirements for the provision of information that was delayed due to uncertainty regarding capital expenditures, and (iii) other related technical defaults. Edison First Power is in the process of requesting the necessary waivers and consents to amendments from the financing parties. We cannot assure you that waivers and consents to amendments will be forthcoming. The financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing parties are entitled to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite the breaches under the financing documents, Edison First Power's debt service coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service payments, Edison First Power utilized L37 million from its debt service reserve to meet its debt service requirements in 2000. Our net investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry power plants and related debt was $918 million at December 31, 2000.
Another of our subsidiaries, EME Finance UK Limited, is the borrower under the facility made available for the purposes of funding coal and capital expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At December 31, 2000, L58 million was outstanding for coal purchases and zero was outstanding to fund capital expenditures under this facility. EME Finance UK Limited on-lends any drawings under this facility to Edison First Power. The financing parties of this facility have also issued letters of credit directly to Edison First Power to support their obligations to lend to EME Finance UK Limited. EME Finance UK Limited's obligations under this facility are separate and apart from the obligations of Edison First Power under the financing documents related to the acquisition of these plants. We have guaranteed the obligations of EME Finance UK Limited under this facility, including any letters of credit issued to Edison First Power under the facility, for the amount of L359 million, and our guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents.
In addition, Edison Mission Energy may provide guarantees in support of bilateral contracts entered into by Edison First Power under the new electricity trading arrangements. Edison Mission Energy has provided guarantees totaling L19 million relating to these contracts at March 20, 2001.
During October 1999, we completed the acquisition of the remaining 20% of the 220 MW natural gas fired Roosecote project located in England. Consideration for the remaining 20% consisted of a cash payment of approximately $16.0 million, or 9.6 million pounds sterling.
In March 2000, we completed a transaction with UPC International Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy. All the projects use wind to generate electricity from turbines. The electricity is sold under fixed price, long-term tariffs. Assuming all the projects under development are completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW. The total purchase price was 90 billion Italian Lira (approximately $44 million at December 31, 2000), with equity contribution obligations of up to 33 billion Italian Lira (approximately $16 million at December 31, 2000), depending on the number of projects that are ultimately developed. As of December 31, 2000, our payments in respect of these projects included $27 million toward the purchase price and $13 million in equity contributions.
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 ownership interests in operating projects that employ gas fired combustion turbine technology, predominantly through an application known as cogeneration. Cogeneration facilities sequentially produce two or more useful forms of energy, such as electricity and steam, from a single primary source of fuel, such as natural gas or coal. Many of our cogeneration projects are located near large, industrial steam users or in oil fields that inject steam underground to enhance recovery of heavy oil. The regulatory advantages for cogeneration facilities under the Public Utility Regulatory Policies Act of 1978, as amended, have become somewhat less significant because of other federal regulatory exemptions made available to independent power producers under the Energy Policy Act. Accordingly, we expect that the majority of our future projects will generate power without selling steam to industrial users.
We also have ownership interests in projects that use renewable resources like hydroelectric energy and geothermal energy. Our hydroelectric projects, excluding First Hydro's plants, use run-of-the-river technology to generate electricity. The First Hydro plant utilizes pumped-storage stations that consume electricity when it is comparatively less expensive in order to pump water for storage in an upper
reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is higher. This type of generation is characterized by its speed of response, its ability to work efficiently at wide variations of load and the basic reliance of revenue on the difference between the peak and trough prices of electricity during the day. Our geothermal projects included as part of our Contact Energy investment use technologies that convert the heat from geothermal fluids and underground steam into electricity.
We also have domestic and international ownership interests in operating projects and projects 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. We also have acquired ownership interests in gas-fired projects and have purchased gas-fired turbines for combined cycle gas turbines (commonly referred to as "F" technology), which are designed to increase efficiency of power generation due to higher firing temperatures.
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 long-term contracts. Electric power generated by several of our international projects is sold under long term contracts to electric utilities located in the country where the power project is located. These projects' revenues from power purchase agreements usually consist of two components: energy payments and capacity payments. Energy payments are made based on actual deliveries of electric energy, such as kilowatt hours, to the purchaser. Energy payments are usually indexed to specified variable costs that the purchaser avoids by purchasing this electric energy from our projects opposed to operating its own power plants to produce the same amount of electric energy. The variable components typically include fuel costs and selected operation and maintenance expenses. These costs may be indexed to the utility's cost of fuel and/or selected inflation indices. Capacity payments are based on a project's proven capability to reliably make electric capacity available, whether or not the project is called to deliver electric energy. Capacity payments compensate a project for specified fixed costs that are incurred independent of the amount of energy sold by the project. Such fixed costs include taxes, debt service and distributions to the project's owners. To receive capacity payments, there are typically minimum performance standards that must be met, and often there is a performance range that further influences the amount of capacity payments.
Steam produced from our cogeneration facilities is sold to industrial steam users, such as petroleum refineries or companies involved in the enhanced recovery of oil through steam flooding of oil fields, under long term steam sales contracts. Steam payments are generally based on formulas that reflect the cost of water, fuel and capital to us. In some cases, we have provided steam purchasers with discounts from their previous costs for producing this steam and/or have partially indexed steam payments to other indices including specified oil prices.
SALE OF POWER FROM MERCHANT PLANTS
During 1999, we 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 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.
The majority of electric power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company in which Exelon Generation Company purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999, and have a term of up to five years, provide for Exelon Generation Company to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production. If Exelon Generation Company 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 plants in the U.K. currently 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 pricing arrangements include provision for capacity payments to be added to the basic pool price at times of capacity shortage. The First Hydro, Ferrybridge and Fiddler's Ferry plants have the opportunity to 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 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 net exposure to pool price volatility. See "Management's Discussion and Analysis of Results of Operations and Financial Condition--Market Risk Exposures--United Kingdom."
The Loy Yang B plant sells its electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant has entered into a number of financial hedges. From May 8, 1997 to December 31, 2000, approximately 53% to 64% of the plant output sold was hedged under vesting contracts, with the remainder of the plant capacity hedged under the State Hedge. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2001 to July 2014, approximately 77% of the plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant has entered into a number of fixed forward electricity contracts with terms of up to two years, and which will further mitigate against the price volatility of the electricity pool.
POWER MARKETING AND TRADING ACTIVITIES
When making sales under negotiated contracts, it is our policy to deal with investment grade counterparties or counterparties that provide equivalent credit support. Exceptions to the policy are granted only after thorough review and scrutiny by our Risk Management Committee. Most entities
that have received exceptions are organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants in order to stabilize and enhance the operating revenues from merchant plants. When appropriate, we manage the "spark spread," or margin, which is the spread between electric prices and fuel prices and use forward contracts, swaps, futures, or options contracts to achieve those objectives.
Our power marketing and trading organization, Edison Mission Marketing & Trading, is divided into front-, middle-, and back-office segments, with specified duties segregated for control purposes. The personnel of Edison Mission Marketing & Trading have a high level of knowledge of utility operations, fuel procurement, energy marketing and futures and options trading. We have systems in place which monitor real time spot and forward pricing and perform option valuations. We also have a wholesale power scheduling group that operates on a 24 hour basis.
Edison Mission Marketing & Trading markets and trades electric power and energy related commodity products, including forwards, futures, options and swaps. It also provides services and price risk management capabilities to the electric power industry. Price risk management activities include the restructuring of power sales and power supply agreements. We generally balance forward sales and purchase contracts to mitigate market risk and secure cash flow streams.
Energy trading and price risk management activities give rise to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored to ensure compliance with our risk management policies. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, we supplement this approach with industry "best practice" techniques including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.
FUEL SUPPLY 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 with long term contracts to operate profitably under a wide array of potential price scenarios.
PROJECT FINANCING
Each project we develop requires a substantial capital investment. Permanent project financing is often arranged immediately prior to the construction of the project. With limited exceptions, this debt financing is for approximately 50% to 80% of each project's costs and is structured on a basis that is non-recourse to us and our other projects. In addition, the collateral security for each project's financing generally has been limited to the physical assets, contracts and cash flow of that project and our ownership interests in that project.
In general, each of our direct or indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Any asset of any of these subsidiaries may not be available to
satisfy our obligations or those of any of our other subsidiaries. However, unrestricted cash or other assets that are available for distribution by a subsidiary may, subject to applicable law and the terms of financing arrangements of these subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us.
The ability to arrange project financing and the cost of such financing are dependent upon numerous factors, including general economic and capital market conditions, the credit attributes of a project, conditions in energy markets, regulatory developments, credit availability from banks or other lenders, investor confidence in the industry, us and other project participants, the continued success of our other projects, and provisions of tax and securities laws that are conducive to raising capital.
Our financial exposure in any equity investment is generally limited by contractual arrangement to our equity commitment, which is usually about 20% to 50% of our share of the aggregate project cost. In some cases, we provide additional credit support to projects in the form of debt service reserves, contingent equity commitments, revenue shortfall support or other arrangements designed to provide limited support.
PERMITS AND APPROVALS
Because the process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking a year or longer, we seek to obtain all permits, licenses and other approvals required for the construction and operation of a project, including siting, construction and environmental permits, rights of way and planning approvals, early in the development process for a project. See "--Regulatory Matters--General."
Emission allowances were acquired by us as part of the acquisition of the Illinois Plants and the Homer City plant. Emission allowances are required by our facilities in order to be certified by the local environmental authorities and are required to be maintained throughout the period of operation of those facilities located in Pennsylvania and Illinois. We purchase additional emission allowances when necessary to meet the environmental regulations. We also use forward sales and purchases of emission allowances, together with options, to achieve our objective of stabilizing and enhancing the operations from these merchant plants.
CONSTRUCTION, OPERATIONS & MAINTENANCE AND MANAGEMENT
In the project implementation stage, we often provide construction management, start up and testing services. The detailed engineering and construction of the projects typically are performed by outside contractors under fixed price, turnkey contracts. Under these contracts, the contractor generally is required to pay liquidated damages to us in the event of cost overruns, schedule delays or the project's failure to meet specified capacity, efficiency and emission standards.
As a project goes into operation, operation and maintenance services are provided to the project by one of our operation and maintenance subsidiaries or another operation and maintenance contractor. The projects that we operated in 2000 achieved an average 82% availability. Availability is a measure of the weighted average number of hours each generator is available for generation as a percentage of the total number of hours in a year.
An executive director generally manages the day-to-day administration of each project. Management committees comprised of the project's partners generally meet monthly or quarterly to review and manage the operating performance of the project.
RISK FACTORS ASSOCIATED WITH THE CALIFORNIA POWER CRISIS
Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in
higher wholesale power prices to California utilities. At the same time, two of the three major utilities, Southern California Edison and Pacific Gas and Electric Co., have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers and others. Given these and other payment defaults, creditors of Southern California Edison and Pacific Gas and Electric could file involuntary bankruptcy petitions against these companies.
Southern California Edison's current financial condition has had, and may continue to have, an adverse impact on Edison International's credit quality and, as previously reported by Edison International, has resulted in cross-defaults under Edison International's credit facilities. Both Standard & Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the credit ratings of Edison International and Southern California Edison to substantially below investment grade levels. The credit ratings remain under review for potential downgrade by both Standard & Poor's and Moody's.
To isolate ourselves from the credit downgrades and potential bankruptcies of Edison International and Southern California Edison, and to facilitate our ability and the ability of our subsidiaries to maintain their respective investment grade credit ratings, on January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity despite the current credit difficulties of Edison International and Southern California Edison. See "Management's Discussion and Analysis of Results of Operations and Financial Condition--Credit Ratings."
We cannot assure you that these measures will effectively isolate us from the credit downgrades or the potential bankruptcies of Edison International and Southern California Edison. In January 2001, Standard & Poor's and Moody's lowered our credit ratings. Our senior unsecured credit ratings were downgraded to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's. Our credit ratings remain investment grade. Both Standard & Poor's and Moody's have indicated that the credit ratings outlook for us is stable. A downgrade in our credit ratings below investment grade could increase our cost of capital, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries.
On March 15, 2001, the California Public Utilities Commission released a draft of a proposed order instituting an investigation into whether California's investor-owned utilities, including Southern California Edison, have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. Action on this agenda item repeatedly has been deferred, including at the Commission meeting on March 27, 2001, and the item has continued to appear on the agendas for subsequent Commission meetings. The proposed order would reopen the past holding company decisions and initiate an investigation into the following matters:
- whether the holding companies, including Edison International, violated requirements to give priority to the capital needs of their respective utility subsidiaries;
- whether the ring-fencing actions by Edison International and PG&E Corporation and their respective nonutility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries;
- whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies;
- any additional suspected violations of laws or Commission rules and decisions; and
- whether additional rules, conditions, or other changes to the holding company decisions are necessary.
We cannot predict whether the Commission will institute this investigation or what effects any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us.
We have partnership interests in eight partnerships which own power plants in California which have power purchase contracts with Pacific Gas and Electric and/or Southern California Edison. Three of these partnerships have a contract with Southern California Edison, four of them have a contract with Pacific Gas and Electric, and one of them has contracts with both. In 2000, our share of earnings before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at December 31, 2000 was $345 million.
As a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities has failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the eight power plants which are owned by partnerships in which we have a partnership interest. Southern California Edison did not pay any of the amounts due to the partnerships in January, February and March of 2001 and may continue to miss future payments. Pacific Gas and Electric made its January payment in full but thus far has paid only a small portion of the amounts due to the partnerships in February and March and may not pay all or a portion of its future payments.
On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. In addition, the decision modified the pricing formula for determining short run avoided costs for qualifying facilities subject to these provisions. Depending on how the utilities react to this order, the immediate impact of this decision may be to commence payment in April 2001 at significantly reduced prices for power to qualifying facilities subject to this pricing adjustment. Furthermore, this decision called for further study of the pricing formula tied to short run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this recent decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001.
The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly could have an adverse impact on the operations of our California qualifying facilities. Provisions in the partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be taken through the non-affiliated partner in the partnership. Therefore, partnership actions concerning the enforcement of rights under each qualifying facility's power purchase agreement with Southern California Edison in response to Southern California Edison's suspension of payments under that power purchase agreement are to be taken through the non-Edison Mission Energy affiliated partner in the partnership. Some of the partnerships have sought to minimize their exposure to Southern California Edison by reducing deliveries under their power purchase agreements. It is unclear at this time what additional actions, if any, the partnerships will take in regard to the utilities' suspension of payments due to the qualifying facilities. As a result of the utilities' failure to make payments due under these power purchase agreements, the partnerships have called on the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours have made equity contributions totaling approximately $103 million to meet capital calls by the partnerships. Our subsidiaries and the other partners may be required to make additional capital contributions to the partnerships.
Southern California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. Pacific Gas and Electric has taken a different approach and is seeking to invoke force majeure provisions under its power purchase agreements to excuse its failure to pay. In either case, it is possible that the utilities will not pay all their obligations in full. In addition, it is possible that Southern California Edison and/or Pacific Gas and Electric could be forced into bankruptcy proceedings. If this were to occur, payments to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, could be subject to significant delays associated with the lengthy bankruptcy court process and may not be paid in full. At February 28, 2001, accounts receivable due to these partnerships from Southern California Edison and Pacific Gas & Electric were $437 million; our share of these receivables was $217 million. Furthermore, Southern California Edison's and Pacific Gas and Electric's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court. While we believe that the generation of electricity by the qualifying facilities, including those owned by partnerships in which we have a partnership interest, is needed to meet California's power needs, we cannot assure you either that these partnerships will continue to generate electricity without payment by the purchasing utility, or that the power purchase agreements will not be adversely affected by a bankruptcy or contract renegotiation as a result of the current power crisis.
A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are ongoing. These activities may result in a restructuring of the California power market. At this time, these activities are in their preliminary stages, and it is not possible to estimate their likely ultimate outcome. The situation in California changes on an almost daily basis. You should monitor developments in California for the most up to date information. For more information on the current regulatory situation in California, see "--Regulatory Matters--California Deregulation."
RISK FACTORS ASSOCIATED WITH OUR LIQUIDITY
As of December 31, 2000, we had $2.1 billion of debt which is recourse to Edison Mission Energy and $5.9 billion of debt which is non-recourse to Edison Mission Energy but is recourse to our subsidiaries appearing on our consolidated balance sheet.
Edison Mission Energy has a substantial amount of short-term debt that will need to be extended or refinanced. Edison Mission Energy has two credit facilities, in a total amount of $1 billion, that are scheduled to expire in May 2001 and one credit facility, in the amount of $500 million, that is scheduled to expire in October 2001.
We cannot assure you that we will be able to extend our existing credit facilities or obtain new credit facilities to finance our needs, or that any new credit facility can be obtained under similar terms and rates as our existing credit facilities. If we cannot extend our existing credit facilities or obtain new credit facilities to finance our needs on similar terms and rates as our existing credit facilities, this could have a negative impact on our liquidity.
Our substantial amount of debt and financial obligations presents the risk that we might not have sufficient cash to service our indebtedness and that our existing corporate and project debt could limit our ability to finance the acquisition and development of additional projects, to compete effectively or to operate successfully under adverse economic conditions.
We cannot assure you that Standard & Poor's and Moody's will not downgrade us below investment grade, whether as a result of the California power crisis or otherwise. If we are downgraded, we could be required to, among other things:
- provide additional guarantees, collateral, letters of credit or cash for the benefit of counterparties in our trading activities,
- post a letter of credit or cash collateral to support our $58.5 million equity contribution obligation in connection with our acquisition in February 2001 of a 50% interest in the CBK project in the Philippines, and
- repay a portion of the preferred shares issued by our subsidiary in connection with our 1999 acquisition of a 40% interest in Contact Energy Limited, a New Zealand power company, which, based on their value at March 20, 2001, would require a payment of approximately $19 million.
Our downgrade could result in a downgrade of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below its current credit rating, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, limit the ability of Midwest Generation to use excess cash flow to make distributions.
A downgrade in our credit rating below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries.
Because substantially all our operations are conducted by our subsidiaries, our cash flow and ability to service our indebtedness or otherwise meet our financial obligations are dependent upon the ability of our subsidiaries to pay dividends and make distributions to us. As mentioned above, the California power crisis has had, and may continue to have, an adverse impact on our California partnership investments and may adversely affect their ability to make distributions to us. In addition, financing agreements of our subsidiaries and affiliates generally place limitations on the ability of those subsidiaries and affiliates to pay dividends, make distributions or otherwise transfer funds to us. Financing agreements for our operating subsidiaries and affiliates are generally secured and contain representations, warranties, covenants and other agreements on our part that, if not met, could lead to a default under those agreements. If there is a default under a project financing for any reason, project lenders could exercise rights and remedies typically granted to secured parties, including the ability to take control of the project's assets and/or our ownership interest in the project company. In addition, we own a minority interest in some of our projects, and so are unable unilaterally to cause dividends or distributions to be made to us from those projects. Lastly, many of our projects are located overseas and, therefore, distributions from foreign operations could be subject to additional taxes in the United States upon repatriation.
Any right of ours to receive any assets of any of our subsidiaries upon any liquidation or reorganization of a subsidiary will be effectively subordinated to the claims of the subsidiary's creditors, including trade creditors and holders of debt incurred by the subsidiary.
One of our subsidiaries, Edison First Power, has defaulted on its financing documents related to the acquisition of the Fiddler's Ferry and Ferrybridge power plants. Edison First Power is currently in the process of requesting the necessary waivers and consents to amendments from the financing parties. We cannot assure you that these waivers and consents to amendments will be forthcoming. The financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing parties are entitled to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Due to the timing of its cash flows and debt service payments, Edison First Power utilized L37 million from its debt service reserve to meet its debt service requirements in 2000. Our net investment in our subsidiary that holds the Ferrybridge and Fiddlers' Ferry power plants and related debt was
$918 million at December 31, 2000. See "Management's Discussion and Analysis of Results of Operations and Financial Condition--Financing Plans."
RISK FACTORS ASSOCIATED WITH PROJECT DEVELOPMENT, FINANCE AND OPERATION
Some of our projects do not have long-term power purchase agreements. Also, projects which we may acquire or develop in the future may not have long-term power purchase agreements. Because their output is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the amount and price of power that they sell. We cannot assure you that these plants will be successful in selling power into their markets. If they are unsuccessful, they may not be able to generate enough cash to service their own debt or to make distributions to us.
In 2000, 33% of our electric revenues were derived under power purchase agreements with Exelon Generation Company, a subsidiary of Exelon Corporation, entered into in connection with our December 1999 acquisition of the Illinois Plants. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major utilities located in Illinois and Pennsylvania. Electric revenues attributable to sales to Exelon Generating Company are earned from capacity and energy provided by the Illinois Plants under three five-year power purchase agreements. If Exelon Generation were to fail or become unable to fulfill its obligations under these power purchase agreements, we may not be able to find another customer on similar terms for the output of our power generation assets. Any material failure by Exelon Generation Company to make payments under these power purchase agreements could adversely affect our results of operations and liquidity.
Our international projects are subject to political and business risks, including uncertainties associated with currency exchange rates, currency repatriation, expropriation, political instability and other issues that have the potential to impair the projects from making dividends or other distributions to us and against which we may not be fully capable of insuring. In particular, fluctuations in currency exchange rates can affect, on a U.S. dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. At times, we have hedged a portion of our exposure to fluctuations in currency exchange rates. However, hedge contracts may involve risks, including default by the other party to the contract, and we cannot assure you that fluctuations in currency exchange rates will be fully offset by these hedges.
Generally, the uncertainty of the legal structure in some foreign countries in which we may develop or acquire projects could make it more difficult to enforce our rights under agreements relating to the projects. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire.
The economic crisis in Indonesia has raised concerns over the ability of PT PLN, the state owned utility, to meet its obligations under its power purchase agreement with our Paiton project and has negatively affected and may continue to negatively affect that project's dividends to us. See "Management's Discussion and Analysis of Results of Operations and Financial Condition-- Commitments and Contingencies--Paiton."
The global independent power industry is characterized by numerous strong and capable competitors, some of which may have more extensive operating experience in the acquisition and development of power projects, larger staffs and greater financial resources than we do. Further, in recent years some power markets have been characterized by strong and increasing competition as a result of regulatory changes and other factors which have contributed to a reduction in market prices for power. These regulatory and other changes may continue to increase competitive pressures in the markets where we operate. Increased competition for new project investment opportunities may adversely affect our ability to develop or acquire projects on economically favorable terms.
Our operations are subject to extensive regulation by governmental agencies in each of the countries in which we conduct operations. See "--Regulatory Matters." Our domestic projects are
subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of the projects. Our projects are also subject to federal, state and local laws and regulations that govern the geographical location, zoning and land use of or with respect to a project. Our international projects are subject to the energy, environmental and other laws and regulations of the foreign jurisdictions in which these projects are located. The degree of regulation varies according to each country and may be materially different from the regulatory regimes in the United States.
We cannot assure you that the introduction of new laws or other future regulatory developments in countries in which we conduct business will not have a material adverse effect on our business, results of operations or financial condition, nor can we assure you that we will be able to obtain and comply with all necessary licenses, permits and approvals for our proposed energy projects. If we cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected.
In addition, if any of our projects were to lose its status as a qualifying facility, eligible facility or foreign utility company under U.S. federal regulations, we could become subject to regulation as a "holding company" under the Public Utility Holding Company Act of 1935. If that were to occur, we would be required to divest all operations not functionally related to the operation of a single integrated utility system and would be required to obtain approval of the Securities and Exchange Commission for various actions. See "--Regulatory Matters--U.S. Federal Energy Regulation."
The operation of power generating plants involves many risks, including start-up problems, the breakdown or failure of equipment or processes, performance below expected levels of output, the inability to meet expected efficiency standards, operator errors, strikes, work stoppages or labor disputes and catastrophic events such as earthquakes, landslides, fires, floods, explosions or similar calamities. The occurrence of any of these events could significantly reduce revenues generated by our projects or increase their generating expenses, thus diminishing distributions by the projects to us. Equipment and plant warranties and insurance obtained by us may not be adequate to cover lost revenues or increased expenses and, as a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under a financing obligation of a project subsidiary could cause us to lose our interest in the project.
Our strategy includes the development and acquisition of electric power generation facilities. The development projects and acquisitions in which we have invested, or in which we may invest in the future, may be large and complex, and we may not be able to complete the development or acquisition of any particular project. The development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether we will win a competitive bid, or whether a project is feasible, economically attractive or financeable. Moreover, our access to capital for future projects is uncertain. Furthermore, due to the effects of the California power crisis on Edison International, we do not expect to receive capital contributions from Edison International in the near future. We cannot assure you that we will be successful in obtaining financing for our projects or that we will obtain sufficient additional equity capital, project cash flow or additional borrowings to enable us to fund the equity commitments required for future projects.
OUR OPERATING PROJECTS
DOMESTIC OVERVIEW
We currently own interests in 32 domestic operating projects in eight states and one project in the Commonwealth of Puerto Rico. These operating projects consist of 12 natural gas fired cogeneration projects, one coal fired cogeneration project, seven coal fired exempt wholesale generator projects, one waste coal project, one liquefied natural gas combined cycle cogeneration project and 11 gas fired exempt wholesale generator projects. All 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 15,257 MW, of which our net ownership share is 13,231 MW.
The primary power sales contracts for four of our operating projects in 2000 and 1999 and five of our operating projects in 1998 are with Southern California Edison Company. See "--Recent Developments--The California Power Crisis" for further discussion of these projects. Our share of equity in earnings from these projects accounted for 5% in 2000, 8% in 1999 and 13% in 1998 of our consolidated revenues. The failure of Southern California Edison 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 and the Office of Ratepayer Advocates, the consumer advocacy branch of the California Public Utilities Commission, Southern California Edison 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's consent. The terms of the agreement, however, do not affect the terms of the existing power sales contracts between us and Southern California Edison. 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 to terminate a power sales agreement. The termination agreement became effective in February 1999.
DESCRIPTION OF DOMESTIC OPERATING PROJECTS
We have ownership or leasehold interests in the following domestic operating projects:
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(1) Operated by subsidiaries or affiliates of Edison Mission Energy; all other projects are operated by unaffiliated third parties.
(2) Electric purchaser abbreviations are as follows:
(3) All the cogeneration projects are gas fired facilities, except for the James River project, which uses coal. All the exempt wholesale generator (EWG) projects are gas fired facilities, except for the Homer City plant and six of the Illinois Plants, which use coal.
INTERNATIONAL OVERVIEW
We own interests in 40 operating projects outside the United States. The total generating capacity of these facilities is 12,779 MW, of which our net ownership share is 9,528 MW.
DESCRIPTION OF INTERNATIONAL OPERATING PROJECTS
We have ownership interests in the following international operating projects:
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(1) Operated by subsidiaries or affiliates of Edison Mission Energy; all other projects are operated by unaffiliated third parties.
(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 interest 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 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, 2000, we owned 36% of the stock of Four Star Oil & Gas Company, a subsidiary of Texaco Inc. The underlying value of Four Star is attributable to the production of oil and gas from nine producing properties. Our proportionate interest in net quantities of proved reserves at December 31, 2000 totaled 180.6 billion cubic feet of natural gas and 10.4 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 were $20.5 million. We recorded an after-tax gain on the sale of our investment of approximately $30 million. Our net ownership interest in Four Star was reduced from 50% at December 31, 1998 to 34% as a result of the transaction. In December 1999 and May and July 2000, we purchased additional shares of stock of Four Star, increasing our ownership interest to 38%. On December 31, 2000, shares of convertible preferred shares were converted to common shares, reducing our net ownership interest to 36%.
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 of the United States, which generally have power sales contracts that provide for higher payments during summer months. The First Hydro plants, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants provide for higher electric revenues during the winter months.
EMPLOYEES AND OFFICES
At December 31, 2000, we employed 3,391 people, all of whom were full time employees and approximately 639, 146 and 1,294 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 or strike. We believe we have good relations with our employees. However, the term of the collective bargaining agreement covering our employees at the Illinois Plants is currently in dispute, with the union maintaining that the agreement's term could expire as early as March 31, 2001 and we maintaining that the agreement remains in effect until June 2002. Although we cannot predict the outcome of this dispute, we believe that the impact on the operations of the Illinois Plants will not be material.
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.
Furthermore, each of our international projects is subject to the energy and environmental laws and regulations of the foreign country in which this project is located. The degree of regulation varies according to each country and may be materially different from the regulatory regime in the United States.
U.S. FEDERAL ENERGY REGULATION
The Federal Energy Regulatory Commission has ratemaking jurisdiction and other authority with respect to interstate sales and transmission of electric energy under the Federal Power Act and with respect to certain interstate sales, transportation and storage of natural gas under the Natural Gas Act of 1938. The Securities and Exchange Commission has regulatory powers with respect to upstream owners of electric and natural gas utilities under the Public Utility Holding Company Act of 1935. The enactment of the Public Utility Regulatory Policies Act of 1978 and the adoption of regulations thereunder by the Federal Energy Regulatory Commission provided incentives for the development of cogeneration facilities and small power production facilities using alternative or renewable fuels by establishing certain exemptions from the Federal Power Act and the Public Utility Holding Company Act for the owners of qualifying facilities. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing additional exemptions from the Public Utility Holding Company Act for exempt wholesale generators and foreign utility companies.
A "QUALIFYING FACILITY" under the Public Utility Regulatory Policies Act is a cogeneration facility or a small power production facility that satisfies criteria adopted by the Federal Energy Regulatory Commission. In order to be a qualifying facility, a cogeneration facility must (i) sequentially produce both useful thermal energy, such as steam, and electric energy, (ii) meet specified operating standards, and energy efficiency standards when oil or natural gas is used as a fuel source and (iii) not be controlled, or more than 50% owned by one or more electric utilities (where "electric utility" is interpreted with reference to the Public Utility Holding Company Act definition of an "electric utility company"), electric utility holding companies (defined by reference to the Public Utility Holding Company Act definitions of "electric utility company" and "holding company") or affiliates of such entities. A small power production facility seeking to be a qualifying facility must produce power from renewable energy sources, such as geothermal energy, waste sources of fuel, such as waste coal, or any combination thereof and must meet the ownership restrictions discussed above. Before 1990, a small power production facility seeking to be a qualifying facility was subject to 30 MW or 80 MW size limits, depending upon its fuel source. In 1990, these limits were lifted for solar, wind, waste, and geothermal qualifying facilities, provided that applications for or notices of qualifying facility status were filed with the Federal Energy Regulatory Commission for these facilities on or before December 31, 1994, and provided, in the case of new facilities, the construction of these facilities commenced on or before December 31, 1999.
An "EXEMPT WHOLESALE GENERATOR" under the Public Utility Holding Company Act is an entity determined by the Federal Energy Regulatory Commission to be exclusively engaged, directly or indirectly, in the business of owning and/or operating specified eligible facilities and selling electric energy at wholesale or, if located in a foreign country, at wholesale or retail.
A "FOREIGN UTILITY COMPANY" under the Public Utility Holding Company Act is, in general, an entity located outside the United States that owns or operates facilities used for the generation, distribution or transmission of electric energy for sale or the distribution at retail of natural or manufactured gas, but that derives none of its income, directly or indirectly, from such activities within the United States.
FEDERAL POWER ACT. The Federal Power Act grants the Federal Energy Regulatory Commission exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce, including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the Federal Energy Regulatory Commission to revoke or modify previously approved rates. These rates may be based on a
cost-of-service approach or, in geographic and product markets determined by Federal Energy Regulatory Commission to be workably competitive, may be market-based. As noted, most qualifying facilities are exempt from the ratemaking and several other provisions of the Federal Power Act. Exempt wholesale generators and other non-qualifying facility independent power projects are subject to the Federal Power Act and to the ratemaking jurisdiction of the Federal Energy Regulatory Commission thereunder, but the Federal Energy Regulatory Commission typically grants exempt wholesale generators the authority to charge market-based rates as long as the absence of market power is shown. In addition, the Federal Power Act grants the Federal Energy Regulatory Commission jurisdiction over the sale or transfer of jurisdictional facilities, including wholesale power sales contracts, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. In granting authority to make sales at market-based rates, the Federal Energy Regulatory Commission typically also grants blanket approval for the issuance of securities and partial waiver of the restrictions on interlocking directorates.
Currently, in addition to the facilities owned or operated by us, a number of our operating projects, including the Homer City plant, the Illinois Plants, the Nevada Sun-Peak, Brooklyn Navy Yard, Commonwealth Atlantic and Harbor facilities, are subject to the Federal Energy Regulatory Commission ratemaking regulation under the Federal Power Act. Our future domestic non-qualifying facility independent power projects will also be subject to Federal Energy Regulatory Commission jurisdiction on rates.
THE PUBLIC UTILITY HOLDING COMPANY ACT. Unless exempt or found not to be a holding company by the Securities and Exchange Commission, a company that falls within the definition of a holding company must register with the Securities and Exchange Commission and become subject to Securities and Exchange Commission regulation as a registered holding company under the Public Utility Holding Company Act. "HOLDING COMPANY" is defined in Section 2(a)(7) of the Public Utility Holding Company Act to include, among other things, any company that owns 10% or more of the voting securities of an electric utility company. "ELECTRIC UTILITY COMPANY" is defined in Section 2(a)(3) of the Public Utility Holding Company Act to include any company that owns facilities used for generation, transmission or distribution of electric energy for resale. Exempt wholesale generators and foreign utility companies are not deemed to be electric utility companies and qualifying facilities are not considered facilities used for the generation, transmission or distribution of electric energy for resale. Securities and Exchange Commission precedent also indicates that it does not consider "paper facilities," such as contracts and tariffs used to make power sales, to be facilities used for the generation, transmission or distribution of electric energy for resale, and power marketing activities will not, therefore, result in an entity being deemed to be an electric utility company.
A registered holding company is required to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. In addition, a registered holding company will require Securities and Exchange Commission approval for the issuance of securities, other major financial or business transactions (such as mergers) and transactions between and among the holding company and holding company subsidiaries.
Because it owns Southern California Edison, an electric utility company, Edison International, our parent company, is a holding company. Edison International is, however, exempt from registration pursuant to Section 3(a)(1) of the Public Utility Holding Company Act, because the public utility operations of the holding company system are predominantly intrastate in character. Consequently, we are not a subsidiary of a registered holding company, so long as Edison International continues to be exempt from registration pursuant to Section 3(a)(1) or another of the exemptions enumerated in Section 3(a). Nor are we a holding company under the Public Utility Holding Company Act, because our interests in power generation facilities are exclusively in qualifying facilities, exempt wholesale generators and foreign utility companies. All international projects and specified U.S. projects that we are currently developing or proposing to acquire will be non-qualifying facility independent power
projects. We intend for each project to qualify as an exempt wholesale generator or as a foreign utility company. Loss of exempt wholesale generator, qualifying facility or foreign utility company status for one or more projects could result in our becoming a holding company subject to registration and regulation under the Public Utility Holding Company Act and could trigger defaults under the covenants in our project agreements. Becoming a holding company could, on a retroactive basis, lead to, among other things, fines and penalties and could cause certain of our project agreements and other contracts to be voidable.
PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
The Public Utility Regulatory Policies Act provides two primary benefits to qualifying facilities. First, as discussed above, ownership of qualifying facilities will not result in a company's being deemed an electric utility company for purposes of the Public Utility Holding Company Act. In addition, all cogeneration facilities and all small production facilities that generate power from sources other than geothermal and whose capacity exceeds 30 MWs that are qualifying facilities are exempt from most provisions of the Federal Power Act and regulations of the Federal Energy Regulatory Commission thereunder. Second, the Federal Energy Regulatory Commission regulations promulgated under the Public Utility Regulatory Policies Act require that electric utilities purchase electricity generated by qualifying facilities at a price based on the purchasing utility's avoided cost, and that the utilities sell back up power to the qualifying facility on a non discriminatory basis. The Federal Energy Regulatory Commission's regulations define "avoided cost" as the incremental cost to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, the utility would generate itself or purchase from another source. The Federal Energy Regulatory Commission's regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different than the utility's avoided costs. While it has been common for utilities to enter into long term contracts with qualifying facilities in order, among other things, to facilitate project financing of independent power facilities and to reflect the deferral by the utility of capital costs for new plant additions, increasing competition and the development of new power markets have resulted in a trend toward shorter term power contracts that would place greater risk on the project owner.
If one of the projects in which we have an interest were to lose its status as a qualifying facility, the project would no longer be entitled to the qualifying facility-related exemptions from regulation under the Public Utility Holding Company Act and the Federal Power Act. As a result, the project could become subject to rate regulation by the Federal Energy Regulatory Commission under the Federal Power Act, and we could inadvertently become a holding company under the Public Utility Holding Company Act. Under Section 26(b) of the Public Utility Holding Company Act, any project contracts that are entered into in violation of the Public Utility Holding Company Act, including contracts entered into during any period of non-compliance with the registration requirement, could be determined by the courts or the Securities and Exchange Commission to be void. If a project were to lose its qualifying facility status, we could attempt to avoid holding company status on a prospective basis by qualifying the project owner as an exempt wholesale generator. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from the Federal Energy Regulatory Commission would be required. In addition, the project would be required to cease selling electricity to any retail customers, in order to qualify for exempt wholesale generator status, and could become subject to additional state regulation. Loss of qualifying facility status by one project could also potentially cause other projects with the same partners to lose their qualifying facility status to the extent those partners became electric utilities, electric utility holding companies or affiliates of such companies for purposes of the ownership criteria applicable to qualifying facilities. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or acceleration of indebtedness under such
agreements. If a power purchaser were to cease taking and paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of qualifying facility status, we cannot assure you that the costs incurred in connection with the project could be recovered through sales to other purchasers. Moreover, our business and financial condition could be adversely affected if regulations or legislation were modified or enacted that changed the standards for maintaining qualifying facility status or that eliminated or reduced the benefits, such as the mandatory purchase provisions of the Public Utility Regulatory Policies Act and exemptions currently enjoyed by qualifying facilities. Loss of qualifying facility status on a retroactive basis could lead to, among other things, fines and penalties being levied against us, or claims by a utility customer for the refund of payments previously made.
We endeavor to develop our qualifying facility projects, monitor regulatory compliance by these projects and choose our customers in a manner that minimizes the risks of losing these projects' qualifying facility status. However, some factors necessary to maintain qualifying facility status are subject to risks of events outside of our control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a qualifying facility could cause a facility to fail to meet the requirements regarding the minimum level of useful thermal energy output. Upon the occurrence of this type of event, we would seek to replace the thermal energy customer or find another use for the thermal energy that meets the requirements of the Public Utility Regulatory Policies Act.
NATURAL GAS ACT
Twenty-four of the domestic operating facilities that we own, operate or have investments in use natural gas as their primary fuel. Under the Natural Gas Act, the Federal Energy Regulatory Commission has jurisdiction over certain sales of natural gas and over transportation and storage of natural gas in interstate commerce. The Federal Energy Regulatory Commission has granted blanket authority to all persons to make sales of natural gas without restriction but continues to exercise significant oversight with respect to transportation and storage of natural gas services in interstate commerce.
STATE ENERGY REGULATION
State public utility commissions have broad jurisdiction over non-qualifying facility independent power projects, including exempt wholesale generators, which are considered public utilities in many states. This jurisdiction often includes the issuance of certificates of public convenience and necessity and/or other certifications to construct, own and operate a facility, as well as the regulation of organizational, accounting, financial and other corporate matters on an ongoing basis. Qualifying facilities may also be required to obtain these certificates of public convenience and necessity in some states. Some states that have restructured their electric industries require generators to register 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 to regulate the retail rates charged by qualifying facilities. In addition, states may assert jurisdiction over the siting and construction of independent power projects and, among other things, the issuance of securities, related party transactions and the sale or other transfer of assets by these facilities. The actual scope of jurisdiction over independent power projects by state public utility commissions varies from state to state.
In addition, state public utility commissions may seek to modify, suspend or terminate a qualifying facility's power sales contract under specified circumstances. This could occur if the state public utility commission were to determine that the pricing mechanism of the power sales contract is unfairly high in light of the current prevailing market cost of power for the utility purchasing the power. In this instance, the state public utility commission could attempt to alter the terms of the power sales contract to reflect more accurately market conditions for the prevailing cost of power. While we believe that these attempts are not common, and that the state public utility commission may not have any jurisdiction to modify the terms of the wholesale power sales, we cannot assure you that the power sales contracts of our projects will not be subject to adverse regulatory actions.
The California Public Utilities Commission has authorized the electric utilities in California to "monitor" compliance by qualifying facilities with the Public Utility Regulatory Policies Act rules and regulations. However, the United States Court of Appeals for the Ninth Circuit found in 1994 that a California Public Utilities Commission program was preempted by the Public Utility Regulatory Policies Act, to the extent it authorized utilities to determine that a qualifying facility was not in compliance with the Public Utility Regulatory Policies Act rules and regulations, to then pay a reduced avoided cost rate and to take other action contrary to a facility's status as a qualifying facility. The court did, however, uphold reasonable monitoring of qualifying facility operating data. Other states, like New York and Virginia, have also instituted qualifying facility monitoring programs.
We buy and transport the natural gas used at our domestic facilities through local distribution companies. State public utility commissions have jurisdiction over the transportation of natural gas by local distribution companies. Each state's regulatory laws are somewhat different. However, all generally require the local distribution companies to obtain approval from the relevant public utility commission for the construction of facilities and transportation services if the local distribution company's generally applicable tariffs do not cover the proposed transaction. Local distribution companies' rates are usually subject to continuing public utility commission oversight.
CALIFORNIA DEREGULATION
DEREGULATION PLAN. Efforts to restructure the California electric industry began in 1994 in response to high electricity prices. A final restructuring order was issued by the California Public Utility Commission in December 1995, which led to the unanimous enactment of Assembly Bill 1890, the Restructuring Legislation, in September 1996 and its signature by the Governor of California at the time. The main points of this legislation included the following:
- the creation of the California System Operator and California Power Exchange by January 1998 and simultaneous initiation of direct access between electricity suppliers and end use customers;
- the creation of the California Electricity Oversight Board; and
- the adoption of a Competitive Transition Charge for the recovery of stranded costs.
The state's utilities were authorized to divest much of their generation assets and apply the proceeds to their stranded costs resulting from deregulation of the retail markets. The restructuring also required that California investor-owned utilities sell into and purchase most of their power requirements from the California Power Exchange but did not permit them to hedge their risk through long-term forward contracts. Through this mechanism, a spot market was created that set the purchase price for power by establishing the highest bid as the market clearing price for all bidders.
Additionally, the legislation provided for a limited transition period ending March 31, 2002, or an earlier date at which it is determined that a utility has recovered its stranded costs. During the transition period, there is a rate reduction of no less than 10% for residential and small commercial ratepayers. The rate reduction was financed through the issuance of rate reduction bonds. The rate reduction scheme capped retail electric rates at 1996 levels. The retail rate cap and bond offering were
intended to assist utilities in the recovery of stranded costs incurred by their investments made prior to deregulation. At the conclusion of the transition period, the legislation anticipated that residential and small business purchasers of electricity would pay 20% less for electricity due to effective implementation of Assembly Bill 1890.
THE CURRENT POWER CRISIS IN CALIFORNIA. Wholesale power prices rose significantly in California during 2000 and early 2001, we believe primarily as a result of supply shortages, high natural gas and petroleum prices and a variety of other factors. Unregulated wholesale rates rose above the fixed retail rates the California utilities were permitted to charge their customers. The inability of utilities to recover the full amount of wholesale prices has led to billions of dollars in unrecovered costs by the California utilities and to their current liquidity crisis.
Ongoing legislative and regulatory efforts seek to address both market structure and supply problems. In September 2000, legislation was enacted in California seeking to accelerate the power plant siting approval process. Other initiatives may seek to stimulate entry into the market of new power generation capacity. In December 2000, the Federal Energy Regulatory Commission issued an order permitting California utilities to negotiate long-term supply contracts, and establishing a "soft-cap" limiting the wholesale price that could be charged without additional cost justification, as opposed to allowing the highest bid price to set the market clearing price for all generators. At that time the Federal Energy Regulatory Commission refused to set a regional price cap for wholesale power prices as sought by state officials. On January 4, 2001, the California Public Utilities Commission authorized an interim surcharge on customers' bills, subject to refund, which is to be applied only to ongoing power procurement costs and will result in rate increases of 7-15% during a 90-day period. This interim surcharge does not otherwise affect the retail rate freeze which has been in effect since deregulation began in 1998. On March 27, 2001, the California Public Utilities Commission authorized a rate increase of three cents per kilowatt-hour, or approximately 50%, but kept the retail rate freeze in effect for Southern California Edison and Pacific Gas and Electric.
On February 1, 2001, legislation was enacted in California that, among other things: authorized the California Department of Water Resources to enter into long-term power purchase contracts; authorized the Department of Water Resources to sell revenue bonds to finance electricity purchases; provided for rate recovery of the Department of Water Resources' costs through rate increases, subject to specified limits; authorized the Department of Water Resources to sell power at its costs to retail customers and, with specified exceptions, to local publicly owned electric utilities; appropriated a total of $500 million toward additional spot market power purchases; and provided for suspension of the ability of customers to choose alternative energy providers while the Department of Water Resources is procuring power. Executive Orders promoting energy conservation measures were also signed by the Governor of California, including a mandatory requirement that retail businesses reduce outdoor retail lighting during non-business hours or face fines. In addition, on February 21, 2001, the California Senate approved formation of a California state power authority, which (if formed) will have the power to own and operate generation and transmission facilities in the state. The formation of the state power authority has not yet been approved by the California Assembly. The Governor of California has also proposed that the state acquire the transmission assets of the investor-owned utilities, including Southern California Edison, and that the proceeds from such sales be applied against the utilities' existing debts.
As part of an investigation that the Federal Energy Regulatory Commission has been conducting on wholesale power prices in the California market, the Federal Energy Regulatory Commission ordered a number of power generators, not including Edison Mission Energy, to justify charges to California utilities during the months of January and February 2001 or refund such charges. The Federal Energy Regulatory Commission has further required a power generator and a marketer to justify their decision to bring plants off-line or refund to the California utilities the increased costs resulting from such shutdowns. Also, the Governor of California and other western states have
petitioned the Federal Energy Regulatory Commission and the United States Congress for "cost-based" price caps for wholesale power rates on the spot market, permitting power generators to recover all their costs with a small level of profit. Further actions are anticipated as both the Federal and California state governments have intervened to address the short- and long-term issues associated with the power crisis. A recent Federal Energy Regulatory Commission report estimates that it could take up to 24 months to address these issues.
On March 15, 2001, the California Public Utilities Commission released a draft of a proposed order instituting an investigation into whether California's investor-owned utilities, including Southern California Edison, have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. Action on this agenda item repeatedly has been deferred, including at the Commission meeting on March 27, 2001, and the item has continued to appear on the agendas for subsequent Commission meetings. The proposed order would reopen the past holding company decisions and initiate an investigation into the following matters:
- whether the holding companies, including Edison International, violated requirements to give priority to the capital needs of their respective utility subsidiaries;
- whether the ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries;
- whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies;
- any additional suspected violations of laws or Commission rules and decisions; and
- whether additional rules, conditions, or other changes to the holding company decisions are necessary.
We cannot predict whether the Commission will institute this investigation or what effects any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us.
On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. In addition, the decision modified the pricing formula for determining short run avoided costs for qualifying facilities subject to these provisions. Depending on how the utilities react to this order, the immediate impact of this decision may be to commence payment in April 2001 at significantly reduced prices for power to qualifying facilities subject to this pricing adjustment. Furthermore, this decision called for further study of the pricing formula tied to short run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this recent decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001.
RECENT FOREIGN REGULATORY MATTERS
UNITED KINGDOM. The U.K.'s new electricity trading arrangements are the direct result of an October 1997 request by the Minister for Science, Energy and Industry who asked the U.K. Director
General of Electricity Supply to review the operation of the pool pricing system. In July 1998 the Director General proposed 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 U.K. Government accepted the proposals in October 1998 subject to reservations. Following this, further proposals were published by the Government and the Director General in July and October 1999. The proposals include, among other things, the establishment of a spot market or voluntary short-term power exchanges operating from 24 to 3 1/2-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 strong incentives for being in balance; and a Balancing and Settlement Code Panel to oversee governance of the balancing mechanism. Contracting over time periods longer than the day-ahead market are not directly affected by the proposals. Physical bilateral contracts will replace the current contracts for differences, but will function in a similar manner. However, it remains difficult to evaluate the future impact of the proposals. A key feature of the new electricity trading arrangements is to require firm physical delivery which means that a generator must deliver, and a consumer must take delivery, against their contracted positions or face assessment of energy imbalance penalty charges by the system operator. A consequence of this should be to increase greatly the motivation of parties to contract in advance and develop forwards and futures markets of greater liquidity than at present. Recent experience has been that the new electricity trading arrangements have placed a significant downward pressure on forward contract prices. Furthermore, another consequence may be that counterparties may require additional credit support, including parent company guarantees or letters of credit. Legislation in the form of the Utilities Act, which was approved July 28, 2000, allows for the implementation of new electricity trading arrangements and the necessary amendments to generators' licenses. Various key documents were designated by the Secretary of State and signed by participants on August 14, 2000 (the Go-Active Date); however, due to difficulties encountered during testing, implementation of the new electricity trading arrangements has been delayed from November 21, 2000 until March 27, 2001.
A warmer-than-average winter (January to March 2000), the entry of new operations into the generation market, the impending introduction of the new electricity trading arrangements coupled with uncertainties surrounding the new Utilities Act and action by the Director General to control abuse of market power, discussed below, contributed to a drop in the energy component of pool prices throughout the year (time weighted average System Marginal Price dropped from L22.39/MWh in 1999 to L18.75/MWh in 2000) and depressed forward prices for winter 2000/2001. We have entered into contracts for differences for the majority of our forecasted generation through the winter 2000/2001, and accordingly, have mitigated the downside risks to further decreases in energy prices. Despite improvement in capacity prices during August, September and early October 2000, and a slight firming of forward prices, the short-term prices for energy continue to be below prior years. As a result of the foregoing, we continue to expect lower revenues from our Ferrybridge and Fiddler's Ferry plants.
The Utilities Act sets a principal objective for the Government and the Director General to "protect the interests of consumers. .. where appropriate by promoting competition. .. ". This represents a shift in emphasis toward the consumer interest. But this is qualified by a recognition that license holders should be able to finance their activities. The Act also contains new powers for the Government to issue guidance to the Director General on social and environmental matters, changes to the procedures for modifying licenses and a new power for the Director General to impose financial penalties on companies for breach of license conditions. We will be monitoring the operation of these new provisions.
NEW ZEALAND. The New Zealand Government has been undergoing a steady process of electric industry deregulation since 1987. Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity distribution and provided for competition in the retail electric
supply function. The New Zealand Energy Market, established in 1996, is a voluntary competitive wholesale market which allows for the trading of physical energy on a half-hourly basis. The Electricity Industry Reform Act, which was passed in July 1998, was designed to increase competition at the wholesale generation level by splitting up Electricity Company of New Zealand Limited, the large state-owned generator, into three separate generation companies. The Electricity Industry Reform Act also prohibits the ownership of both generation and distribution assets by the same entity.
The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. This Inquiry Board's report was presented to the government in mid 2000. The main focus of the report was on the monopoly segments of the industry, transmission and distribution, with substantial limitations being recommended in the way in which these segments price their services in order to limit their monopoly power. Recommendations were also made with respect to the retail customer in order to reduce barriers to customers switching. In addition, the Board made recommendations in relation to the wholesale market's governance arrangements with the purpose of streamlining them. The recommended changes are now being progressively implemented.
TRANSMISSION OF WHOLESALE POWER
Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others, also known as wheeling. The prices and other terms and conditions of transmission contracts are regulated by the Federal Energy Regulatory Commission, when the entity providing the wheeling service is a jurisdictional public utility under the Federal Power Act. Until 1992, the Federal Energy Regulatory Commission's ability to compel wheeling was very limited, and the availability of voluntary wheeling service could be a significant factor in determining whether a site was viable for project development.
The Federal Energy Regulatory Commission's authority under the Federal Power Act to require electric utilities to provide transmission service on a case by case basis to qualifying facilities, exempt wholesale generators, and other power generators was expanded substantially by the Energy Policy Act. Furthermore, in 1996 the Federal Energy Regulatory Commission issued a rulemaking order, Order 888, in which the Federal Energy Regulatory Commission asserted the power, under its authority to eliminate undue discrimination in transmission, to compel all jurisdictional public utilities under the Federal Power Act to file open access transmission tariffs consistent with a pro forma tariff drafted by the Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission subsequently issued Orders 888-A, 888-B and 888-C to clarify the terms that jurisdictional transmitting utilities are required to include in their open access transmission tariffs. The Federal Energy Regulatory Commission also issued Order 889, which required those transmitting utilities to abide by specified standards of conduct when using their own transmission systems to make wholesale sales of power, and to post specified transmission information, including information about transmission requests and availability, on a publicly available computer bulletin board. Although the pro forma tariff does not cover the pricing of transmission service, Order 888 and the subsequently issued regional transmission organization rulemaking are expected to improve transmission access for independent power producers like us. A 1999 decision by the United States Court of Appeals for the Eighth Circuit has cast doubt on the extent of the Federal Energy Regulatory Commission's authority to require specified curtailment policies in the pro forma tariff. The United States Court of Appeals for the D.C. Circuit issued an opinion on June 30, 2000 that affirmed the Federal Energy Regulatory Commission's Order 888 et seq. in all material respects.
RETAIL COMPETITION
In response to pressure from retail electric customers, particularly large industrial users, the state commissions or state legislatures of most states are considering, or have considered, whether to open the retail electric power market to competition. Retail competition is possible when a customer's local
utility agrees, or is required, to "unbundle" its distribution service (for example, the delivery of electric power through its local distribution lines) from its transmission and generation service (for example, the provision of electric power from the utility's generating facilities or wholesale power purchases). Several state commissions and legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution service, which is called retail wheeling, and phasing in retail wheeling over the next several years.
The competitive pricing environment that will result from retail competition may cause utilities to experience revenue shortfalls and deteriorating creditworthiness. However, we expect that most, if not all, state plans will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay their obligations under existing long-term power purchase contracts with qualifying facilities and exempt wholesale generators. On the other hand, qualifying facilities and exempt wholesale generators may be subject to pressure to lower their contract prices in an effort to reduce the stranded investment costs of their utility customers.
We believe that, as a predominantly low cost producer of electricity, we will ultimately benefit from any increased competition that may arise from the opening of the retail market. Although our exempt wholesale generators are forbidden under the Public Utility Holding Company Act from selling electric power in the retail market, our exempt wholesale generators can sell at wholesale to a power marketer which could resell at retail. Furthermore, qualifying facilities are permitted to market power directly to large industrial users that could not previously be served, because of local franchise laws or the inability to obtain retail wheeling. We also believe we will compete effectively as a wholesale supplier to power marketers serving the newly-open retail markets.
ENVIRONMENTAL REGULATION
We are subject to environmental regulation by federal, state and local authorities in the United States and foreign regulatory authorities with jurisdiction over projects located outside the United States. We believe that we are in substantial compliance with environmental regulatory requirements and that maintaining compliance with current requirements will not materially affect our financial position or results of operations. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings which may be taken by environmental authorities, could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. We cannot assure you that we would be able to recover these increased costs from our customers or that our financial position and results of operations would not be materially adversely affected.
Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures.
The Clean Air Act provides the statutory framework to implement a program for achieving national ambient air quality standards in areas exceeding such standards and provides for maintenance of air quality in areas already meeting such standards. Among other requirements, it also restricts the emission of toxic air contaminants and provides for the reduction of sulfur dioxide emissions to address acid deposition. In 1990, Congress passed amendments to the Clean Air Act that greatly expanded the scope of federal regulations in several significant respects. We expect to spend approximately $67 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 anticipate upgrades to the environmental controls at the Illinois Plants to control nitrogen oxide emissions to result in expenditures of approximately $61 million, $67 million, $130 million, $123 million and $57 million for 2001, 2002, 2003, 2004 and 2005, 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 anticipate environmental costs arising from plant modification of approximately $52 million for the 2001-2005 period.
We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoElectrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoElectrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoElectrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action will be taken by the Environmental Protection Agency.
On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's "new source review" requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's new source review requirements.
To date, one utility, the Tampa Electric Company, has reached a formal agreement with the United States to resolve alleged new source review violations. Two other utilities, the Virginia Electric & Power Company and Cinergy Corp., have reached agreements in principle with the Environmental Protection Agency. In each case, the settling party has agreed to incur over $1 billion in expenditures over several years for the installation of additional pollution control, the retirement or repowering of coal fired generating units, supplemental environmental projects and civil penalties. These agreements provide for a phased approach to achieving required emission reductions over the next 10-15 years. The settling utilities have also agreed to pay civil penalties ranging from $3.5 million to $8.5 million.
Prior to our purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. Other than with respect to the Homer City plant, no proceedings have been initiated or requests for information issued with respect to any of our United States facilities. However, we have been in informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. We cannot assure you that we will reach a satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the proceedings, we could be required to invest in additional pollution control requirements, over and above the upgrades we are planning to install, and could be subject to fines and penalties.
A new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act,
the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the EPA to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in WHITMAN V. AMERICAN TRUCKING ASSOCIATIONS, INC., reversed the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard on our facilities is uncertain at this time.
On December 20, 2000, the Environmental Protection Agency issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum available control technology" standards will be developed. Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by us or our affiliates in the United States. This section of the Clean Air Act provides only for technology-based standards, and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and we cannot evaluate the potential impact on the operations of our facilities.
Since the adoption of the United Nations Framework on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton Administration participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels. However, because of opposition to the treaty in the United States Senate, the Kyoto Protocol has not been submitted to the Senate for ratification. Although legislative developments at the federal and state level related to controlling greenhouse gas emissions are beginning, we are not aware of any state legislative developments in the states in which we operate. If the United States ratifies the Kyoto Protocol or we otherwise become subject to limitations on emissions of carbon dioxide from its plants, these requirements could have a significant impact on our operations.
The Comprehensive Environmental Response, Compensation, and Liability Act, which is also known as CERCLA, and similar state statutes, require the cleanup of sites from which there has been a release or threatened release of hazardous substances. We are not aware of any material liabilities under this act; however, we cannot assure you that we will not incur CERCLA liability or similar state law liability in the future.
ITEM 2.
ITEM 2. PROPERTIES
We lease our principal office in Irvine, California. This lease is approximately 142,000 square feet. 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, Boston, Massachusetts, 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. The Boston lease is approximately 27,000 square feet and expires on June 30, 2007. Both the Fairfax and the Washington, D.C. leases are immaterial. At December 31, 2000, approximately 34% of above space was either available for sublease or subleased. 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 or our investments. 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 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 the plaintiffs asserted general monetary claims under the Construction Turnkey Agreement in the amount of $136.8 million. Brooklyn Navy Yard has also filed an action entitled BROOKLYN NAVY YARD COGENERATION PARTNERS, L.P. V. PMNC, PARSONS MAIN OF NEW YORK, INC., NAB CONSTRUCTION CORPORATION, L.K. COMSTOCK & CO., INC. AND THE PARSONS CORPORATION, in the Supreme Court of the State of New York, Kings County, Index No. 5966/97 asserting general monetary claims in excess of $13 million under the Construction
Turnkey Agreement. On March 26, 1998, the Superior Court in the California action granted PMNC's motion for attachment in the amount of $43 million against Brooklyn Navy Yard and attached 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. On November 13, 2000, a New York appellate court issued a ruling granting summary judgment in favor of Brooklyn Navy Yard, striking PMNC's cause of action for quantum meruit, and limiting PMNC to its claims under the construction contract. Discovery is continuing. We agreed to indemnify Brooklyn Navy Yard and our partner in the venture from all claims and costs arising from or in connection with this litigation. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations.
ECOELECTRICA POTENTIAL ENVIRONMENTAL PROCEEDING
We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoElectrica a notice of violation and a compliance order alleging violations of the federal Clean Air Act primarily related to start-up activities. Representatives of EcoElectrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoElectrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action will be taken by the Environmental Protection Agency. At December 31, 2001, no loss accrual had been recorded by EcoElectrica. We do not believe the outcome of this matter will have a material adverse effect on our consolidated financial position or results of operations.
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 "Business--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 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 on the Common Stock will be paid when declared by our Board of Directors. We made cash dividend payments to The Mission Group totaling $88 million in 2000. In February 2001, we made a $32.5 million cash dividend payment to The Mission Group.
Our articles of incorporation and bylaws contain restrictions on our ability to declare or pay dividends or distributions. These restrictions require the unanimous approval of our board of directors, including at least one independent director, before we can declare or pay dividends or distributions, unless either of the following are true:
- we then have an investment grade rating and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or
- the dividends do not exceed $32.5 million in any fiscal quarter and we then meet an interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters. We currently meet this interest coverage ratio.
For more information on these restrictions, see "Management's Discussion and Analysis of Results of Operations and Financial Condition--Credit Ratings."
COMPANY OBLIGATED MANDATORILY REDEEMABLE SECURITIES 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 of 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, with mandatory redemption in 2024 at a redemption price of $25 per security, plus accrued and unpaid distributions. None of these securities have been redeemed as of December 31, 2000. During August 1995, Mission Capital issued 2.5 million of 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, with mandatory redemption in 2025 at a redemption price of $25 per security, plus accrued and unpaid distributions. None of these securities were redeemed as of December 31, 2000. We have guarantees in favor of the holders of the preferred securities, which guarantee the payments of distributions declared on the preferred securities, payments upon a liquidation of Mission Capital and payments on redemption with respect to our 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 our common stock if at such time (i) we shall be in default with respect to our payment obligations under the guarantees, (ii) there shall have occurred any event of default under the subordinated indenture, or (iii) we shall have given notice of our 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 consisted 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.
On December 20, 2000, Edison Mission Energy Global Management, Inc. was dissolved and its $120 million of Flexible Money Market Cumulative Preferred Stock was redeemed. The 600 Series A
and 600 Series B shares were redeemed at their liquidation preference of $100,000 per share, together with a liquidation premium of $3,785 per share, and all accrued and unpaid dividends. The redemption of Edison Mission Energy Global Management's preferred shares was funded by return of capital from Edison Mission Energy Taupo Limited. Edison Mission Energy Taupo Limited sold its entire interest in Contact Energy Limited to EME Pacific Holdings, an indirect, wholly-owned subsidiary of Edison Mission Energy, to permit Edison Mission Energy Taupo to make the necessary distribution to Edison Mission Energy Global Management. In connection with the transfer of ownership of Contact, Edison Mission Energy entered into a further Deed of Covenant in favor of the institutional subscriber of 160 million New Zealand dollars of the preferred stock issued by Edison Mission Energy Taupo in June 1999, discussed below. This further Deed of Covenant requires Edison Mission Energy to compensate the institutional preferred stock subscriber in the event that a private binding ruling issued to it by the New Zealand Inland Revenue Department ceases to apply as a direct result of the transfer. The amount of any compensation that may become payable by Edison Mission Energy under the further Deed of Covenant is limited to that necessary to keep the preferred stock subscriber in the same position that it would have been had the private binding ruling continued to apply.
The support agreement between Edison Mission Energy and Edison Mission Energy Global Management, which required Edison Mission Energy to make capital contributions to Edison Mission Energy Global Management, was terminated immediately following the dissolution of Edison Mission Energy Global Management and the redemption of the preferred shares as described above.
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) to an institutional investor. The dividend rate ranges from 6.19% to 6.86%. The shares are mandatorily redeemable in June 2003 at 10,000 New Zealand dollars per share, plus accrued and unpaid dividends. 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 Edison Mission Energy Taupo other than redeemable preferred shares issued by Edison Mission Energy Taupo. 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 redeemable preferred shares described below, 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), plus accrued and unpaid dividends. 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. If an event of
default occurs at any time, 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.
In connection with the preferred shares issued by Edison Mission Energy Taupo Limited to partially finance the acquisition of the 40% interest in Contact Energy, Edison Mission Energy provided a guaranty of Edison Mission Energy Taupo Limited's obligation to pay a minimum level of non-cumulative dividends on the preferred shares through June 30, 2002, including NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts required to ensure that Edison Misison Energy Taupo Limited will satisfy two financial ratio covenants on specified dates. The first financial ratio, called a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is based on historical and projected dividends received from Contact Energy and the dividends payable to preferred shareholders. The second financial ratio, called a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based on the fair value of our Contact Energy shares and the outstanding preferred shares. If, however, Edison Mission Energy's senior unsecured credit rating by Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be called to perform on its guaranty of Edison Mission Energy Taupo Limited's financial covenants before the specified calculation dates. Based on the fair value of our ownership in Contact Energy at March 20, 2001, had Edison Mission Energy been required to perform on its guarantee of the debt to valuation ratio as of that date, Edison Mission Energy's obligation would have been approximately $19 million.
EDISON MISSION ENERGY TAUPO PREFERRED STOCK REDEMPTION REQUIREMENTS (TRANSLATED AT DECEMBER 31, 2000 EXCHANGE RATES)
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. THESE STATEMENTS ARE BASED ON OUR CURRENT PLANS AND EXPECTATIONS AND INVOLVE RISKS AND UNCERTAINTIES WHICH COULD CAUSE ACTUAL FUTURE ACTIVITIES AND RESULTS OF OPERATIONS TO BE MATERIALLY DIFFERENT FROM THOSE SET FORTH IN THE FORWARD-LOOKING STATEMENTS. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER INCLUDE RISKS SET FORTH IN "BUSINESS--PROJECT DEVELOPMENT--RISK FACTORS." UNLESS OTHERWISE INDICATED, THE INFORMATION PRESENTED IN THIS SECTION IS WITH RESPECT TO EDISON MISSION ENERGY AND OUR CONSOLIDATED SUBSIDIARIES.
GENERAL
We are an independent power producer engaged in the business of developing, acquiring, owning or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition. Edison International is our ultimate parent company. Edison International also owns Southern California Edison Company, one of the largest electric utilities in the United States. We were formed in 1986 with two domestic operating projects. As of December 31, 2000, we owned interests in 33 domestic and 40 international operating power projects with an aggregate generating capacity of 28,036 MW, of which our share was 22,759 MW. At that date, one domestic and one international project, totaling 603 MW of generating capacity, of which our anticipated share will be approximately 462 MW, were in construction. At December 31, 2000, we had consolidated assets of $15.0 billion and total shareholder's equity of $2.9 billion.
Our operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 91%, 83% and 74% of our total operating revenues during 2000, 1999 and 1998, respectively. Our consolidated operating revenues during those years also include equity in income from oil and gas investments, net losses from energy trading and price risk management activities and revenues attributable to operation and maintenance services.
ACQUISITIONS, DISPOSITIONS AND SALE-LEASEBACK TRANSACTIONS
ACQUISITION OF SUNRISE PROJECT
On November 17, 2000, we completed a transaction with Texaco Inc. to purchase a proposed 560 MW gas fired combined cycle project to be located in Kern County, California, referred to as the Sunrise Project. The acquisition included all rights, title and interest held by Texaco in the Sunrise Project, except that Texaco has an option to repurchase a 50% interest in the project prior to its commercial operation. As part of this transaction, we also: (i) acquired from Texaco an option to purchase two gas turbines which we plan to utilize in the project, (ii) provided Texaco an option to purchase two of the turbines available to us under the Edison Mission Energy Master Turbine Lease and (iii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future power plant projects we designate. For more information on the Edison Mission Energy Master Turbine Lease, see "--Commitments and Contingencies--Edison Mission Energy Master Turbine Lease." The Sunrise Project consists of two phases, with Phase I, construction of a single-cycle gas fired facility (320 MW), currently scheduled to be completed in August 2001, and Phase II, conversion to a combined-cycle gas fired facility (560 MW), currently scheduled to be completed in June 2003. In December 2000, we received the Energy Commission Certification and a permit to construct the Sunrise plant, which allowed us to commence construction of Phase I. We are negotiating with the California Department of Water Resources the detailed terms and conditions of a long-term cost-based-type rate power purchase agreement. We cannot assure you that we will be successful in reaching a final agreement.
The total purchase price of the Sunrise Project was $27 million. We funded the purchase with cash. The total estimated construction cost of this project is approximately $400 million. As of December 31, 2000, we had spent $17.8 million on construction costs for the Sunrise Project.
ACQUISITION OF TRADING OPERATIONS OF CITIZENS POWER LLC
On September 1, 2000, we completed a transaction with P&L Coal Holdings Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading operations of Citizens Power LLC and a minority interest in structured transaction investments relating to long-term power purchase agreements. The purchase price of $44.9 million was based on the sum of: (a) fair market value of the trading portfolio and the structured transaction investments at the date of the acquisition and (b) $25 million. The acquisition was funded with cash. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. By the end of the third quarter of 2000, the Citizens trading operations were merged into our own marketing operations under Edison Mission Marketing & Trading, Inc.
ACQUISITION OF INTEREST IN ITALIAN WIND
On March 15, 2000, we completed a transaction with UPC International Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy. All the projects use wind to generate electricity from turbines which is sold under fixed-price, long-term tariffs. Assuming all the projects under development are completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW. The total purchase price is 90 billion Italian Lira (approximately $44 million at December 31, 2000), with equity contribution obligations of up to 33 billion Italian Lira (approximately $16 million at December 31, 2000), depending on the number of projects that are ultimately developed. As of December 31, 2000, our payments in respect of these projects included $27 million toward the purchase price and $13 million in equity contributions.
ACQUISITION OF ILLINOIS PLANTS
On December 15, 1999, we completed a transaction with Commonwealth Edison, a subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel power generating plants located in Illinois, which are collectively referred to as the Illinois Plants. These plants 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 terms of up to five years, pursuant to which Commonwealth Edison purchases capacity and has the right to purchase energy generated by the plants. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, LLC.
Concurrently with the acquisition of the Illinois Plants, we assigned our right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating station located in Illinois, to third party lessors. After this assignment, we entered into leases of the Collins Station with terms of 33.75 years. The aggregate megawatts either purchased or leased as a result of these transactions with Commonwealth Edison and the third party lessors is 9,539 MW.
Consideration for the Illinois Plants, excluding $860 million paid by the third party lessors to acquire the Collins Station, consisted of a cash payment of approximately $4.1 billion. The acquisition was funded primarily with a combination of approximately $1.6 billion of non-recourse debt secured by a pledge of the stock of specified subsidiaries, $1.3 billion of Edison Mission Energy's debt and $1.2 billion in equity contributions to us from Edison International.
ACQUISITION OF FERRYBRIDGE AND FIDDLER'S FERRY PLANTS
On July 19, 1999, we completed a transaction with PowerGen UK plc to acquire the Ferrybridge and Fiddler's Ferry coal fired electric generating plants located in the U.K. Ferrybridge, located in West
Yorkshire, and Fiddler's Ferry, located in Warrington, each has a generating capacity of approximately 2,000 MW.
Consideration for the purchase of the Ferrybridge and Fiddler's Ferry plants by our indirect subsidiary, Edison First Power, consisted of an aggregate of approximately $2.0 billion (L1.3 billion sterling at the time of the acquisition) for the two plants. The acquisition was funded primarily with a combination of net proceeds of L1.15 billion from the Edison First Power Limited Guaranteed Secured Variable Rate Bonds due 2019, a $500 million equity contribution to us from Edison International and cash. The Edison First Power Bonds were issued to a special purpose entity formed by Merrill Lynch International. Merrill Lynch International sold the variable rate coupons portion of the bonds to a special purpose entity that borrowed $1.3 billion (830 million pounds sterling at the time of the acquisition) 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 an overseas public offering resulting in widespread ownership among the citizens of New Zealand and offshore investors. These shares are publicly traded on stock exchanges in New Zealand and Australia. During 2000, we increased our share of ownership in Contact Energy to 42%. 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 2,449 MW.
Consideration for Contact Energy consisted of a cash payment of approximately $635 million (1.2 billion New Zealand dollars at the time of the acquisition), which was financed by $120 million of preferred securities, a $214 million (400 million New Zealand dollars at the time of the acquisition) credit facility, a $300 million equity contribution to us from Edison International and cash. The credit facility was subsequently paid off with proceeds from the issuance of additional preferred securities.
ACQUISITION OF HOMER CITY PLANT
On March 18, 1999, we completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to acquire the 1,884 MW Homer City Electric Generating Station. This facility is a coal fired plant in the mid-Atlantic region of the United States and has direct, high voltage interconnections to both the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly known as the NYISO, and the Pennsylvania-New Jersey-Maryland Power Pool, which is commonly known as the PJM.
Consideration for the Homer City plant consisted of a cash payment of approximately $1.8 billion, which was partially financed by $1.5 billion of new loans, combined with our revolver borrowings and cash.
ACQUISITION OF INTEREST IN ECOELECTRICA
In December 1998, we acquired 50% of the 540 MW EcoElectrica liquefied natural gas combined-cycle cogeneration facility under construction in Penuelas, Puerto Rico for approximately $243 million. The project also includes a desalination plant and liquefied natural gas storage and vaporization facilities. Commercial operation commenced in March 2000.
ACCOUNTING TREATMENT OF ACQUISITIONS
Each of the acquisitions described above has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and liabilities assumed based on their
respective fair market values. Amounts in excess of the fair value of the net assets acquired have been assigned to goodwill. Our consolidated statement of income reflects the operations of Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, EcoElectrica beginning March 1, 2000, the Homer City plant beginning March 18, 1999, Contact Energy beginning May 1, 1999, the Ferrybridge and Fiddler's Ferry plants beginning July 19, 1999, and the Illinois Plants beginning December 15, 1999.
DISPOSITIONS
On August 16, 2000, we completed the sale of 30% of our interest in the Kwinana cogeneration plant to SembCorp Energy. We retain the remaining 70% ownership interest in the plant. Proceeds from the sale were $12 million. We recorded a gain on the sale of $8.5 million ($7.7 million after tax).
On June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a gain on the sale of $17 million ($10.5 million after tax).
SALE-LEASEBACK TRANSACTIONS
On August 24, 2000, we entered into a sale-leaseback transaction for the Powerton and Joliet power facilities located in Illinois to third party lessors for an aggregate purchase price of $1.367 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), our subsidiary makes semi-annual lease payments on each January 2 and July 2, beginning January 2, 2001. Edison Mission Energy guarantees the subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, we have a right of first refusal to acquire the interest at fair market value. Minimum lease payments during the next five years are $83.3 million for 2001, $97.3 million for 2002, $97.3 million for 2003, $97.3 million for 2004, and $141.1 million for 2005. At December 31, 2000, the total remaining minimum lease payments are $2.4 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain recognized on the sale of the power facilities has been deferred and is being amortized over the term of the leases.
On July 10, 2000, one of our subsidiaries entered into a sale-leaseback of equipment, primarily Illinois peaker power units, to a third party lessor for $300 million. Under the terms of the 5-year lease, we have a fixed price purchase option at the end of the lease term of $300 million. We guarantee the monthly payments under the lease. In connection with the sale-leaseback, a subsidiary of ours purchased $255 million of notes issued by the lessor which accrue interest at LIBOR plus 0.65% to 0.95%, depending on our credit rating. The notes are due and payable in five years. The gain recognized on the sale of equipment has been deferred and is being amortized over the term of the lease.
RESULTS OF OPERATIONS
We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific, and Europe, Central Asia, Middle East and Africa.
Operating revenues are derived from our majority-owned domestic and international entities. Equity in income from investments relates to energy projects where our ownership interest is 50% or less in the projects. The equity method of accounting is generally used to account for the operating results of entities over which we have a significant influence but in which we do not have a controlling interest. With respect to entities accounted for under the equity method, we recognize our proportional share of the income or loss of such entities.
AMERICAS
OPERATING REVENUES
Operating revenues increased $1.2 billion in 2000 compared to 1999, and increased $348.7 million in 1999 compared to 1998. The 2000 increase resulted from a full-year of electric revenues from the Illinois Plants acquired in December 1999 and the Homer City plant acquired in March 1999. The 1999 increase resulted from electric revenues from the Homer City plant. There were no comparable electric revenues for the Homer City plant for 1998.
Electric power generated at the Illinois Plants is sold under three five-year power purchase agreements with Exelon Generation Company, terminating in December 2004. Exelon Generation is obligated to make capacity payments for the plants under contract and an energy payment for electricity produced by these plants. Our revenues under these power purchase agreements were $1.1 billion for the year ended December 31, 2000. This represented 33% of our consolidated operating revenues in 2000.
On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. Our energy trading activities are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Net gains from energy trading activities since the date of this acquisition were $62.2 million. Our price risk management activities included economic hedge transactions that required mark to market accounting. Total losses from price risk management activities were $79.5 million and $6.4 million in 2000 and 1999, respectively. The increase in losses was primarily due to realized and unrealized losses for a gas swap entered into as an economic hedge of a portion of our gas price risk related to our share of gas production in Four Star (an oil and gas company in which we have a minority interest and which we account for under the equity method). Although we believe the gas swap hedges our gas price risk, hedge accounting is not permitted for our investments accounted for on the equity method.
Partially offsetting this loss in 2000 was a gain realized for calendar year 2001 financial options entered into beginning August 2000 as a hedge of our price risk associated with expected natural gas purchases at the Illinois Plants. During the fourth quarter, we determined that it was no longer probable that we would purchase natural gas at the Illinois Plants during 2001. This decision resulted from sustained gas prices far greater than were contemplated when we originally projected our 2001 gas needs and the fact that we can use fuel oil interchangeably with natural gas at some of the Illinois Plants. At the time we made our revised determination, the fair value of our financial option was $38 million. This gain is being deferred as required by hedge accounting and will be recognized upon either purchasing natural gas in 2001 or determining that it is probable we will not purchase natural gas
in 2001. Subsequent to our revised determination, we settled the option for a $56 million gain. Accordingly, $18 million of gain was recognized in the fourth quarter. Concurrent with our revised determination of our 2001 natural gas requirements at the Illinois Plants, we entered into some additional fuel contracts to offset our financial option and economically hedge the price risk associated with fuel oil. We recognized a $12 million loss at December 31, 2000 on these additional fuel contracts.
Equity in income from investments rose 14% in 2000 over 1999, and 22% in 1999 over 1998. The 2000 increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing and higher revenues from oil and gas investments due to higher oil and gas prices. The 1999 increase was primarily the result of higher revenues from several cogeneration projects due to a final settlement on energy prices tied to short-run avoided cost with the applicable public utilities and, second, from one cogeneration project as a result of a gain on termination of a power sales agreement. In addition, the 1999 increase resulted from higher revenues from oil and gas investments primarily due to higher oil and gas prices.
Many of the domestic energy projects in which our ownership interest is 50% or less rely on one power sales contract with a single electric utility customer for the majority, and in some cases all, of their power sales revenues over the life of the power sales contract. The primary power sales contracts for four of our operating projects in 2000 and 1999 and five of our operating projects in 1998 are with Southern California Edison. Our share of equity in earnings from these projects accounted for 5% in 2000, 8% in 1999 and 13% in 1998 of our consolidated revenues for the respective years. For more information on these projects and other projects in California, see "--Commitments and Contingencies--California Power Crisis."
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 equity in income from investments in energy projects is materially higher than other quarters of the year due to higher summer pricing for our West Coast power investments.
OPERATING EXPENSES
Fuel and plant operations increased $893.9 million in 2000 compared to 1999, and increased $215.5 million in 1999 compared to 1998. The 2000 increase resulted from a full year of expenses at the Illinois Plants and the Homer City plant. The 1999 increase in fuel and plant operations resulted from having no comparable expenses for the Homer City plant and the Illinois Plants for 1998.
Depreciation and amortization expense increased $138.7 million in 2000 compared to 1999, and increased $42.7 million in 1999 compared to 1998. The 2000 increase was primarily due to a full year of depreciation and amortization expense related to the Illinois Plants. The 1999 increase in depreciation and amortization compared to 1998 resulted primarily from the 1999 acquisition of the Homer City plant.
Administrative and general expenses for 2000 consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts from September 1, 2000, the acquisition date of Citizens Power LLC, through December 31, 2000. Prior to September 1, 2000, administrative and general expenses incurred by our own marketing operations were reflected in Corporate/Other administrative and general expenses.
OPERATING INCOME
Operating income increased $160.2 million in 2000 compared to 1999, and increased $124.3 million in 1999 compared to 1998. The 2000 increase was primarily due to operating income from the Illinois Plants, the Homer City plant and equity in income from investments in oil and gas. The 1999 increase
resulted from operating income from the Homer City plant and equity in income from investments in energy projects.
ASIA PACIFIC
OPERATING REVENUES
Operating revenues decreased $29.4 million in 2000 compared to 1999, and increased $8.5 million in 1999 compared to 1998. The 2000 decrease was attributable to lower electric revenues from our Loy Yang B plant. During May 2000, we experienced a major outage due to damage to the generator at one of our two 500 MW units at the Loy Yang B power plant complex in Australia. The unit was restored to operation in September 2000. Under our insurance program, we are obligated for the property damage insurance deductible of $2 million and for loss of profits during the first 15 days following the insurable event. The repair costs in excess of the deductible amount together with the loss of profits after the first 15 days and until the unit was back in operation were partially recovered from insurance as of December 31, 2000. The 1999 increase was primarily due to higher electric revenues from the Loy Yang B plant due to increased generation in 1999; as compared to 1998, when the plant experienced longer planned outages.
Equity in income from investments decreased $3.5 million in 2000 compared to 1999, and increased $16.8 million in 1999 compared to 1998. The 2000 decrease is primarily due to lower profitability of our interest in Contact Energy resulting from lower electricity prices caused by milder winter weather conditions. The 1999 increase reflects the purchase of our 40% ownership interest in Contact Energy in May 1999.
OPERATING EXPENSES
Fuel and plant operations decreased $12.3 million in 2000 compared to 1999, and increased $4.2 million in 1999 compared to 1998. The 2000 decrease resulted primarily from lower fuel costs at the Loy Yang B plant due to the major outage at one of its two 500 MW units. The 1999 increase in fuel expense and plant operations resulted from higher fuel costs from the Loy Yang B plant due to increased production in 1999; as compared to 1998, when the plant had lower fuel expenses and longer planned outages.
Depreciation and amortization expense decreased $5.5 million in 2000 compared to 1999, and increased $8.9 million in 1999 compared to 1998. The 2000 decrease was primarily due to favorable changes in foreign exchange rates. The 1999 increase in depreciation and amortization expense related to the acquisition of our interest in 1999 in the Contact Energy project.
OPERATING INCOME
Operating income decreased $15.1 million in 2000 compared to 1999, and increased $12.2 million in 1999 compared to 1998. The 2000 decrease was due to lower operating income from the Loy Yang B plant resulting from the major outage at one of its two 500 MW units and a decrease in the value of the Australian dollar compared to the U.S. dollar. We recorded pre-tax losses of $8.4 million in 2000 related to this outage. The 1999 increase resulted from the acquisition of Contact Energy.
EUROPE, CENTRAL ASIA, MIDDLE EAST AND AFRICA
OPERATING REVENUES
Operating revenues increased $430.5 million in 2000 compared to 1999, and increased $336.4 million in 1999 compared to 1998. The 2000 increase resulted from a full year of electric revenues from the Ferrybridge and Fiddler's Ferry plants acquired in July 1999 and the Doga project, which commenced commercial operation in May 1999. Despite the overall increase in operating revenues in 2000 which resulted from the inclusion of a full year of operations of these projects, electric revenues from Ferrybridge and Fiddler's Ferry in 2000 were adversely affected by lower energy prices during the year, primarily due to increased competition, warmer-than-average weather and uncertainty surrounding planned changes in electricity trading arrangements described under "--Market Risk Exposures--United Kingdom." The time weighted average System Marginal Price dropped from L22.39/MWh in 1999 to L18.75/MWh in 2000. We have entered into electricity rate price swaps for the majority of our forecasted generation through the winter 2000/2001, and accordingly, have mitigated the downside risks to further decreases in energy prices during this period. Despite improvement in capacity prices during August, September and early October 2000, and a slight firming of forward prices, the short-term prices for energy continue to be below the prices in prior years. As a result of the foregoing, we continue to expect lower revenues from our Ferrybridge and Fiddler's Ferry plants in 2001. The 1999 increase as compared to 1998 was primarily due to inclusion of electric revenues from the Ferrybridge and Fiddler's Ferry plants and the Doga project. There were no comparable electric revenues for the Ferrybridge and Fiddler's Ferry plants and the Doga project for 1998. The First Hydro plants, Ferrybridge and Fiddler's Ferry plants and the Iberian Hy-Power plants are expected to provide for higher electric revenues during the winter months.
Equity in income from investments decreased $6.4 million in 2000 compared to 1999, and decreased $2.1 million in 1999 compared to 1998. The 2000 decrease reflects losses from initial commercial operation of the ISAB project in April 2000. We had no comparable results for the ISAB project in 1999.
OPERATING EXPENSES
Fuel and plant operations increased $273.5 million in 2000 compared to 1999, and increased $215.3 million in 1999 compared to 1998. The 2000 increase resulted from a full year of expenses at the
Ferrybridge and Fiddler's Ferry plants and the Doga project, partially offset by lower fuel expense at the First Hydro plant. Fuel expense at First Hydro decreased primarily due to a drop in energy prices throughout the year and lower pumping costs. The 1999 increase in fuel expense and plant operations resulted from having no comparable expenses for the Ferrybridge and Fiddler's Ferry plants and the Doga project for 1998.
Depreciation and amortization expense increased $56.5 million in 2000 compared to 1999, and increased $48 million in 1999 compared to 1998. The 2000 increase was primarily due to a full year of depreciation and amortization expense associated with the Ferrybridge and Fiddler's Ferry plants. The 1999 increase in depreciation and amortization resulted primarily from the 1999 acquisition of the Ferrybridge and Fiddler's Ferry plants.
OPERATING INCOME
Operating income increased $94.1 million in 2000 compared to 1999, and increased $71 million in 1999 compared to 1998. The 2000 increase was primarily due to operating income from the Ferrybridge and Fiddler's Ferry plants, the Doga project and higher operating income from the First Hydro plant. The 1999 increase resulted from the inclusion of operating income from the Ferrybridge and Fiddler's Ferry plants and the Doga project.
CORPORATE/OTHER
Long-term incentive compensation expense consists of charges related to our now terminated phantom option plan. Long-term incentive compensation expenses decreased $192.3 million in 2000 compared to 1999, and increased $97.3 million in 1999 compared to 1998. The 2000 decrease was due to the absence of new accruals, as the plan had been terminated, and to a reduction in the liability for previously accrued incentive compensation by approximately $60 million. This decrease resulted from the lower valuation implicit in the August 2000 exchange offer pursuant to which the phantom option plan was terminated compared to the value previously accrued. The 1999 increase was primarily due to the impact of the 1999 acquisitions of the Illinois Plants, the Ferrybridge and Fiddler's Ferry plants, the Homer City plant and a 40% interest in Contact Energy. No further phantom option plan grants were made in 2000 and, since the plan and all of the outstanding phantom stock options have been terminated, no further phantom stock options will be granted or exercised.
Administrative and general expenses increased $24.9 million in 2000 compared to 1999, and increased $31 million in 1999 compared to 1998. The increases in both periods were primarily due to additional salaries and facilities costs incurred to support the 1999 acquisitions. We recorded a pretax charge of approximately $9 million against earnings for severance and other related costs, which contributed to the 2000 increase. The charge resulted from a series of actions undertaken by us designed to reduce administrative and general operating costs, including reductions in management and administrative personnel.
OTHER INCOME (EXPENSE)
On August 16, 2000, we completed the sale of 30% of our interest in the Kwinana cogeneration plant to SembCorp Energy. We retain the other 70% ownership interest in the plant. Proceeds from the sale were $12 million. We recorded a gain on the sale of $8.5 million ($7.7 million after tax).
On June 30, 2000, we completed the sale of our 50% interest in the Auburndale project to the existing partner. Proceeds from the sale were $22 million. We recorded a gain on the sale of $17 million ($10.5 million after tax).
During the fourth quarter of 1999, we completed the sale of 31.5% of our 50.1% interest in Four Star Oil & Gas for $34.2 million in cash and a 50% interest in the acquirer, Four Star Holdings. Four Star Holdings financed the purchase of the interest in Four Star Oil & Gas from $27.5 million in loans from affiliates, including $13.7 million from us, and $13.7 million from cash. Upon completion of the sale, we continue to own an 18.6% direct interest in Four Star Oil & Gas and an indirect interest of 15.75% which is held through Four Star Holdings. As a result of this transaction, our total interest in Four Star Oil & Gas has decreased from 50.1% to 34.35%. Cash proceeds from the sale were $34.2 million ($20.5 million net of the loan to Four Star Holdings). The gain on the sale of the 31.5% interest in Four Star Oil & Gas was $11.5 million of which we deferred 50%, or $5.6 million, due to our equity interest in Four Star Holdings. The after-tax gain on the sale was approximately $30 million.
Interest expense increased $336.2 million in 2000 compared to 1999, and increased $170.3 million in 1999 compared to 1998. The 2000 increase was primarily the result of additional debt financing associated with the acquisitions of the Illinois Plants, Ferrybridge and Fiddler's Ferry plants and the Homer City plant. The 1999 increase was also the result of debt financing of the Homer City plant, Ferrybridge and Fiddler's Ferry plants and the Illinois Plants acquisition.
Dividends on mandatorily redeemable preferred securities increased $9.7 million in 2000 compared to 1999 and increased $9.2 million in 1999 compared to 1998. The 2000 and 1999 increases reflect the issuance of preferred securities in connection with the Contact Energy acquisition.
PROVISION (BENEFIT) FOR INCOME TAXES
We had effective tax provision (benefit) rates of 40.3%, (39.0)% and 34.8% in 2000, 1999 and 1998, respectively. Income taxes increased in 2000 principally due to a higher foreign income tax expense compared to 1999, nonrecurring 1999 tax benefits discussed below and higher state income taxes due to the Homer City plant and Illinois Plants. Income taxes decreased in 1999, principally due to lower pre-tax income and income tax benefits. In 1999, we recorded tax benefits associated with a capital loss attributable to the sale of a portion of our interest in Four Star Oil & Gas Company, refunds of advanced corporation tax payments from the United Kingdom and a reduction in deferred taxes in Australia as a result of a decrease in statutory rates. In addition, our effective tax rate has decreased as a result of lower foreign income taxes that result from the permanent reinvestment of earnings from foreign affiliates located in different foreign tax jurisdictions. The Australian corporate tax rate decreased from 36% to 34% effective in July 2000, and is scheduled to decrease from 34% to 30% effective in July 2001. The 1998 tax provision reflects a benefit from reductions in the U.K corporate tax rate from 33% to 31% effective in April 1997, and from 31% to 30% effective in April 1999. In accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the reductions in the Australia and U.K. income tax rates resulted in reductions in income tax expense of approximately $5.9 million and $11 million in 1999 and 1998, respectively.
We are, and may in the future be, under examination by tax authorities in varying tax jurisdictions with respect to positions we take in connection with the filing of our tax returns. Matters raised upon audit may involve substantial amounts, which, if resolved unfavorably, an event not currently
anticipated, could possibly be material. However, in our opinion, it is unlikely that the resolution of any such matters will have material adverse effect upon our financial condition or results of operations.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as the "accrue in advance" accounting method). The accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the Securities and Exchange Commission issued a letter to the Accounting Standards Executive Committee, stating its position that the Securities and Exchange Commission staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance costs. The Accounting Standards Executive Committee agreed to add accounting for major maintenance costs as part of an existing project and to issue authoritative guidance by August 2001. Due to the position taken by the Securities and Exchange Commission staff, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. Such change in accounting policy is considered preferable based on the recent guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we have recorded a $17.7 million, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000.
In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities," which became effective in January 1999. The Statement requires that specified costs related to start-up activities be expensed as incurred and that specified previously capitalized costs be expensed and reported as a cumulative change in accounting principle. The reduction to our net income that resulted from adopting SOP 98-5 was $13.8 million, after tax.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2000, we had cash and cash equivalents of $962.9 million and had available a total of $41 million of borrowing capacity under a $500 million revolving credit facility that expires on October 11, 2001 and a $300 million senior credit facility that expires on May 29, 2001. We also had available $127.3 million of borrowing capacity under a $700 million senior credit facility that is now scheduled to expire on May 29, 2001. The revolving credit facility provides credit available in the form of cash advances or letters of credit, and bears interest on advances under the London Interbank Offered Rate, LIBOR, which was 6.66% at December 31, 2000, plus the applicable margin as determined by our long-term credit ratings (0.175% margin at December 31, 2000). In addition to the interest component described above, we pay a facility fee as determined by our long-term credit ratings (0.09% at December 31, 2000) on the entire credit facility independent of the level of borrowings.
Net working capital at December 31, 2000 was ($1,703.9) million compared to ($815.5) million at December 31, 1999. The decrease reflects the reclassification to current maturities of long-term obligations from long-term obligations at December 31, 2000 of indebtedness under the financing documents entered into to finance the acquisition of the Ferrybridge and Fiddler's Ferry plants in 1999. See "--Financing Plans" for further discussion.
Cash provided by operating activities is derived primarily from operations of the Illinois Plants and the Homer City plant, distributions from energy projects and dividends from investments in oil and gas. Net cash provided by operating activities increased $248.1 million in 2000 compared to 1999 and $150.6 million in 1999 compared to 1998. The 2000 increase primarily reflects higher pre-tax earnings from projects acquired in 1999 and higher dividends from oil and gas investments. The 1999 increase was primarily due to higher distributions from energy projects and higher dividends from oil and gas investments.
Net cash used in financing activities totaled $783 million in 2000, compared to net cash provided by financing activities of $8,363.5 million and $17.9 million in 1999 and 1998, respectively. Payments made on our credit facilities totaling $1.4 billion, a $500 million payment on our floating rate notes and the redemption of the Flexible Money Market Cumulative Preferred Stock for $124.7 million were the primary contributors of the net cash used in financing activities during 2000. Edison Mission Energy used the proceeds from the August 2000 Powerton and Joliet sale-leaseback transaction for a significant portion of those payments on the credit facilities, commercial paper facilities and the floating rate notes. We also paid dividends of $88 million to Edison International. In 2000, we also had borrowings of $1.2 billion under our credit facilities and commercial paper facilities. In February 2000, Edison Mission Midwest Holdings Co. issued $1.7 billion of commercial paper under its credit facility and repaid a similar amount of its outstanding bank borrowings for the Illinois Plants. Subsequently, Edison Mission Midwest Holdings Co. repaid $769.3 million of commercial paper under its credit facility and issued a similar amount of its bank borrowings for the Illinois Plants in December 2000. In January 2000, one of our foreign subsidiaries borrowed $242.7 million from Edison Capital, an indirect affiliate. In 1999, financings related to the acquisition of four new projects in 1999 contributed to net cash provided by financing activities. A term loan facility of $1.3 billion related to the Ferrybridge and Fiddler's Ferry plants, senior secured bonds totaling $830 million related to the Homer City plant, $120 million Flexible Money Market Cumulative Preferred Stock and $125 million Retail Redeemable Preference Shares and $84 million Class A Redeemable Preferred Shares related to Contact Energy and credit facilities totaling $1.7 billion related to the Illinois Plants. In addition, our financings in connection with the aforementioned acquisitions consisted of floating rate notes of $500 million, borrowings of $215 million under our revolving credit facility and commercial paper facilities totaling $1.2 billion. In addition, we also received $2 billion in equity contributions from Edison International, which amount was 100% financed in the capital markets, to finance our 1999 acquisitions. In June 1999, we issued $600 million of 7.73% Senior Notes due 2009. As of December 31, 2000, we had recourse debt of $2.1 billion, with an additional $5.9 billion of non-recourse debt (debt which is recourse to specific assets or subsidiaries, but not to Edison Mission Energy) on our consolidated balance sheet.
Net cash provided by investing activities totaled $718.1 million in 2000, compared to net cash used in investing activities of $8,837.8 million and $408.2 million in 1999 and 1998, respectively. In 2000, net cash provided by investing activities was primarily due to proceeds of $1.367 billion and $300 million received from the sale leaseback transactions with respect to the Powerton and Joliet power facilities in August 2000 and the Illinois peaker power units in July 2000, respectively. In connection with the Illinois peaker power units transaction, we purchased $255 million of notes issued by the lessor. In 2000, $27 million was paid toward the purchase price and $13 million in equity contributions for the Italian Wind projects, $44.9 million for the Citizens trading operations and structured transaction investments, and $27 million for the acquisition of the Sunrise project. In addition, $33.5 million, $21.2 million and $20 million was made in equity contributions for the EcoElectrica project (June 2000), the Tri Energy project (July 2000) and the ISAB project (September 2000), respectively. In 1999, cash used in investing activities was primarily due to the purchase of the Homer City plant, Ferrybridge and Fiddler's Ferry generating facilities, the Illinois Plants and the 40% interest in Contact Energy. We invested $352.3 million, $216.4 million and $73.4 million in 2000, 1999 and 1998, respectively, in new plant and equipment principally related to the Homer City plant and Illinois Plants in 2000, the Homer City plant and Ferrybridge and Fiddler's Ferry plants in 1999, and the Doga project in 1998.
CREDIT RATINGS
On January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions to isolate ourselves from the credit downgrades and potential bankruptcies of Edison International and Southern California Edison and to facilitate our ability and the ability of our
subsidiaries to maintain their respective investment grade ratings. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity despite the current credit difficulties of Edison International and Southern California Edison. These provisions require the unanimous approval of our board of directors, including at least one independent director, before we can do any of the following:
- declare or pay dividends or distributions unless:
- we then have an investment grade rating and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or
- the dividends do not exceed $32.5 million in any fiscal quarter and we meet an interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters. We currently meet this interest coverage ratio;
- institute or consent to bankruptcy, insolvency or similar proceedings or actions; or
- consolidate or merge with any entity or transfer substantially all our assets to any entity, except to an entity that is subject to similar restrictions.
We cannot assure you that these measures will effectively isolate us from the credit downgrades or the potential bankruptcies of Edison International and Southern California Edison. In January 2001, Standard & Poor's and Moody's lowered our credit ratings. Our senior unsecured credit ratings were downgraded to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's. Our credit ratings remain investment grade. Both Standard & Poor's and Moody's have indicated that the credit ratings outlook for us is stable.
We cannot assure you that Standard & Poor's and Moody's will not downgrade us below investment grade, whether as a result of the California power crisis or otherwise. If we are downgraded, we could be required to, among other things:
- provide additional guarantees, collateral, letters of credit or cash for the benefit of counterparties in our trading activities,
- post a letter of credit or cash collateral to support our $58.5 million equity contribution obligation in connection with our acquisition in February 2001 of a 50% interest in the CBK project in the Philippines, and
- repay a portion of the preferred shares issued by our subsidiary in connection with our 1999 acquisition of a 40% interest in Contact Energy Limited, a New Zealand power company, which, based on their value at March 20, 2001, would require a payment of approximately $19 million.
Our downgrade could result in a downgrade of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below its current credit rating, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, limit the ability of Midwest Generation to use excess cash flow to make distributions.
On March 15, 2001, the California Public Utilities Commission released a draft of a proposed order instituting an investigation into whether California's investor-owned utilities, including Southern California Edison, have complied with past Commission decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. Action on this agenda item repeatedly has been deferred, including at the Commission meeting on March 27, 2001, and the item has continued to appear on the agendas for subsequent Commission meetings. The proposed order would reopen the past holding company decisions and initiate an investigation into the following matters:
- whether the holding companies, including Edison International, violated requirements to give priority to the capital needs of their respective utility subsidiaries;
- whether the ring-fencing actions by Edison International and PG&E Corporation and their respective nonutility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries;
- whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies;
- any additional suspected violations of laws or Commission rules and decisions; and
- whether additional rules, conditions, or other changes to the holding company decisions are necessary.
We cannot predict whether the Commission will institute this investigation or what effects any investigation or subsequent actions by the Commission may have on Edison International or indirectly on us.
A downgrade in our credit rating below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries.
RESTRICTED ASSETS OF SUBSIDIARIES
Each of our direct or indirect subsidiaries is organized as a legal entity separate and apart from us and our other subsidiaries. Assets of our subsidiaries may not be available to satisfy our obligations or the obligations of any of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.
FINANCING PLANS
CORPORATE FINANCING PLANS
We have three corporate credit facilities that are scheduled to expire in May 2001 (in a total amount of $1 billion) and October 2001 (in an amount of $500 million). As of March 16, 2001, we have borrowed or issued letters of credit aggregating $1.49 billion under these credit facilities and have an unused capacity of approximately $10 million. We plan to refinance these credit facilities through modifications to our existing credit facilities or by entering into new short-term facilities prior to their expiration. Our corporate cash requirements in 2001 are expected to exceed cash distributions from our subsidiaries. Our corporate cash requirements in 2001 include:
- debt service under our senior notes and intercompany notes resulting from sale-leaseback transactions which aggregate $149 million;
- capital requirements for projects in development and under construction of $251 million; and
- development costs, general and administrative expenses.
We plan to finance these activities through new short-term facilities and through the use of project or subsidiary financings or capital markets debt, depending on market conditions. However, while we cannot assure you that we will be able to enter into modifications to our existing credit facilities or obtain additional debt to finance our needs or that the credit facilities can be modified or obtained under similar terms and rates as our agreements, we believe our corporate financing plans will be successful in meeting our cash requirements in 2001. In addition, to reduce debt and to provide additional liquidity, we may sell our interest in individual projects in our project portfolio. Under one of our credit facilities, we are required to use 50% of the net proceeds from the sale of assets and 75% of the net proceeds from the issuance of capital markets debt to repay senior bank indebtedness, in
each case in excess of $300 million in the aggregate. There is no assurance that we will be able to sell assets on favorable terms or that the sale of individual assets will not result in a loss.
SUBSIDIARY FINANCING PLANS
During 2001, the estimated capital expenditures of our subsidiaries is $262 million, including environmental expenditures disclosed under "--Environmental Matters and Regulations." These capital expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations. Other than as described under "--Commitments and Contingencies," we do not plan to make additional capital contributions to our subsidiaries.
One of our subsidiaries, Edison First Power, has defaulted on its financing documents related to the acquisition of the Fiddler's Ferry and Ferrybridge power plants. The financial performance of the Fiddler's Ferry and Ferrybridge power plants has not matched our expectations, largely due to lower energy power prices resulting primarily from increased competition, warmer-than-average weather and uncertainty surrounding the new electricity trading arrangements. See "--Market Risk Exposures--United Kingdom." As a result, Edison First Power has decided to defer some environmental capital expenditures originally planned to increase plant utilization and therefore is currently in breach of milestone requirements for the implementation of the capital expenditures program set forth in the financing documents relating to the acquisition of these plants. In addition, due to this reduced financial performance, Edison First Power's debt service coverage ratio during 2000 declined below the threshold set forth in the financing documents.
Edison First Power is currently in discussions with the relevant financing parties to revise the required capital expenditure program, to waive (i) the breach of the financial ratio covenant for 2000, (ii) a technical breach of requirements for the provision of information that was delayed due to uncertainty regarding capital expenditures, and (iii) other related technical defaults. Edison First Power is in the process of requesting the necessary waivers and consents to amendments from the financing parties. We cannot assure you that waivers and consents to amendments will be forthcoming. The financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing parties are entitled to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite the breaches under the financing documents, Edison First Power's debt service coverage ratio for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service payments, Edison First Power utilized L37 million from its debt service reserve to meet its debt service requirements in 2000.
Another of our subsidiaries, EME Finance UK Limited, is the borrower under the facility made available for the purposes of funding coal and capital expenditures related to the Fiddler's Ferry and Ferrybridge power plants. At December 31, 2000, L58 million was outstanding for coal purchases and zero was outstanding to fund capital expenditures under this facility. EME Finance UK Limited on-lends any drawings under this facility to Edison First Power. The financing parties of this facility have also issued letters of credit directly to Edison First Power to support their obligations to lend to EME Finance UK Limited. EME Finance UK Limited's obligations under this facility are separate and apart from the obligations of Edison First Power under the financing documents related to the acquisition of these plants. We have guaranteed the obligations of EME Finance UK Limited under this facility, including any letters of credit issued to Edison First Power under the facility, for the amount of L359 million, and our guarantee remains in force notwithstanding any breaches under Edison First Power's acquisition financing documents.
In addition, Edison Mission Energy may provide guarantees in support of bilateral contracts entered into by Edison First Power under the new electricity trading arrangements. Edison Mission Energy has provided guarantees totalling L19 million relating to these contracts at March 20, 2001.
In accordance with SFAS No. 121, "ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED", we have evaluated impairment of the Ferrybridge and Fiddler's Ferry
power plants. The undiscounted projected cash flow from these power plants exceeds the net book value at December 31, 2000, and, accordingly, no impairment of these power plants is permitted under SFAS No. 121. As a result of the change in the prices of power in the U.K., we are considering the sale of Ferrybridge and Fiddler's Ferry power plants. Management has not made a decision whether or not the sale of these power plants will ultimately occur and, accordingly, these assets are not classified as held for sale. However, if a decision to sell the Ferrybridge and Fiddler's Ferry power plants were made, it is likely that the fair value of the assets would be substantially below their book value at December 31, 2000. Our net investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry power plants and related debt was $918 million at December 31, 2000.
COMMITMENTS AND CONTINGENCIES
CAPITAL COMMITMENTS
The following table summarizes our consolidated capital commitments as of December 31, 2000. Details regarding these capital commitments are discussed in the sections referenced.
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* Represents the total estimated costs related to four projects using the Siemens Westinghouse turbines procured under the Edison Mission Energy Master Turbine Lease. One of these projects may be used to meet the new gas fired generation commitments resulting from the acquisition of the Illinois Plants. See "--Illinois Plants--Power Purchase Agreements."
In addition, in February 2001, we purchased a 50% interest in the CBK project for $20 million. Financing for this $460 million project will require equity contributions of $117 million, of which our share is $58.5 million. See "--Recent Developments."
CALIFORNIA POWER CRISIS
We have partnership interests in eight partnerships which own power plants in California which have power purchase contracts with Pacific Gas and Electric and/or Southern California Edison. Three of these partnerships have a contract with Southern California Edison, four of them have a contract with Pacific Gas and Electric, and one of them has contracts with both. In 2000, our share of earnings before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at December 31, 2000 was $345 million.
As a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities has failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the eight power plants which are owned by partnerships in which we have a partnership interest. Southern California Edison did not pay any of the amounts due to the partnerships in January, February and March of 2001 and may continue to miss future payments. Pacific Gas and Electric made its January payment in full but thus far has paid only a small portion of the amounts due to the partnerships in February and March and may not pay all or a portion of its future payments.
On March 27, 2001, the California Public Utilities Commission issued a decision that ordered the three California investor owned utilities, including Southern California Edison and Pacific Gas and Electric, to commence payment for power generated from qualifying facilities beginning in April 2001. In addition, the decision modified the pricing formula for determining short run avoided costs for qualifying facilities subject to these provisions. Depending on how the utilities react to this order, the immediate impact of this decision may be to commence payment in April 2001 at significantly reduced prices for power to qualifying facilities subject to this pricing adjustment. Furthermore, this decision called for further study of the pricing formula tied to short run avoided costs and, accordingly, may be subject to more changes in the future. Finally, this decision is subject to challenge before the Commission, the Federal Energy Regulatory Commission and, potentially, state or federal courts. Although it is premature to assess the full effect of this recent decision, it could have a material adverse effect on our investment in the California partnerships, depending on how it is implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas procured by our California partnerships. This decision did not address payment to the qualifying facilities for amounts due prior to April 2001.
The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly could have an adverse impact on the operations of our California qualifying facilities. Provisions in the partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be taken through the non-affiliated partner in the partnership. Therefore, partnership actions concerning the enforcement of rights under each qualifying facility's power purchase agreement with Southern California Edison in response to Southern California Edison's suspension of payments under that power purchase agreement are to be taken through the non-Edison Mission Energy affiliated partner in the partnership. Some of the partnerships have sought to minimize their exposure to Southern California Edison by reducing deliveries under their power purchase agreements. It is unclear at this time what additional actions, if any, the partnerships will take in regard to the utilities' suspension of payments due to the qualifying facilities. As a result of the utilities' failure to make payments due under these power purchase agreements, the partnerships have called on the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours have made equity contributions totaling approximately $103 million to meet capital calls by the partnerships. Our subsidiaries and the other partners may be required to make additional capital contributions to the partnerships.
Southern California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. Pacific Gas and Electric has taken a different approach and is seeking to invoke force majeure provisions under its power purchase agreements to excuse its failure to pay. In either case, it is possible that the utilities will not pay all their obligations in full. In addition, it is possible that Southern California Edison and/or Pacific Gas and Electric could be forced into bankruptcy proceedings. If this were to occur, payments to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, could be subject to significant delays associated with the lengthy bankruptcy court process and may not be paid in full. At February 28, 2001, accounts receivable due to these partnerships from Southern California Edison and Pacific Gas & Electric were
$437 million; our share of these receivables was $217 million. Furthermore, Southern California Edison's and Pacific Gas and Electric's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court. While we believe that the generation of electricity by the qualifying facilities, including those owned by partnerships in which we have a partnership interest, is needed to meet California's power needs, we cannot assure you either that these partnerships will continue to generate electricity without payment by the purchasing utility, or that the power purchase agreements will not be adversely affected by a bankruptcy or contract renegotiation as a result of the current power crisis.
A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are ongoing. These activities may result in a restructuring of the California power market. At this time, these activities are in their preliminary stages, and it is not possible to estimate their likely ultimate outcome. The situation in California changes on an almost daily basis. You should monitor developments in California for the most up to date information. For more information on the current regulatory situation in California, see "Business--Regulatory Matters--California Deregulation."
CREDIT SUPPORT FOR TRADING AND PRICE RISK MANAGEMENT ACTIVITIES
Our trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc., which is currently rated investment grade ("BBB-" by Standard and Poor's). As part of obtaining an investment grade rating for this subsidiary, we have entered into a support agreement, which commits us to contribute up to $300 million in equity to Edison Mission Marketing & Trading, if needed to meet cash requirements. An investment grade rating is an important benchmark used by third parties when deciding whether or not to enter into master contracts and trades with us. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. If Edison Mission Marketing & Trading does not maintain its investment grade rating or if other events adversely affect its financial position, a third party could request Edison Mission Marketing & Trading to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, additional guarantees, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against Edison Mission Marketing & Trading for any losses.
The California power crisis has adversely affected the liquidity of West Coast trading markets, and to a lesser extent, other regions in the United States. Our trading and price risk management activity has been reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. It is not certain that resolution of the California power crisis will occur in 2001 or that, if resolved, we will be able to conduct trading and price risk management activities in a manner that will be favorable to us.
PAITON
The Paiton project is a 1,230 MW coal fired power plant in operation in East Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a $490 million investment in the project at December 31, 2000. The project's tariff under the power purchase agreement with PT PLN is higher in the early years and steps down over time. The tariff for the Paiton project includes costs relating to 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 PLN. Payments are in Indonesian Rupiah, with the portion of the payments intended to cover non-Rupiah project costs, including returns to investors, adjusted to account for exchange rate fluctuations between the Indonesian Rupiah and the U.S. dollar. The project received substantial finance and insurance support from the Export-Import Bank of the United States, the Japan Bank for International Cooperation (formerly known as The Export-Import Bank of Japan), the U.S. Overseas Private Investment Corporation and the Ministry of Economy, Trade and Industry of Japan (formerly known as the Ministry of International Trade and Industry). PT PLN'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 PLN might not be able to honor the power purchase agreement with P.T. Paiton Energy, the project company. 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.
In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the Paiton project had achieved commercial operation under the terms of the power purchase agreement and, in July 1999, that the second 615 MW unit of the plant had similarly achieved commercial operation. Because of the economic downturn, PT PLN was then experiencing low electricity demand and PT PLN, through February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a lawsuit contesting the validity of its agreement to purchase electricity from the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in connection with this withdrawal, the parties entered into an interim agreement for the period through December 31, 2000, under which dispatch levels and fixed and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made all fixed payments due under the interim agreement totaling $115 million and all payments due for energy delivered by the plant to PT PLN. As part of the continuing negotiations on a long-term restructuring of the tariff, Paiton Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provides for fixed monthly payments aggregating $108 million over its six month duration and for the payment for energy delivered to PT PLN from the plant during this period. Paiton Energy and PT PLN intend to complete the negotiations of the future phases of a new long-term tariff during the six month duration of the Phase I Agreement. To date, PT PLN has made all fixed and energy payments due under the Phase I Agreement.
Events, including those discussed above, have occurred which may mature into defaults of the project's debt agreements following the passage of time, notice or lapse of waivers granted by the project's lenders. On October 15, 1999, the project entered into an interim agreement with its lenders pursuant to which the lenders waived defaults during the term of the agreement and effectively agreed to defer payments of principal until July 31, 2000. In July, the lenders agreed to extend the term of the lender interim agreement through December 31, 2000. In December 2000, the lenders agreed to an additional extension of the lender interim agreement through December 31, 2001. Paiton Energy has received lender approval of the Phase I Agreement.
Under the terms of the power purchase agreement, PT PLN has been required to pay for capacity and fixed operating costs once each unit and the plant achieved commercial operation. As of December 31, 2000, PT PLN had not paid invoices amounting to $814 million for capacity charges and fixed operating costs under the power purchase agreement. All arrears under the power purchase agreement continue to accrue, minus the fixed monthly payments actually made under the year 2000 interim agreement and under the recently agreed Phase I Agreement, with the payment of these arrears to be dealt with in connection with the overall long-term restructuring of the tariff. In this regard, under the Phase I Agreement, Paiton Energy has agreed that, so long as the Phase I Agreement is complied with, it will seek to recoup no more than $590 million of the above arrears, the payment of which is to be dealt with in connection with the overall tariff restructuring.
Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new long-term tariff could require a renegotiation of the Paiton project's debt agreements. The impact of any such renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is uncertain at this time; however, we believe that we will ultimately recover our investment in the project.
BROOKLYN NAVY YARD
Brooklyn Navy Yard is a 286 MW gas fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. At this time, we cannot reasonably estimate the amount that would be due, if any, related to this litigation. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the power plant would be accounted for as an additional part of its power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of up to $10 million over an initial amount, including legal fees, payable from its management and royalty fees. At December 31, 2000, no accrual had 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
Edison Mission Energy has guaranteed to the bondholders, banks and other secured parties which financed the acquisition of the Homer City plant the performance and payment when due by Edison Mission Holdings Co. of its obligations in respect of specified senior debt, up to $42 million. This guarantee will be available until December 31, 2001, after which time Edison Mission Energy will have no further obligations under this guarantee.
To satisfy the requirements under the Edison Mission Holdings Co. bond financing to have a debt service reserve account balance in an amount equal to six months' debt service projected to be due following the payment of a distribution, Edison Mission Energy agreed to guarantee the payment and performance of the obligations of Edison Mission Holdings, in the amount of approximately $35 million, pursuant to a debt service reserve guarantee. In addition, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $3 million to the lenders involved in the bank financing. As a result of Edison Mission Energy's downgrade in January 2001, Edison Mission Holdings is in the process of finalizing the arrangement of a letter of credit of approximately $35 million to replace the bond debt service reserve guarantee.
PREFERRED SHARES OF EDISON MISSION ENERGY TAUPO LIMITED
In connection with the preferred shares issued by Edison Mission Energy Taupo Limited to partially finance the acquisition of the 40% interest in Contact Energy, Edison Mission Energy provided a guaranty of Edison Mission Energy Taupo Limited's obligation to pay a minimum level of non-cumulative dividends on the preferred shares through June 30, 2002, including NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts required to ensure that Edison Misison Energy Taupo Limited will satisfy two financial ratio covenants on specified dates. The first financial ratio, called a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is based on historical and projected dividends received from Contact Energy and the dividends payable to preferred shareholders. The second financial ratio, called a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based on the fair value of our Contact Energy shares and the outstanding preferred shares. If, however, Edison Mission Energy's senior unsecured credit rating by Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be called to perform on its guaranty of Edison Mission Energy Taupo Limited's financial covenants before the specified calculation dates. Based on
the fair value of our ownership in Contact Energy at March 20, 2001, had Edison Mission Energy been required to perform on its guarantee of the debt to valuation ratio as of that date, Edison Mission Energy's obligation would have been approximately $19 million.
EDISON MISSION ENERGY MASTER TURBINE LEASE
In December 2000, we entered into a master lease and other agreements for the construction of new projects using nine turbines that are being procured from Siemens Westinghouse. The aggregate total construction cost of these projects is estimated to be approximately $986 million. Under the terms of the master lease, the lessor, as owner of the projects, is responsible for the development and construction costs of the new projects using these turbines. We have agreed to supervise the development and construction of the projects as the agent of the lessor. Upon completion of construction of each project, we have agreed to lease the projects from the lessor. In connection with the lease, we have provided a residual value guarantee to the lessor at the end of the lease term. We are required to deposit treasury notes equal to 103% of the construction costs as collateral for the lessor which can only be used under circumstances involving our default of the obligations we have agreed to perform during the construction of each project. Lease payments are scheduled to begin in November 2003. Minimum lease payments under this agreement are $3.1 million in 2003, $27.7 million in 2004, and $50.2 million in 2005. The term of the master lease ends in 2010. The master lease grants us, as lessee, a purchase option based on the lease balance which can be exercised at any time during the term.
SALE-LEASEBACK COMMITMENTS
At December 31, 2000, we had minimum lease payments related to purchased power generation assets from Commonwealth Edison that were leased back to us in three separate transactions. In connection with the 1999 acquisition of the Illinois Plants, we assigned the right to purchase the Collins gas and oil-fired power plant to third party lessors. The third party lessors purchased the Collins Station for $860 million and leased the plant to us. During 2000, we entered into sale-leaseback transactions for equipment, primarily the Illinois peaker power units, and for two power facilities, the Powerton and Joliet coal fired stations located in Illinois, to third party lessors. Total minimum lease payments during the next five years are $146.6 million in 2001, $168.6 million in 2002, $168.6 million in 2003, $168.8 million in 2004, and $191.4 million in 2005. At December 31, 2000, the total remaining minimum lease payments were $3.9 billion.
ILLINOIS PLANTS-POWER PURCHASE AGREEMENTS
During 2000, 33% of our electric revenues were derived under power purchase agreements with Exelon Generation Company, a subsidiary of Exelon Corporation, entered into in connection with our December 1999 acquisition of the Illinois Plants. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major utilities located in Illinois and Pennsylvania. Electric revenues attributable to sales to Exelon Generating Company are earned from capacity and energy provided by the Illinois Plants under three five-year power purchase agreements. If Exelon Generation were to fail to or became unable to fulfill its obligations under these power purchase agreements, we may not be able to find another customer on similar terms for the output of our power generating assets. Any material failure by Exelon Generation to make payments under these power purchase agreements could adversely affect our results of operations and liquidity.
Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas-fired power plants having an additional gross dependable capacity of 500 MWs at existing or adjacent power plant site in Chicago. The acquisition documents require that commercial operations of this project be completed by
December 15, 2003. The estimated cost to complete the construction of this 500 MW gas-fired power plant is approximately $250 million.
FUEL SUPPLY CONTRACTS
At December 31, 2000, we had contractual commitments to purchase and/or transport coal and fuel oil. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses in some cases, these minimum commitments are currently estimated to aggregate $2.4 billion in the next five years summarized as follows: 2001--$838 million; 2002--$653 million; 2003--$386 million; 2004--$308 million; 2005--$241 million.
FIRM COMMITMENT FOR ASSET PURCHASE
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(1) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Purchase payments will continue through 2002, depending on the number of projects that are ultimately developed.
FIRM COMMITMENTS TO CONTRIBUTE PROJECT EQUITY
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(1) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Equity will be contributed depending on the number of projects that are ultimately developed.
Firm commitments to contribute project equity could be accelerated due to certain events of default as defined in the non-recourse project financing facilities. Management does not believe that these events of default will occur to require acceleration of the firm commitments.
CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY
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(1) Contingent obligations to contribute additional project equity will be based on events principally related to insufficient cash flow to cover interest on project debt and operating expenses, project cost overruns during plant construction, specified partner obligations or events of default. Our obligation to contribute contingent equity will not exceed $141 million, of which $102 million has been contributed as of December 31, 2000. As of March 16, 2001, $5 million of this amount remains to be funded.
For more information on the Paiton project, see "--Paiton" above.
(2) ISAB is a 512 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 49% interest. Commercial operations
commenced in April 2000. Contingent obligations to contribute additional equity to the project relate specifically to an agreement to provide equity assurances to the project's lenders depending on the outcome of the contractor claim arbitration.
We are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions to be made by us to meet capital calls by partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "--California Power Crisis" for further discussion.
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, 2000, if payment were required, would be $256 million. We have no reason to believe that the projects will either terminate their performance or reduce their electric power producing capability during the term of the power contracts.
OTHER
In support of the businesses of our subsidiaries, we have made, from time to time, guarantees, and have entered into indemnity agreements with respect to our subsidiaries' obligations like those for debt service, fuel supply or the delivery of power, and have entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We may incur additional guaranty, indemnification, and reimbursement obligations, as well as obligations to make equity and other contributions to projects in the future.
MARKET RISK EXPOSURES
Our 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 in part by using derivative financial instruments in accordance with established policies and procedures.
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 $16.1 million, $25.2 million and $22.8 million for the years 2000, 1999 and 1998, respectively, as a result of interest rate hedging mechanisms. We have entered into several interest rate swap agreements under which the maturity date of the swaps occurs prior to the final maturity of the underlying debt. A 10% increase in market interest rates at December 31, 2000 would result in a $17.2 million increase in the fair value of our interest rate hedge agreements. A 10% decrease in market interest rates at December 31, 2000 would result in a $17.1 million decline in the fair value of our interest rate hedge agreements.
We had short-term obligations of $883.4 million consisting of commercial paper and bank borrowings at December 31, 2000. The fair values of these obligations approximated their carrying values at December 31, 2000, and would not have been materially affected by changes in market interest rates. The fair market value of long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of our total long-term obligations (including current portion) was $6,999.8 million at December 31, 2000. A 10% increase in market interest rates at December 31, 2000
would result in a decrease in the fair value of total long-term obligations by approximately $96 million. A 10% decrease in market interest rates at December 31, 2000 would result in an increase in the fair value of total long-term obligations by approximately $104 million.
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 things, address credit risk. When making sales under negotiated bilateral contracts, it is our policy to deal with investment grade counterparties or counterparties that provide equivalent credit support. Exceptions to the policy are granted only after thorough review and scrutiny by Edison Mission Energy's Risk Management Committee. Most entities that have received exceptions are organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants, whose output is not committed to be sold under long-term contracts, in order to lock in desirable outcomes. When appropriate, we manage the spread between electric prices and fuel prices, and use forward contracts, swaps, futures, or options contracts to achieve those objectives.
Our electric revenues were increased by $47.5 million, $60.9 million and $108.4 million in 2000, 1999 and 1998, respectively, as a result of electricity rate swap agreements and other hedging mechanisms. A 10% increase in pool prices would result in a $130.8 million decrease in the fair market value of electricity rate swap agreements. A 10% decrease in pool prices would result in a $130.5 million increase in the fair market value of electricity rate swap agreements. An electricity rate swap agreement is an exchange of a fixed price of electricity for a floating price. As a seller of power, we receive the fixed price in exchange for a floating price, like the index price associated with electricity pools. A 10% increase in electricity prices at December 31, 2000 would result in a $1.8 million decrease in the fair market value of forward contracts entered into by the Loy Yang B plant. A 10% decrease in electricity prices at December 31, 2000 would result in a $1.8 million increase in the fair market value of forward contracts entered into by Loy Yang B plant.
A 10% increase in fuel oil, natural gas and electricity forward prices at December 31, 2000 would result in a $15.7 million decrease in the fair market value of energy contracts utilized by our domestic trading operations in energy trading and price risk management activities. A 10% decrease in fuel oil, natural gas and electricity forward prices at December 31, 2000 would result in a $15.7 million increase in the fair market value of energy contracts utilized by our domestic trading operations in energy trading and price risk management activities.
AMERICAS
On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. Our energy trading and price risk management activities give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. Market risks are actively monitored to ensure compliance with the risk management policies of Edison Mission Energy. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the reasons for the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, we supplement this approach with industry "best
practice" techniques including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.
Electric power generated at the Homer City plant is sold under bilateral arrangements with domestic utilities and power marketers under short-term contracts with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets, which establish an hourly clearing price. The Homer City plant is situated in the PJM control area and is physically connected to high-voltage transmission lines serving both the PJM and NYISO markets. The Homer City plant can also transmit power to the midwestern United States.
Electric power generated at the Illinois Plants is sold under power purchase agreements with Exelon Generation Company, in which Exelon Generation Company purchases capacity and has the right to purchase energy generated by the Illinois Plants. The agreements, which began on December 15, 1999 and have a term of up to five years, provide for Exelon Generation Company to make capacity payments for the plants under contract and energy payments for the electricity produced by these plants and taken by Exelon Generation Company. The capacity payments provide the Illinois Plants revenue for fixed charges, and the energy payments compensate the Illinois Plants for variable costs of production. If Exelon Generation Company does not fully dispatch the plants under contract, the Illinois Plants may sell, subject to specified conditions, the excess energy at market prices to neighboring utilities, municipalities, third party electric retailers, large consumers and power marketers on a spot basis. A bilateral trading infrastructure already exists with access to the Mid-America Interconnected Network and the East Central Area Reliability Council.
UNITED KINGDOM
Our plants in the U.K. currently 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. This system has been in place since 1989 but is due to be replaced on March 27, 2001 with a bilateral physical trading system referred to as the new electricity trading arrangements.
The new electricity trading arrangements are the direct result of an October 1997 request by the Minister for Science, Energy and Industry who asked the U.K. Director General of Electricity Supply to review the operation of the pool pricing system. In July 1998 the Director General proposed 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 U.K. Government accepted the proposals in October 1998 subject to reservations. Following this, further proposals were published by the Government and the Director General in July and October 1999. The proposals include, among other things, the establishment of a spot market or voluntary short-term power exchanges operating from 24 to 3 1/2-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 strong incentives for being in balance; and a Balancing and Settlement Code Panel to oversee governance of the balancing mechanism. Contracting over time periods longer than the day-ahead market are not directly affected by the proposals. Physical bilateral contracts will replace the current contracts for differences, but will function in a similar manner. However, it remains difficult to evaluate the future impact of the proposals. A key feature of the new electricity trading arrangements is to require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery, against their contracted positions or face assessment of energy imbalance penalty charges by the system operator. A consequence of this should be to increase greatly the motivation of parties to contract in advance and develop forwards and futures markets of greater liquidity than at present. Recent experience has been that the new electricity trading arrangements have placed a significant downward pressure on forward contract prices. Furthermore, another consequence may be that counterparties may require additional credit support, including parent company guarantees or letters of credit. Legislation in the form of the Utilities Act, which was
approved July 28, 2000, allows for the implementation of new electricity trading arrangements and the necessary amendments to generators' licenses. Various key documents were designated by the Secretary of State and signed by participants on August 14, 2000 (the Go-Active Date); however, due to difficulties encountered during testing, implementation of the new electricity trading arrangements has been delayed from November 21, 2000 until March 27, 2001.
The Utilities Act sets a principal objective for the Government and the Director General to "protect the interests of consumers.... where appropriate by promoting competition....". This represents a shift in emphasis toward the consumer interest. But this is qualified by a recognition that license holders should be able to finance their activities. The Act also contains new powers for the Government to issue guidance to the Director General on social and environmental matters, changes to the procedures for modifying licenses and a new power for the Director General to impose financial penalties on companies for breach of license conditions. We will be monitoring the operation of these new provisions. See "--Financing Plans."
ASIA PACIFIC
AUSTRALIA. The Loy Yang B plant sells its electrical energy through a centralized electricity pool, which provides for a system of generator bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day. The National Electricity Market Management Company, operator and administrator of the pool, determines a system marginal price each half-hour. To mitigate exposure to price volatility of the electricity traded into the pool, the Loy Yang B plant has entered into a number of financial hedges. From May 8, 1997 to December 31, 2000, approximately 53% to 64% of the plant output sold was hedged under vesting contracts, with the remainder of the plant capacity hedged under the State Hedge described below. Vesting contracts were put into place by the State Government of Victoria, Australia, between each generator and each distributor, prior to the privatization of electric power distributors in order to provide more predictable pricing for those electricity customers that were unable to choose their electricity retailer. Vesting contracts set base strike prices at which the electricity will be traded. The parties to the vesting contracts make payments, which are calculated based on the difference between the price in the contract and the half-hourly pool clearing price for the element of power under contract. Vesting contracts were sold in various structures and accounted for as electricity rate swap agreements. The State Hedge agreement with the State Electricity Commission of Victoria is a long-term contractual arrangement based upon a fixed price commencing May 8, 1997 and terminating October 31, 2016. The State Government of Victoria, Australia guarantees the State Electricity Commission of Victoria's obligations under the State Hedge. From January 2001 to July 2014, approximately 77% of the plant output sold is hedged under the State Hedge. From August 2014 to October 2016, approximately 56% of the plant output sold is hedged under the State Hedge. Additionally, the Loy Yang B plant entered into a number of fixed forward electricity contracts commencing January 1, 2001, which expire either on January 1, 2002 or January 1, 2003, and which will further mitigate against the price volatility of the electricity pool.
NEW ZEALAND. The New Zealand Government has been undergoing a steady process of electric industry deregulation since 1987. Reform in the distribution and retail supply sector began in 1992 with legislation that deregulated electricity distribution and provided for competition in the retail electric supply function. The New Zealand Energy Market, established in 1996, is a voluntary competitive wholesale market 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 commissioned an inquiry into the electricity industry in February 2000. This Inquiry Board's report was presented to the government in mid 2000. The main
focus of the report was on the monopoly segments of the industry, transmission and distribution, with substantial limitations being recommended in the way in which these segments price their services in order to limit their monopoly power. Recommendations were also made with respect to the retail customer in order to reduce barriers to customers switching. In addition, the Board made recommendations in relation to the wholesale market's governance arrangements with the purpose of streamlining them. The recommended changes are now being progressively implemented.
FOREIGN EXCHANGE RATE RISK
Fluctuations in foreign currency exchange rates can affect, on a United States dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. As we continue to expand into foreign markets, fluctuations in foreign currency exchange rates can be expected to have a greater impact on our results of operations in the future. At times, we have hedged a portion of our current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to United States dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, we have used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We cannot assure you, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or forecasted relationships. Foreign exchange considerations for three major international projects, other than Paiton which was discussed earlier, are discussed below.
The First Hydro, Ferrybridge and Fiddler's Ferry plants in the U.K. and the Loy Yang B plant in Australia have been financed in their local currency, pounds sterling and Australian dollars, respectively, thus hedging the majority of their acquisition costs against foreign exchange fluctuations. Furthermore, we have evaluated the return on the remaining equity portion of these investments with regard to the likelihood of various foreign exchange scenarios. These analyses use market derived volatilities, statistical correlations between specified variables, and long-term forecasts to predict ranges of expected returns.
Foreign currencies in the U.K., Australia and New Zealand decreased in value compared to the U.S. dollar by 7%, 15% and 15%, respectively (determined by the change in the exchange rates from December 31, 1999 to December 31, 2000). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $157.3 million during 2000. A 10% increase or decrease in the exchange rate at December 31, 2000 would result in foreign currency translation gains or losses of $196.7 million.
In December 2000, we entered into foreign currency forward exchange contracts in the ordinary course of business to protect ourselves from adverse currency rate fluctuations on anticipated foreign currency commitments with varying maturities ranging from January 2001 to July 2002. The periods of the forward exchange contracts correspond to the periods of the hedged transactions. At December 31, 2000, the outstanding notional amount of the contracts totaled $91 million, consisting of contracts to exchange U.S. dollars to pound sterling. A 10% fluctuation in exchange rates would change the fair value of the contracts at December 31, 2000 by approximately $6 million.
We will continue to monitor our foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future.
OTHER
The electric power generated by some of our investments in domestic operating projects, excluding the Homer City plant and the Illinois Plants, is sold to electric utilities under long-term contracts, typically with terms of 15 to 30-years. We structure our long-term contracts so that fluctuations in fuel
costs will produce similar fluctuations in electric and/or steam revenues and enter into long-term fuel supply and transportation agreements. The degree of linkage between these revenues and expenses varies from project to project, but generally permits the projects to operate profitably under a wide array of potential price fluctuation scenarios.
ENVIRONMENTAL MATTERS AND 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 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. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings which may be taken by environmental authorities, could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. We cannot assure you that we would be able to recover these increased costs from our customers or that our financial position and results of operations would not be materially adversely affected.
Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures.
We expect that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in increased capital expenditures and operating expenses. For example, we expect to spend approximately $67 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 anticipate upgrades to the environmental controls at the Illinois Plants to control nitrogen oxide emissions to result in expenditures of approximately $61 million, $67 million, $130 million, $123 million and $57 million for 2001, 2002, 2003, 2004 and 2005, 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 anticipate environmental costs arising from plant modification of approximately $52 million for the 2001-2005 period.
We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoElectrica a notice of violation and a compliance order alleging violations of the federal Clean Air Act primarily related to start-up activities. Representatives of EcoElectrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoElectrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action will be taken by the Environmental Protection Agency.
On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act's "new source review" requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states have joined these lawsuits. In addition, the United States Environmental Protection Agency has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power plants. The Environmental Protection Agency has also issued requests for information pursuant to the
Clean Air Act to numerous other electric utilities seeking to determine whether these utilities also engaged in activities that may have been in violation of the Clean Air Act's new source review requirements.
To date, one utility, the Tampa Electric Company, has reached a formal agreement with the United States to resolve alleged new source review violations. Two other utilities, the Virginia Electric & Power Company and Cinergy Corp., have reached agreements in principle with the Environmental Protection Agency. In each case, the settling party has agreed to incur over $1 billion in expenditures over several years for the installation of additional pollution control, the retirement or repowering of coal fired generating units, supplemental environmental projects and civil penalties. These agreements provide for a phased approach to achieving required emission reductions over the next 10-15 years. The settling utilities have also agreed to pay civil penalties ranging from $3.5 million to $8.5 million.
Prior to our purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. Other than with respect to the Homer City plant, no proceedings have been initiated or requests for information issued with respect to any of our United States facilities. However, we have been in informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. We cannot assure you that we will reach a satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the proceedings, we could be required to invest in additional pollution control requirements, over and above the upgrades we are planning to install, and could be subject to fines and penalties.
A new ambient air quality standard was adopted by the Environmental Protection Agency in July 1997 to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate matter standard may require reductions in nitrogen oxides and sulfur dioxides, although under the time schedule announced by the Environmental Protection Agency when the new standard was adopted, non-attainment areas were not to have been designated until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999, the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards, as interpreted by the Environmental Protection Agency, was an unconstitutional delegation of legislative power. The Court of Appeals remanded both the fine particulate matter standard and the revised ozone standard to allow the EPA to determine whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard on our facilities is uncertain at this time.
On December 20, 2000, the Environmental Protection Agency issued a regulatory finding that it is "necessary and appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants. The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean Air Act for which "maximum available control technology" standards will be developed. Eventually, unless overturned or reconsidered, the Environmental Protection Agency will issue technology-based standards that will apply to every coal-fired unit owned by us or our affiliates in the United States. This section of the Clean Air Act provides only for technology-based standards, and does not permit market trading options. Until the standards are actually promulgated, the potential cost of these control technologies cannot be estimated, and we cannot evaluate the potential impact on the operations of our facilities.
Since the adoption of the United Nations Framework on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions. In December 1997, the Clinton
Administration participated in the Kyoto, Japan negotiations, where the basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7% from 1990 levels. However, because of opposition to the treaty in the United States Senate, the Kyoto Protocol has not been submitted to the Senate for ratification. Although legislative developments at the federal and state level related to controlling greenhouse gas emissions are beginning, we are not aware of any state legislative developments in the states in which we operate. If the United States ratifies the Kyoto Protocol or we otherwise become subject to limitations on emissions of carbon dioxide from our plants, these requirements could have a significant impact on our operations.
The Comprehensive Environmental Response, Compensation, and Liability Act, which is also known as CERCLA, and similar state statutes, require the cleanup of sites from which there has been a release or threatened release of hazardous substances. We are unaware of any material liabilities under this act; however, we can not assure you that we will not incur CERCLA liability or similar state law liability in the future.
NEW ACCOUNTING STANDARDS
Effective January 1, 2001, Edison Mission Energy adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." 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. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.
Effective January 1, 2001, we will record all derivatives at fair value unless the derivatives qualify for the normal sales and purchases exception. We expect that the portion of our business activities related to physical sales and purchases of power or fuel and those similar business activities of our affiliates will qualify for this exception. We expect the majority of our risk management activities will qualify for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income. In the United Kingdom, we expect that the majority of our activities related to the Fiddler's Ferry, Ferrybridge and First Hydro power plants will not qualify for either the normal purchases and sales exception or as cash flow hedges. Accordingly, we expect the majority of these contracts will be recorded at fair value, with subsequent changes in fair value recorded through the income statement.
As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under our prior accounting policy. The cumulative effect on prior years' net income resulting from the change in accounting for derivatives in accordance with SFAS No. 133 is expected to be less than $10 million, net of tax.
RECENT DEVELOPMENTS
In February 2001, we completed the acquisition of a 50% interest in CBK Power Co. Ltd. in exchange for $20 million. CBK Power has entered into a 25-year build-rehabilitate-transfer-and-operate agreement with National Power Corporation related to the 726 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project has been completed with equity contributions of $117 million (our 50% share is $58.5 million) required to be made upon completion of the rehabilitation and expansion, currently scheduled for 2003, and debt financing has been arranged for the remainder of the cost for this project.
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
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, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index of financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Arthur Andersen LLP
Orange County, California March 28, 2001
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. GENERAL
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 or leasing and operating electric power generation facilities worldwide. We also conduct energy trading and price risk management activities in power markets open to competition.
CALIFORNIA POWER CRISIS
Edison International, our ultimate parent company, is a holding company. Edison International is also the corporate parent of Southern California Edison Company, an electric utility that buys and sells power in California. In the past year, various market conditions and other factors have resulted in higher wholesale power prices to California utilities. At the same time, two of the three major utilities, Southern California Edison and Pacific Gas and Electric Co., have operated under a retail rate freeze. As a result, there has been a significant under recovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies has failed to make payments due to power suppliers and others. Given these and other payment defaults, creditors of Southern California Edison and Pacific Gas and Electric could file involuntary bankruptcy petitions against these companies. Other results of the under recoveries could include an end to the rate freeze and significant retail rate increases. A number of federal and state, legislative and regulatory initiatives addressing the issues of the California electric power industry have been proposed, including wholesale rate caps, retail rate increases, acceleration of power plant permitting and state entry into the power market. Many of these activities are ongoing. These activities may result in a restructuring of the California power market. At this time, these activities are in their preliminary stages, and it is not possible to estimate their likely ultimate outcome For more information on how the current California power crisis affects our investments, see "--Note 13. Commitments and Contingencies--Other Commitments and Contingencies--California Power Crisis."
Southern California Edison's current financial condition has had, and may continue to have, an adverse impact on Edison International's credit quality and, as previously reported by Edison International, has resulted in cross-defaults under Edison International's credit facilities. Both Standard & Poor's Ratings Services and Moody's Investors Service, Inc. have lowered the credit ratings of Edison International and Southern California Edison to substantially below investment grade levels. The credit ratings remain under review for potential downgrade by both Standard & Poor's and Moody's.
To isolate ourselves from the credit downgrades and potential bankruptcies of Edison International and Southern California Edison, and to facilitate our ability and the ability of our subsidiaries to maintain their respective investment grade credit ratings, on January 17, 2001, we amended our articles of incorporation and our bylaws to include so-called "ring-fencing" provisions. These ring-fencing provisions are intended to preserve us as a stand-alone investment grade rated entity despite the current credit difficulties of Edison International and Southern California Edison. These provisions
require the unanimous approval of our board of directors, including at least one independent director, before we can do any of the following:
- declare or pay dividends or distributions unless:
- we then have an investment grade credit rating and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or
- the dividends do not exceed $32.5 million in any fiscal quarter and we meet an interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters. We currently meet this interest coverage ratio;
- institute or consent to bankruptcy, insolvency or similar proceedings or actions; or
- consolidate or merge with any entity or transfer substantially all our assets to any entity, except to an entity that is subject to similar restrictions.
We cannot assure you that these measures will effectively isolate us from the credit downgrades or the potential bankruptcies of Edison International and Southern California Edison. In January 2001, Standard & Poor's and Moody's lowered our credit ratings. Our senior unsecured credit ratings were downgraded to "BBB-" from "A-" by Standard & Poor's and to "Baa3" from "Baa1" by Moody's. Our credit ratings remain investment grade. Both Standard & Poor's and Moody's have indicated that the credit ratings outlook for us is stable. A downgrade in our credit ratings below investment grade could increase our cost of capital, increase our credit support obligations, make efforts to raise capital more difficult and could have an adverse impact on us and our subsidiaries.
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.
CASH EQUIVALENTS
Cash equivalents include time deposits and other investments totaling $555.7 million at December 31, 2000, with maturities of three months or less. All investments are classified as available-for-sale.
INVESTMENTS
Investments in energy projects and oil and gas investments 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, 2000 and 1999. 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.
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 the emission allowances in the normal course of our business to generate electricity. Accordingly, we have classified emission allowances expected to be used by us to generate power as part of property, plant and equipment. Acquired emission allowances 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 excess of the fair value of net assets acquired in a purchase transaction. The amounts are being amortized on a straight-line basis over periods ranging from 20 to 40 years. Accumulated amortization was $38.8 million and $33.2 million at December 31, 2000 and 1999, 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 10.
MAINTENANCE ACCRUALS
Certain of our plant facilities' major pieces of equipment require major maintenance on a periodic basis. These costs are expensed as incurred. Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). The accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the Securities and Exchange Commission issued a letter to the Accounting Standards Executive Committee, stating its position that the Securities and Exchange Commission staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance costs. The Accounting Standards Executive Committee agreed to add accounting for major maintenance costs as part of an existing project and to issue authoritative guidance by August 2001. Due to the position taken by the Securities and Exchange Commission staff, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. Such change in accounting policy is considered preferable based on the recent guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we have recorded $17.7 million, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000. Pro forma data have not been provided for prior periods, as the impact would not be material.
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 of these costs amounted to $30.4 million in 2000 and $9.7 million in 1999.
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. Revenues are adjusted for price differentials resulting from electricity rate swap agreements in the United States, United Kingdom and Australia. These rate swap agreements are discussed further in Note 7.
DERIVATIVE 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. If a derivative financial instrument contract is terminated because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized. If a derivative financial instrument contract is terminated for other economic reasons, any gain or loss as of the termination date is deferred and recorded concurrently with the related energy purchase or sale. Mark-to-market accounting would be used if the hedge accounting criteria were not met.
Derivative financial instruments that are utilized for trading purposes are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Under this method, forwards, futures, options, swaps and other financial instruments with third parties are reflected at market value and are included in the balance sheet as assets or liabilities from energy trading activities. In the absence of quoted value, financial instruments are valued at fair value, considering time value, volatility of the underlying commodity, and other factors as determined by Edison Mission Energy. Resulting gains and losses are recognized in net gains (losses) from energy trading and price risk management in the accompanying Consolidated Income Statements in the period of change. Assets from energy trading and price risk management activities include the fair value of open financial positions related to trading activities and the present value of net amounts receivable from structured transactions. Liabilities from energy trading and price risk management activities include the fair value of open financial positions related to trading activities of open financial positions related to trading activities and the present value of net amounts payable from structured transactions.
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 from translation of foreign currency financial statements are included in comprehensive income in shareholder's equity. Gains or losses resulting from foreign currency transactions are normally included in other income in the consolidated statements of income. Foreign currency transaction gains/(losses) amounted to $12.8 million, ($1.7) million and ($1.2) million for 2000, 1999 and 1998, respectively.
STOCK-BASED COMPENSATION
We measure compensation expense relative to stock-based compensation by the intrinsic-value method.
NEW ACCOUNTING STANDARD
Effective January 1, 2001, Edison Mission Energy adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." 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. For derivatives that qualify for hedge accounting, depending on the nature of the hedge, changes in fair value are either offset by changes in the fair value of the hedged assets, liabilities or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value is immediately recognized in earnings.
Effective January 1, 2001, we will record all derivatives at fair value unless the derivatives qualify for the normal sales and purchases exception. We expect that the portion of our business activities related to physical sales and purchases of power or fuel and those similar business activities of our affiliates will qualify for this exception. We expect the majority of our risk management activities will qualify for treatment under SFAS No. 133 as cash flow hedges with appropriate adjustments made to other comprehensive income. In the United Kingdom, we expect that the majority of our activities related to the Fiddler's Ferry, Ferrybridge and First Hydro power plants will not qualify for either the normal purchases and sales exception or as cash flow hedges. Accordingly, we expect the majority of these contracts will be recorded at fair value, with subsequent changes in fair value recorded through the income statement.
As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under our prior accounting policy. The cumulative effect on prior years' net income resulting from the change in accounting for derivatives in accordance with SFAS No. 133 is expected to be less than $10 million, net of tax.
NOTE 3. INVENTORY
Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2000 and December 31, 1999 consisted of the following:
NOTE 4. ACQUISITIONS
ACQUISITION OF SUNRISE PROJECT
On November 17, 2000, we completed a transaction with Texaco Inc. to purchase a proposed 560 MW gas fired combined cycle project to be located in Kern County, California, referred to as the Sunrise Project. The acquisition included all rights, title and interest held by Texaco in the Sunrise Project, except that Texaco has an option to repurchase a 50% interest in the project prior to its commercial operation. As part of this transaction, we also: (i) acquired from Texaco an option to purchase two gas turbines which we plan to utilize in the project, (ii) provided Texaco an option to purchase two of the turbines available to us under the Edison Mission Energy Master Turbine Lease and (iii) granted Texaco an option to acquire a 50% interest in 1000 MW of future power plant projects we designate. For more information on the Edison Mission Energy Master Turbine Lease, see "Note 14. Lease Commitments--Edison Mission Energy Master Turbine Lease." The Sunrise Project consists of two phases with Phase I, construction of a single-cycle gas fired facility (320 MW), currently scheduled to be completed in August 2001, and Phase II, conversion to a combined-cycle gas fired facility (560 MW), currently scheduled to be completed in June 2003. In December 2000, we received the Energy Commission Certification and a permit to construct the Sunrise Plant, which allowed us to commence construction of Phase I. We are negotiating with the California Department of Water Resources the detailed terms and conditions of a long-term cost-based-type rate power purchase agreement. We cannot assure you that we will be successful in reaching a final agreement.
The total purchase price of the Sunrise Project was $27 million. We funded the purchase with cash. The total estimated construction cost of this project is approximately $400 million. As of December 31, 2000, we had also spent $17.8 million on construction costs for the Sunrise Project.
ACQUISITION OF TRADING OPERATIONS OF CITIZENS POWER LLC
On September 1, 2000, we completed a transaction with P&L Coal Holdings Corporation and Gold Fields Mining Corporation (Peabody) to acquire the trading operations of Citizens Power LLC and a minority interest in structured transaction investments relating to long-term power purchase agreements. The purchase price of $44.9 million was based on the sum of: (a) fair market value of the trading portfolio and the structured transaction investments at the date of the acquisition and (b) $25 million. The acquisition was funded with cash. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. By the end of the third quarter of 2000, the Citizens trading operations were merged into our own marketing operations under Edison Mission Marketing & Trading, Inc.
ACQUISITION OF INTEREST IN ITALIAN WIND
On March 15, 2000, we completed a transaction with UPC International Partnership CV II to acquire Edison Mission Wind Power Italy B.V., formerly known as Italian Vento Power Corporation Energy 5 B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy. All the projects use wind to generate electricity from turbines which is sold under fixed-price, long-term tariffs. Assuming all projects under development are completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW. The total purchase price is 90 billion Italian Lira (approximately $44 million at December 31, 2000), with equity contribution obligations of up to 33 billion Italian Lira (approximately $16 million at December 31, 2000), depending on the number of projects that are ultimately developed. As of December 31, 2000, our payments in respect of these projects included $27 million toward the purchase price and $13 million in equity contributions.
ACQUISITION OF ILLINOIS PLANTS
On December 15, 1999, we completed a transaction with Commonwealth Edison, a subsidiary of Exelon Corporation, to acquire Commonwealth Edison's fossil-fuel power generating plants located in Illinois, which are collectively referred to as the Illinois Plants. These plants 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 terms of up to five years, pursuant to which Commonwealth Edison purchases capacity and has the right to purchase energy generated by the plants. Subsequently, Commonwealth Edison assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, LLC.
Concurrently with the acquisition of the Illinois Plants, we assigned our right to purchase the Collins Station, a 2,698 MW gas and oil-fired generating station located in Illinois, to third party lessors. After this assignment, we entered into leases of the Collins Station with terms of 33.75 years. The aggregate megawatts either purchased or leased as a result of these transactions with Commonwealth Edison Company and the third party lessors is 9,539 MW.
Consideration for the Illinois Plants, excluding $860 million paid by the third party lessors to acquire the Collins Station, consisted of a cash payment of approximately $4.1 billion. The acquisition was funded primarily with a combination of approximately $1.6 billion of non-recourse debt secured by a pledge of the stock of specified subsidiaries, $1.3 billion of Edison Mission Energy's debt and $1.2 billion in equity contributions to us from Edison International.
ACQUISITION OF FERRYBRIDGE AND FIDDLER'S FERRY PLANTS
On July 19, 1999, we completed a transaction with PowerGen UK plc to acquire the Ferrybridge and Fiddler's Ferry coal fired electric generating plants located in the U.K.. Ferrybridge, located in West Yorkshire, and Fiddler's Ferry, located in Warrington, each has a generating capacity of approximately 2,000 MW.
Consideration for the purchase of the Ferrybridge and Fiddler's Ferry plants by our indirect subsidiary, Edison First Power, consisted of an aggregate of approximately $2.0 billion (L1.3 billion sterling at the time of the acquisition) for the two plants. The acquisition was funded primarily with a combination of net proceeds of L1.15 billion from the Edison First Power Limited Guaranteed Secured Variable Rate Bonds due 2019, a $500 million equity contribution to us from Edison International and cash. The Edison First Power Bonds were issued to a special purpose entity formed by Merrill Lynch International. Merrill Lynch International sold the variable rate coupons portion of the bonds to a special purpose entity that borrowed $1.3 billion (830 million pounds sterling at the time of the acquisition) 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 an overseas public offering resulting in widespread ownership among the citizens of New Zealand and offshore investors. These shares are publicly traded on stock exchanges in New Zealand and Australia. During 2000, we increased our share of ownership in Contact Energy to 42%. 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 2,449 MW.
Consideration for Contact Energy consisted of a cash payment of approximately $635 million (1.2 billion New Zealand dollars at the time of the acquisition), which was financed by $120 million of preferred securities, a $214 million (400 million New Zealand dollars at the time of the acquisition)
credit facility, a $300 million equity contribution to us from Edison International and cash. The credit facility was subsequently paid off with proceeds from the issuance of additional preferred securities.
ACQUISITION OF HOMER CITY PLANT
On March 18, 1999, we completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and their respective affiliates to acquire the 1,884 MW Homer City Electric Generating Station. This facility is a coal fired plant in the mid-Atlantic region of the United States and has direct, high voltage interconnections to both the New York Independent System Operator, which controls the transmission grid and energy and capacity markets for New York State and is commonly known as the NYISO, and the Pennsylvania-New Jersey-Maryland Power Pool, which is commonly known as the PJM.
Consideration for the Homer City plant consisted of a cash payment of approximately $1.8 billion, which was partially financed by $1.5 billion of new loans, combined with our revolver borrowings and cash.
ACQUISITION OF INTEREST IN ECOELECTRICA
In December 1998, we acquired 50% of the 540 MW EcoElectrica liquefied natural gas combined-cycle cogeneration facility under construction in Penuelas, Puerto Rico for approximately $243 million. The project also includes a desalination plant and liquefied natural gas storage and vaporization facilities. Commercial operation commenced March 2000.
ACCOUNTING TREATMENT OF ACQUISITIONS
Each of the acquisitions described above has been accounted for utilizing the purchase method. The purchase price was allocated to the assets acquired and liabilities assumed based on their respective fair market values. Amounts in excess of the fair value of the net assets acquired have been assigned to goodwill. Our consolidated statement of income reflects the operations of Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, EcoElectrica beginning March 1, 2000, the Homer City plant beginning March 18, 1999, Contact Energy beginning May 1, 1999, the Ferrybridge and Fiddler's Ferry plants beginning July 19, 1999, and the Illinois Plants beginning December 15, 1999.
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. 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 and 1998 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. Pro forma financial information is not
presented for the acquisition of trading operations of Citizens Power LLC as the effect of this acquisition was not material to our results of operations or financial position.
The table below summarizes additional acquisitions by Edison Mission Energy or its wholly-owned subsidiaries from 1998 through 2000.
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 $479 million at December 31, 2000. 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, 2000 consist of the following: a $107.8 million, 10% interest loan, due on demand; a $26.3 million, 5% interest promissory note, interest payable semiannually, due April 2008; and a $31.6 million, 12% interest loan, due on demand.
The undistributed earnings of investments accounted for by the equity method were $270.7 million in 2000 and $223.9 million in 1999.
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, 2000, 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.
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(1) Investment is translated into U.S. dollars at the year-end exchange rate.
At December 31, 2000, the quoted market value of our investment in Contact Energy was $288.2 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. We expect to recover our investment in Contact Energy based on future cash flows forecasted to be generated from the project.
INVESTMENTS IN OIL AND GAS
At December 31, 2000, we had one 35.84%-owned (with 34.54% 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 $10.8 million at December 31, 2000. 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 the sale of 31.5% of our 50.1% interest in Four Star Oil & Gas for $34.2 million in cash and 50% interest in the acquirer, Four Star Holdings. Four Star Holdings financed the purchase of the interest in Four Star Oil & Gas from $27.5 million in loans from affiliates, including $13.7 million from us, and $13.7 million from cash on hand. Upon completion of the sale, we continue to own an 18.6% direct interest in Four Star Oil & Gas and an indirect interest of 15.75% which is held through Four Star Holdings. As a result of this transaction, our total interest in Four Star Oil & Gas has decreased from 50.1% to 34.35%. Cash proceeds from the sale were $34.2 million ($20.5 million net of the loan to Four Star Holdings). The gain on the sale of the 31.5% interest in Four Star Oil & Gas was $11.5 million of which we deferred 50%, or $5.6 million, due to our equity interest in Four Star Holdings. The after-tax gain on the sale was approximately $30 million.
NOTE 6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following:
In connection with the Homer City, Loy Yang B, First Hydro, Doga and Iberian Hy-Power plant financings, 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 senior credit facility due May 2001 of which $444.2 million was outstanding at December 31, 2000. The commercial paper facility represents recourse debt and is indexed to LIBOR. Other short-term obligations consist of a borrowing under the $700 million senior credit facility and the $300 million senior credit facility due May 2001 and a 20 million pounds sterling (approximately $30 million at December 31, 2000) bank borrowing of which $283.5 million and $28.7 million were outstanding, respectively, at December 31, 2000. At December 31, 1999, commercial paper consisted of a $700 million facility due March 2000 and a $500 million facility due November 2000, of which $630 million and $500 million was outstanding, respectively.
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, 2000, recourse debt totaled
$1.2 billion and non-recourse project debt totaled $5.9 billion. Long-term obligations consist of the following:
At December 31, 2000, we had available $24.5 million of borrowing capacity and approximately $126.5 million in letters of credit issued under a $500 million revolving credit facility that expires in October 2001.
LONG-TERM OBLIGATIONS--AFFILIATES
During 1997, we declared a dividend of $78 million to The Mission Group which was recorded as a note payable due in June 2007 with interest at LIBOR + 0.275% (6.96% at December 31, 2000). The note was subsequently exchanged for two notes with the same terms and conditions and assigned to other subsidiaries of Edison International.
In January 2000, Edison Capital, a wholly-owned subsidiary of Edison International, provided 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%. On January 17, 2001, the subordinated financing was repaid with interest and, therefore, the obligation is included in current maturities of long-term obligations.
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 consisted 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. The $800 million credit facility has since been repaid as described below. 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 expect to 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, 2000 and 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 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.
To satisfy the requirements under the Edison Mission Holdings Co. bond financing to have a debt service reserve account balance in an amount equal to six months' debt service projected to be due following the payment of a distribution, Edison Mission Energy agreed to guarantee the payment and performance of the obligations of Edison Mission Holdings, in the amount of approximately $35 million, pursuant to a debt service reserve guarantee. In addition, Edison Mission Energy provides a guarantee of Edison Mission Holdings' obligations in the amount of $3 million to the lenders involved in the bank financing. As a result of Edison Mission Energy's downgrade in January 2001, Edison Mission Holdings is in the process of finalizing the arrangement of a letter of credit of approximately $35 million to replace the bond debt service reserve guarantee.
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 830 million pounds sterling (approximately $1.2 billion as of December 31, 2000) 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 359 million pounds sterling (approximately $537 million as of December 31, 2000) Coal and Capex Facility due January 2004 and July 2004, respectively, and a 20 million pounds sterling (approximately $30 million as of December 31, 2000) working capital facility available through September 2019. As of December 31, 2000, $28.7 million was outstanding under the working capital facility.
Edison First Power has defaulted on its financing documents related to the acquisition of the Fiddler's Ferry and Ferrybridge power plants. The financial performance of these plants has not matched our expectations, largely due to lower energy power prices resulting primarily from increased competition, warmer-than-average weather and uncertainty surrounding the new electricity trading arrangements. See "Management's Discussion and Analysis of Results of Operations and Financial Condition--Market Risk Exposures--United Kingdom." As a result, Edison First Power has decided to defer some environmental capital expenditures originally planned to increase plant utilization and therefore is currently in breach of milestone requirements for the implementation of the capital expenditures program set forth in the financing documents relating to the acquisition of these plants. In addition, due to this reduced financial performance, Edison First Power's debt service coverage ratio during 2000 declined below the threshold set forth in the financing documents.
Edison First Power is currently in discussions with the relevant financing parties to revise the required capital expenditure program, to waive (i) the breach of the financial ratio covenant for 2000, (ii) a technical breach of requirements for the provision of information that was delayed due to uncertainty regarding capital expenditures, and (iii) other related technical defaults. Edison First Power is in the process of requesting the necessary waivers and consents to amendments from the financing parties. We cannot assure you that these waivers and consents to amendments will be forthcoming. The financing documents stipulate that a breach of the financial ratio covenant constitutes an immediate event of default and, if the event of default is not waived, the financing parties are entitled to enforce their security over Edison First Power's assets, including the Fiddler's Ferry and Ferrybridge plants. Despite the breaches under the financing documents, Edison First Power's debt service coverage ratio
for 2000 exceeded 1:1. Due to the timing of its cash flows and debt service payments, Edison First Power utilized L37 million from its debt service reserve to meet its debt service requirements in 2000.
In accordance with SFAS No. 121, "ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED", we have evaluated impairment of the Ferrybridge and Fiddler's Ferry power plants. The undiscounted projected cash flow from these power plants exceeds the net book value at December 31, 2000, and, accordingly, no impairment of these power plants is permitted under SFAS No. 121. As a result of the change in the prices of power in the U.K., we are considering the sale of Ferrybridge and Fiddler's Ferry power plants. Management has not made a decision whether or not the sale of these power plants will ultimately occur and, accordingly, these assets are not classified as held for sale. However, if a decision to sell the Ferrybridge and Fiddler's Ferry power plants were made, it is likely that the fair value of the assets would be substantially below their book value at December 31, 2000. Our net investment in our subsidiary that holds the Ferrybridge and Fiddler's Ferry power plants and related debt was $918 million at December 31, 2000.
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 consisted of (1) an $840 million revolving credit facility due 2002, referred to as Tranche A, (2) an $839 million revolving credit facility due 2004, referred to as Tranche B, and (3) a $150 million of borrowing capacity available under a working capital revolving facility, 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. On December 13, 2000, the commitment amount under Tranche A was increased from $840 million to $911 million, and the commitment amount under Tranche B was decreased from $839 million to $816 million. As of December 31, 2000, the amounts borrowed in 1999 under Tranche A were paid. Under the working capital revolving facility, Tranche C, $6.6 million of borrowing capacity was available at December 31, 2000.
In February 2000, Edison Mission Midwest Holdings Co. issued $1.7 billion of commercial paper under a commercial paper program and repaid a similar amount of outstanding bank borrowings. At December 31, 2000, $803.9 million of commercial paper was outstanding.
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. During the third quarter of 2000, the $500 million floating rate notes and the amount borrowed under the revolving credit facility were repaid.
ANNUAL MATURITIES ON LONG-TERM DEBT
Annual maturities on long-term debt at December 31, 2000, for the next five years, excluding capital leases (see Note 14) are summarized as follows: 2001--$1,767.6 million; 2002--$192.6 million; 2003--$326.5 million; 2004--$1,426.4 million; and 2005--$115 million. The current portion of Roosecote debt is included in long-term debt, as proceeds from future borrowings will exceed the current portion under the terms of the Term Loan and Guarantee Facility at Roosecote.
RESTRICTED CASH
Several 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 $121.0 million at December 31, 2000 and $69.9 million at December 31, 1999. Debt service reserves classified in Restricted cash and other assets (including reserves for interest on annual lease payments) were $75.1 million at December 31, 2000 and $69.7 million at December 31, 1999.
Collateral reserves classified in Restricted cash and other assets were $37.2 million at December 31, 2000 as required by the Edison Mission Energy Turbine Trust agreement entered into on December 4, 2000. This agreement is discussed further in Note 14.
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 of those subsidiaries may not be available to satisfy our obligations or any obligations of our other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of these parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or our affiliates.
FAIR VALUES OF FINANCIAL INSTRUMENTS
The following table summarizes the fair values for outstanding financial instruments used for purposes other than trading by risk category and instrument type:
In assessing the fair value of our financial instruments, both derivative and non-derivative, we use a variety of methods and assumptions that are based on market conditions and risk existing at each balance sheet date. Quoted market prices for the same or similar instruments are used for long-term receivables, interest rate swap/cap agreements, long-term obligations and preferred securities. Foreign currency forward exchange agreements are estimated by obtaining quotes from the bank. 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 (included under commodity price-swaps) 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 price contracts considers quoted marked prices, time value, volatility of the underlying commodities and other factors.
NOTE 8. RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS
Our risk management policy allows for the use of 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 for both trading and non-trading purposes.
COMMODITY PRICE RISK MANAGEMENT
Energy trading and price risk management activities give rise to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored to ensure compliance with the risk management policies of Edison Mission Energy. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. Edison Mission Energy performs a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the drivers of the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, we supplement this approach with industry "best practice" techniques including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.
INTEREST RATE RISK MANAGEMENT
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. 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.
Under the fixed to variable swap agreements, the fixed interest rate payments are at a weighted average rate of 5.65% at December 31, 2000 and 1999. Variable rate payments are based on six month LIBOR capped at 9%. The weighted average LIBOR rate applicable to these agreements was 5.605% and 6.22% at December 31, 2000 and 1999, respectively. Under the variable to fixed swap agreements, we will pay counterparties interest at a weighted average fixed rate of 7.59% and 7.6% at December 31, 2000 and 1999, respectively. Counterparties will pay us interest at a weighted average variable rate of 6.43% and 5.03% at December 31, 2000 and 1999, respectively. The weighted average variable interest rates are based on LIBOR or equivalent interest rate benchmarks for foreign denominated interest rate swap agreements.
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. One of our customers, Exelon Generation Company, accounted for 33% of our revenues during 2000. Any failure by Exelon Generation Company to make payments under the power purchase agreements could adversely affect our results of operations. 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 13. In addition, we enter into contracts
whereby the structure of the contracts minimizes our credit exposure. Accordingly, we, with the exception of our contract with Exelon Generation Company and the power sale contract with our Paiton project, do not anticipate any material impact to our financial position or results of operations as a result of counterparty nonperformance.
The electric power generated by some of our investments in domestic operating projects, excluding the Homer City plant and the Illinois Plants, is sold to electric utilities under long-term, 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.
FOREIGN EXCHANGE RATE RISK
Fluctuations in foreign currency exchange rates can affect, on a United States dollar equivalent basis, the amount of our equity contributions to, and distributions from, our international projects. As we continue to expand into foreign markets, fluctuations in foreign currency exchange rates can be expected to have a greater impact on our results of operations in the future. At times, we have hedged a portion of our current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to United States dollars or other indices reasonably expected to correlate with foreign exchange movements. In addition, we have used statistical forecasting techniques to help assess foreign exchange risk and the probabilities of various outcomes. We cannot assure you, however, that fluctuations in exchange rates will be fully offset by hedges or that currency movements and the relationship between certain macro economic variables will behave in a manner that is consistent with historical or forecasted relationships.
At December 31, 2000, we had outstanding foreign currency forward exchange contracts entered into in the ordinary course of business to protect ourselves from adverse currency rate fluctuations on anticipated foreign currency commitments with varying maturities ranging from January 2001 to July 2002. The periods of the forward exchange contracts correspond to the periods of the hedged transactions.
Edison Mission Energy has the following commodity, interest rate and foreign currency hedges:
ENERGY TRADING
On September 1, 2000, we acquired the trading operations of Citizens Power LLC. As a result of this acquisition, we have expanded our trading operations beyond the traditional marketing of our electric power. Our energy trading and price risk management activities give rise to market risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. Market risks are actively monitored to ensure compliance with the risk management policies of Edison Mission Energy. Policies are in place which limit the amount of total net exposure we may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management. We perform a "value at risk" analysis in our daily business to measure, monitor and control our overall market risk exposure. The use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify the reasons for the risk. Value at risk measures the worst expected loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement tool, we supplement this approach with industry "best practice" techniques including the use of stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.
The fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of December 31, 2000, which include energy commodities, and the average fair value of those instruments held during the period from inception (September 1, 2000) to December 31, 2000 are set forth below:
The approximate gross contract or notional amounts of financial instruments as of December 31, 2000 are as follows:
The net realized and change in unrealized gains or losses arising from trading activities for the period from inception (September 1, 2000) to December 31, 2000 are as follows:
The change in unrealized gain from trading and price risk management activities included in the above amounts was $11.7 million for the period ended December 31, 2000.
NOTE 9. 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 have been redeemed as of December 31, 2000. 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. No securities were redeemed in 2000. 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 consisted 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.
On December 20, 2000, Edison Mission Energy Global Management, Inc. was dissolved and its $120 million of Flexible Money Market Cumulative Preferred Stock was redeemed. The 600 Series A and 600 Series B shares were redeemed at their liquidation preference of $100,000 per share, along with an additional liquidation premium of $3,785 per share, and all unpaid dividends. The redemption of Edison Mission Energy Global Management's preferred shares was funded by return of capital from Edison Mission Energy Taupo Limited. Edison Mission Energy Taupo Limited sold its entire interest in Contact Energy Limited to EME Pacific Holdings, an indirect, wholly-owned subsidiary of Edison Mission Energy, to permit Edison Mission Energy Taupo to make the necessary distribution to Edison Mission Energy Global Management. In connection with the transfer of ownership of Contact, Edison
Mission Energy entered into a further Deed of Covenant in favor of the institutional subscriber of 160 million New Zealand dollars of the preferred stock issued by Edison Mission Energy Taupo in June 1999, discussed below. This further Deed of Covenant required Edison Mission Energy to compensate the institutional preferred stock subscriber in the event that a private binding ruling issued to it by the New Zealand Inland Revenue Department ceases to apply as a direct result of the transfer. The amount of any compensation that may become payable by Edison Mission Energy under the further Deed of Covenant is limited to that necessary to keep the preferred stock subscriber in the same position that it would have been had the private binding ruling continued to apply.
The support agreement between Edison Mission Energy and Edison Mission Energy Global Management, which required Edison Mission Energy to make certain capital contributions to Edison Mission Energy Global Management, was terminated immediately following the dissolution of Edison Mission Energy Global Management and the redemption of the preferred shares as described above.
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.
In connection with the preferred shares issued by Edison Mission Energy Taupo Limited to partially finance the acquisition of the 40% interest in Contact Energy, Edison Mission Energy provided a guaranty of Edison Mission Energy Taupo Limited's obligation to pay a minimum level of non-cumulative dividends on the preferred shares through June 30, 2002, including NZ$12.9 million during 2001 and NZ$4.6 million during the six months ending June 30, 2002. In addition, Edison Mission Energy has agreed to pay amounts required to ensure that Edison Misison Energy Taupo Limited will satisfy two financial ratio covenants on specified dates. The first financial ratio, called a dividends to outgoings ratio, is to be calculated as of June 30, 2002, and is based on historical and projected dividends received from Contact Energy and the dividends payable to preferred shareholders. The second financial ratio, called a debt to valuation ratio, is to be calculated as of May 14, 2001, and is based on the fair value of our Contact Energy shares and the outstanding preferred shares. If, however, Edison Mission Energy's senior unsecured credit rating by Standard & Poor's were downgraded below BBB-, Edison Mission Energy may be called to perform on its guaranty of Edison Mission Energy Taupo Limited's financial covenants before the specified calculation dates. Based on the fair value of our ownership in Contact Energy at March 20, 2001, had Edison Mission Energy been required to perform on its guarantee of the debt to valuation ratio as of that date, Edison Mission Energy's obligation would have been approximately $19 million.
NOTE 10. 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 $281 million and $232 million at December 31, 2000 and 1999, respectively, with $11 million expiring in 2005. Federal capital loss carryforwards total $25 million expiring in 2005. State capital loss carryforwards total $309 million and $107 million at December 31, 2000 and 1999, respectively, with no expiration date. Loss carryforwards total approximately $20 million for Pennsylvania and $63 million for Illinois at December 31, 2000 with various expiration dates.
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 $487 million and $372 million at December 31, 2000 and 1999, respectively. In addition, foreign income taxes have not been provided on unrepatriated foreign earnings from a different foreign jurisdiction in the amount of $151 million and $136 million at December 31, 2000 and 1999, respectively.
The provision (benefit) for income taxes is comprised of the following:
The components of the deferred tax provision, 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 a material adverse effect upon our financial condition or results of operations.
NOTE 11. 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 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 below for 1999. Pension expense recorded by Ferrybridge and Fiddler's Ferry totaled $1.0 million for the period from July 1999 through December 31, 1999. During the first quarter of 2000, Ferrybridge and Fiddler's Ferry employees joined a separate defined benefit pension plan utilized by First Hydro employees. All amounts for the year 2000 are included in the table below.
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.
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% for 2001, gradually decreasing to 5% for 2008 and beyond. Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2000, by $31.4 million and annual aggregate service and interest costs by $3.5 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2000, by $23.7 million and annual aggregate service and interest costs by $2.6 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 $5.3 million in 2000, $2.9 million in 1999 and $0.8 million in 1998.
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 was $114 thousand in 2000 and $12 thousand in 1999.
We also sponsor a defined contribution plan for specified United Kingdom subsidiaries. Annual contributions are based on ten percent of covered employees' salaries. Contribution expense for the subsidiaries totaled approximately $0.5 million, $0.4 million and $0.5 million in 2000, 1999 and 1998, respectively.
NOTE 12. 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. In May 2000, Edison International adopted an additional plan, the 2000 Equity Plan. Under these programs, there are currently outstanding to officers of Edison Mission Energy, options on 3,353,371 shares of Edison International Common Stock of which 2,550,660, 154,695 and 83,000 were granted in 2000, 1999 and 1998, 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. The liability and associated expense is accrued each quarter for the dividend equivalents for each option year. At the end of the performance measurement period, the expense and related liability is adjusted accordingly. Upon exercise, the dividends are paid out and the associated liability is reduced on Edison Mission Energy Consolidated Balance Sheet. The 2000 stock option awards did not include dividend equivalents. Future stock option awards are not expected to include dividend equivalents.
A portion of the executive long-term incentives for 2000 was awarded in the form of performance shares. The performance shares were restructured as retention incentives in December 2000, which will pay as a combination of Edison International common stock and cash if the executive remains employed at the end of the performance period. No special stock options may be exercised before five years have passed unless the stock price appreciates to $25 (based on the average of 20 consecutive trading day closing prices). Performance shares may still be awarded in 2001 and 2002.
All stock options have a 10-year term. Options issued after 1997 generally vest in 25 percent annual installments over a four-year period, although the vesting period for the May 2000 grants does not begin until May 2001. Stock options issued prior to 1998 had a three-year vesting period with one-third of the total award vesting after each of the first three years of the award term. If an option holder retires, dies or is permanently and totally disabled (qualifying event) during the vesting period, the unvested options will vest on a pro rata basis. The performance shares values are accrued ratably over a three-year performance period.
We measure compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock compensation program was $0.7 million for 2000, $0.4 million for 1999 and $0.5 million for 1998.
The weighted-average fair value of options granted during 2000, 1999 and 1998 was $5.63 per share option, $6.45 per share option and $6.33 per share option, respectively. The weighted-average remaining life of options outstanding was 8 years as of December 31, 2000, and 7 years as of December 31, 1999 and 1998.
The fair value for each option granted during 2000, 1999 and 1998, 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 net income of $123.8 million, $131.4 million and $132.3 million in 2000, 1999 and 1998, respectively.
A summary of the status of Edison International's stock options granted to Edison Mission Energy employees is as follows:
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 could be exercised to realize any appreciation in the value of one hypothetical share of Edison Mission Energy stock over its exercise price. Compensation expense was recognized during the period that the employee had the right to receive this appreciation. Exercise prices for our phantom stock were escalated on an annually compounded basis over the grant price by 9%. The value of the phantom stock was recalculated annually as determined by a formula linked to the value of its portfolio of investments less general and administrative costs. The options had 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. For options awarded in 1998 and 1999, one-fourth of the total award vested in each of the first four years of the award term.
Compensation expense recorded with respect to phantom stock options was $4.1 million (before the $60 million adjustment referred to below), $136.3 million and $39 million in 2000, 1999 and 1998, respectively.
In June 2000, the board of directors of Edison International approved an exchange offer to the holders of outstanding phantom options which was subsequently accepted by all holders of these options. The exchange offer was principally for cash, with a portion exchanged for stock equivalent units relating to Edison International common stock. The number of stock equivalent units was determined on the basis of $20.50 per share, and the stock equivalent units accrue and will receive dividend equivalents. Participants were required to elect to cash their vested stock equivalent units on either the first or third anniversary of the exchange offer date (August 2000) for an amount equal to the daily average of Edison International common stock (for 20 trading days preceding the elected payment date). Some participants have elected to defer payment of their cash and stock equivalent units. Since all the outstanding phantom options have been terminated, there will be no future exercises of the phantom options.
Due to the lower valuation of the exchange offer, compared to the values previously accrued, the liability for accrued incentive compensation was reduced by approximately $60 million in the third quarter of 2000.
NOTE 13. COMMITMENTS AND CONTINGENCIES
FIRM COMMITMENT FOR ASSET PURCHASE
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(i) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Purchase payments will continue through 2002, depending on the number of projects that are ultimately developed.
FIRM COMMITMENTS TO CONTRIBUTE PROJECT EQUITY
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(i) The Italian Wind Projects are a series of power projects that are in operation or under development in Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 50% interest. Equity will be contributed depending on the number of projects that are ultimately developed.
Firm commitments to contribute project equity could be accelerated due to certain events of default as defined in the non-recourse project financing facilities. Management does not believe that these events of default will occur to require acceleration of the firm commitments.
CONTINGENT OBLIGATIONS TO CONTRIBUTE PROJECT EQUITY
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(i) Contingent obligations to contribute additional project equity will be based on events principally related to insufficient cash flow to cover interest on project debt and operating expenses, project cost overruns during the plant construction, specified partner obligations or events of default. Our obligation to contribute contingent equity will not exceed $141 million, of which $102 million has been contributed as of December 31, 2000. As of March 16, 2001, $5 million of this amount remains to be funded.
For more information on the Paiton project, see "--Other Commitments and Contingencies--Paiton."
(ii) ISAB is a 512 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. A wholly-owned subsidiary of Edison Mission Energy owns a 49% interest. Commercial operations commenced in April 2000. Contingent obligations to contribute additional equity to the project relate specifically to an agreement to provide equity assurances to the project's lenders depending on the outcome of the contractor claim arbitration.
We are not aware of any other significant contingent obligations or obligations to contribute project equity other than as noted above and equity contributions made by us to meet capital calls by
partnerships who own qualifying facilities that have power purchase agreements with Southern California Edison and Pacific Gas and Electric. See "--California Power Crisis" for further discussion.
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, 2000, if payment were required, would be $256 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.
CALIFORNIA POWER CRISIS
We have partnership interests in eight partnerships which own power plants in California which have power purchase contracts with Pacific Gas and Electric and/or Southern California Edison. Three of these partnerships have a contract with Southern California Edison, four of them have a contract with Pacific Gas and Electric, and one of them has contracts with both. In 2000, our share of earnings before taxes from these partnerships was $168 million, which represented 20% of our operating income. Our investment in these partnerships at December 31, 2000 was $345 million.
As a result of Southern California Edison's and Pacific Gas and Electric's current liquidity crisis, each of these utilities has failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the eight power plants which are owned by partnerships in which we have a partnership interest. Southern California Edison did not pay any of the amounts due to the partnerships in January, February and March of 2001 and may continue to miss future payments. Pacific Gas and Electric made its January payment in full but thus far has paid only a small portion of the amounts due to the partnerships in February and March and may not pay all or a portion of its future payments.
The California utilities' failure to pay has adversely affected the operations of our eight California qualifying facilities. Continuing failures to pay similarly could have an adverse impact on the operations of our California qualifying facilities. Provisions in the partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be taken through the non-affiliated partner in the partnership. Therefore, partnership actions concerning the enforcement of rights under each qualifying facility's power purchase agreement with Southern California Edison in response to Southern California Edison's suspension of payments under that power purchase agreement are to be taken through the non-Edison Mission Energy affiliated partner in the partnership. Some of the partnerships have sought to minimize their exposure to Southern California Edison by reducing deliveries under their power purchase agreements. It is unclear at this time what additional actions, if any, the partnerships will take in regard to the utilities' suspension of payments due to the qualifying facilities. As a result of the utilities' failure to make payments due under these power purchase agreements, the partnerships have called on the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 through March 20, 2001, subsidiaries of ours have made equity contributions totaling approximately $103 million to meet capital calls by the partnerships. Our subsidiaries and the other partners may be required to make additional capital contributions to the partnerships.
Southern California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. Pacific Gas and Electric has taken a different approach and is seeking to invoke force
majeure provisions under its power purchase agreements to excuse its failure to pay. In either case, it is possible that the utilities will not pay all their obligations in full. In addition, it is possible that Southern California Edison and/or Pacific Gas and Electric could be forced into bankruptcy proceedings. If this were to occur, payments to the qualifying facilities, including those owned by partnerships in which we have a partnership interest, could be subject to significant delays associated with the lengthy bankruptcy court process and may not be paid in full. At February 28, 2001, accounts receivable due to these partnerships from Southern California Edison and Pacific Gas & Electric were $437 million; our share of these receivables was $217 million. Furthermore, Southern California Edison's and Pacific Gas and Electric's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court. While we believe that the generation of electricity by the qualifying facilities, including those owned by partnerships in which we have a partnership interest, is needed to meet California's power needs, we cannot assure you either that these partnerships will continue to generate electricity without payment by the purchasing utility, or that the power purchase agreements will not be adversely affected by a bankruptcy or contract renegotiation as a result of the current power crisis.
CREDIT SUPPORT FOR TRADING AND PRICE RISK MANAGEMENT ACTIVITIES
Our trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc., which is currently rated investment grade ("BBB-" by Standard and Poor's). As part of obtaining an investment grade rating for this subsidiary, we have entered into a support agreement, which commits us to contribute up to $300 million in equity to Edison Mission Marketing & Trading, if needed to meet cash requirements. An investment grade rating is an important benchmark used by third parties when deciding whether or not to enter into master contracts and trades with us. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. If Edison Mission Marketing & Trading does not maintain its investment grade rating or if other events adversely affect its financial position, a third party could request Edison Mission Marketing & Trading to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, additional guarantees, collateral, letters of credit or cash. Failure to provide adequate assurance could result in a counterparty liquidating an open position and filing a claim against Edison Mission Marketing & Trading for any losses.
The California power crisis has adversely affected the liquidity of West Coast trading markets, and to a lesser extent, other regions in the United States. Our trading and price risk management activity has been reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. It is not certain that resolution of the California power crisis will occur in 2001 or that, if resolved, we will be able to conduct trading and price risk management activities in a manner that will be favorable to us.
PAITON
The Paiton project is a 1,230 MW coal fired power plant in operation in East Java, Indonesia. Our wholly-owned subsidiary owns a 40% interest and had a $490 million investment in the Paiton project at December 31, 2000. The project's tariff under the power purchase agreement with PT PLN is higher in the early years and steps down over time. The tariff for the Paiton project includes costs relating to infrastructure to be used in common by other units at the Paiton complex. The plant's output is fully contracted with the state-owned electric company, PT PLN. Payments are in Indonesian Rupiah, with the portion of the payments intended to cover non-Rupiah project costs, including returns to investors, adjusted to account for exchange rate fluctuations between the Indonesian Rupiah and the U.S. dollar. The project received substantial finance and insurance support from the Export-Import Bank of the United States, the Japan Bank for International Cooperation, the U.S. Overseas Private Investment
Corporation and the Ministry of Economy, Trade and Industry of Japan. PT PLN'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 PLN might not be able to honor the power purchase agreement with P.T. Paiton Energy, the project company. 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.
In May 1999, Paiton Energy notified PT PLN that the first 615 MW unit of the Paiton project had achieved commercial operation under the terms of the power purchase agreement and, in July 1999, that the second 615 MW unit of the plant had similarly achieved commercial operation. Because of the economic downturn, PT PLN was then experiencing low electricity demand and PT PLN, through February 2000, dispatched the Paiton plant to zero. In addition, PT PLN filed a lawsuit contesting the validity of its agreement to purchase electricity from the project. The lawsuit was withdrawn by PT PLN on January 20, 2000, and in connection with this withdrawal, the parties entered into an interim agreement for the period through December 31, 2000, under which dispatch levels and fixed and energy payment amounts were agreed. As of December 31, 2000, PT PLN had made all fixed payments due under the interim agreement totaling $115 million and all payments due for energy delivered by the plant to PT PLN. As part of the continuing negotiations on a long-term restructuring of the tariff, Paiton Energy and PT PLN agreed in January 2001 on a Phase I Agreement for the period from January 1, 2001 through June 30, 2001. This agreement provides for fixed monthly payments aggregating $108 million over its six month duration and for the payment for energy delivered to PT PLN from the plant during this period. Paiton Energy and PT PLN intend to complete the negotiations of the further phases of a new long-term tariff during the six month duration of the Phase I Agreement. To date, PT PLN has made all fixed and energy payments due under the Phase I Agreement.
Events, including those discussed above, have occurred which may mature into defaults of the project's debt agreements following the passage of time, notice or lapse of waivers granted by the project's lenders. On October 15, 1999, the project entered into an interim agreement with its lenders pursuant to which the lenders waived defaults during the term of the agreement and effectively agreed to defer payments of principal until July 31, 2000. In July, the lenders agreed to extend the term of the lender interim agreement through December 31, 2000. In December 2000, the lenders agreed to an additional extension of the lender interim agreement through December 31, 2001. Paiton Energy has received lender approval of the Phase I Agreement.
Under the terms of the power purchase agreement, PT PLN has been required to pay for capacity and fixed operating costs once each unit and the plant achieved commercial operation. As of December 31, 2000, PT PLN had not paid invoices amounting to $814 million for capacity charges and fixed operating costs under the power purchase agreement. All arrears under the power purchase agreement continue to accrue, minus the fixed monthly payments actually made under the year 2000 interim agreement and under the recently agreed Phase I Agreement, with the payment of these arrears to be dealt with in connection with the overall long-term restructuring of the tariff. In this regard, under the Phase I Agreement, Paiton Energy has agreed that, so long as the Phase I Agreement is complied with, it will seek to recoup no more than $590 million of the above arrears, the payment of which is to be dealt with in connection with the overall tariff restructuring.
Any material modifications of the power purchase agreement resulting from the continuing negotiation of a new long-term tariff could require a renegotiation of the Paiton project's debt
agreements. The impact of any such renegotiations with PT PLN, the Government of Indonesia or the project's creditors on our expected return on our investment in Paiton Energy is uncertain at this time; however, we believe that we will ultimately recover our investment in the project.
BROOKLYN NAVY YARD
Brooklyn Navy Yard is a 286 MW gas fired cogeneration power plant in Brooklyn, New York. Our wholly-owned subsidiary owns 50% of the project. In February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard Cogeneration Partners, L.P. for damages in the amount of $136.8 million. Brooklyn Navy Yard Cogeneration Partners has asserted general monetary claims against the contractor. In connection with a $407 million non-recourse project refinancing in 1997, we agreed to indemnify Brooklyn Navy Yard Cogeneration Partners and its partner from all claims and costs arising from or in connection with the contractor litigation, which indemnity has been assigned to Brooklyn Navy Yard Cogeneration Partners' lenders. At this time, we cannot reasonably estimate the amount that would be due, if any, related to this litigation. Additional amounts, if any, which would be due to the contractor with respect to completion of construction of the power plant would be accounted for as an additional part of its power plant investment. Furthermore, our partner has executed a reimbursement agreement with us that provides recovery of up to $10 million over an initial amount, including legal fees, payable from its management and royalty fees. At December 31, 2000, 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.
ILLINOIS PLANTS--POWER PURCHASE AGREEMENTS
During 2000, 33% of our electric revenues were derived under power purchase agreements with Exelon Generation Company, a subsidiary of Exelon Corporation, entered into in connection with our December 1999 acquisition of the Illinois Plants. Exelon Corporation is the holding company of Commonwealth Edison and PECO Energy Company, major utilities located in Illinois and Pennsylvania. Electric revenues attributable to sales to Exelon Generating Company are earned from capacity and energy provided by the Illinois Plants under three five-year power purchase agreements. If Exelon Generation were to fail to or became unable to fulfill its obligations under these power purchase agreements, we may not be able to find another customer on similar terms for the output of our power generating assets. Any material failure by Exelon Generation to make payments under these power purchase agreements could adversely affect our results of operations and liquidity.
Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas-fired power plants having an additional gross dependable capacity of 500 MWs at existing or adjacent power plant site in Chicago. The acquisition documents require that commercial operations of this project be completed by December 15, 2003. The estimated cost to complete the construction of this 500 MW gas-fired power plant is approximately $250 million.
FUEL SUPPLY CONTRACTS
At December 31, 2000, we had contractual commitments to purchase and/or transport coal and fuel oil. Based on the contract provisions which consist of fixed prices, subject to adjustment clauses in some cases, these minimum commitments are currently estimated to aggregate $2.4 billion in the next five years summarized as follows: 2001--$838 million; 2002--$653 million; 2003--$386 million; 2004--$308 million; 2005--$241 million.
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 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. However, possible future developments, such as the promulgation of more stringent environmental laws and regulations, and future proceedings which may be taken by environmental authorities, could affect the costs and the manner in which we conduct our business and could cause us to make substantial additional capital expenditures. We cannot assure you that we would be able to recover these increased costs from our customers or that our financial position and results of operations would not be materially adversely affected.
Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes prevent the completion of a proposed project as well as require extensive modifications to existing projects, which may involve significant capital expenditures.
We expect that compliance with the Clean Air Act and the regulations and revised State Implementation Plans developed as a consequence of the Act will result in increased capital expenditures and operating expenses. For example, we expect to spend approximately $67 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 anticipate upgrades to the environmental controls at the Illinois Plants to control nitrogen oxide emissions to result in expenditures of approximately $61 million, $67 million, $130 million, $123 million and $57 million for 2001, 2002, 2003, 2004 and 2005, 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 anticipate environmental costs arising from plant modification of approximately $52 million for the 2001-2005 period.
We own an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Penuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoElectrica a notice of violation and a compliance order alleging violations of the federal Clean Air Act primarily related to start-up activities. Representatives of EcoElectrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoElectrica has not been informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any, action will be taken by the Environmental Protection Agency.
Prior to our purchase of the Homer City plant, the Environmental Protection Agency requested information from the prior owners of the plant concerning physical changes at the plant. Other than with respect to the Homer City plant, no proceedings have been initiated or requests for information issued with respect to any of our United States facilities. However, we have been in informal voluntary discussions with the Environmental Protection Agency relating to these facilities, which may result in the payment of civil fines. We cannot assure you that we will reach a satisfactory agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of the
proceedings, we could be required to invest in additional pollution control requirements, over and above the upgrades we are planning to install, and could be subject to fines and penalties.
NOTE 14. 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 $171.6 million in a guarantee to the lessor and in loans to the project. As of December 31, 2000, the loan obligation stands at $98.8 million, which is secured by the plant assets of $14.6 million owned by the project and a debt service reserve of $3.0 million.
Future minimum payments for operating and capital leases at December 31, 2000, are:
Operating lease expense amounted to $122.0 million, $10.4 million and $6.9 million in 2000, 1999 and 1998, respectively.
SALE-LEASEBACK TRANSACTIONS
In connection with the acquisition of the Illinois Plants, we assigned the right to purchase the Collins gas and oil-fired power plant to third party lessors. The third party lessors purchased the Collins Station for $860 million and entered into leases of the plant with us. The leases, which are being accounted for as operating leases, have 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 leases, we may request a lessor, at its option, to refinance the lessor's debt, which if completed would impact the base lease rent. If a lessor intends to sell its interest in the Collins Station, we have a first right of refusal to acquire the facility at fair market value. Minimum lease payments (included in the table above) are $42.3 million in 2001, $50.3 million in 2002, $50.3 million in 2003, $50.4 million in 2004, and $50.3 million in 2005. At December 31, 2000, the total remaining minimum lease payments were $1.5 billion.
On July 10, 2000, one of our subsidiaries entered into a sale-leaseback of equipment, primarily Illinois peaker power units, to a third party lessor for $300 million. Under the terms of the 5-year lease, we have a fixed price purchase option at the end of the lease term of $300 million. We guarantee the monthly payments under the lease. Minimum lease payments (included in the table above) are $21.1 million in 2001, $21.0 million in 2002, $21.0 million in 2003, and $21.0 million in 2004. In connection with the sale-leaseback, a subsidiary of ours purchased $255 million of notes issued by the lessor which accrue interest at LIBOR plus 0.65% to 0.95%, depending on our credit rating. The notes
are due and payable in five years. The gain recognized on the sale of equipment has been deferred and is being amortized over the term of the lease.
On August 24, 2000, we entered into a sale-leaseback transaction for the Powerton and Joliet power facilities located in Illinois to third party lessors for an aggregate purchase price of $1.367 billion. Under the terms of the leases (33.75 years for Powerton and 30 years for Joliet), our subsidiary makes semi-annual lease payments on each January 2 and July 2, beginning January 2, 2001. Edison Mission Energy guarantees the subsidiary's payments under the leases. If a lessor intends to sell its interest in the Powerton or Joliet power facility, we have a right of first refusal to acquire the interest at fair market value. Minimum lease payments (including in the table above) are $83.3 million for 2001, $97.3 million for 2002, $97.3 million for 2003, $97.3 million for 2004 and $141.1 million for 2005. At December 31, 2000, the total remaining minimum lease payments are $2.4 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain recognized on the sale of the power facilities has been deferred and is being amortized over the term of the lease.
EDISON MISSION ENERGY MASTER TURBINE LEASE
In December 2000, we entered into a master lease and other agreements for the construction of new projects using nine turbines that are being procured from Siemens Westinghouse. The aggregate total construction cost of these projects is estimated to be approximately $986 million. Under the terms of the master lease, the lessor, as owner of the projects, is responsible for the development and construction costs of the new projects using these turbines. We have agreed to supervise the development and construction of the projects as the agent of the lessor. Upon completion of construction of each project, we have agreed to lease the projects from the lessor. In connection with the lease, we have provided a residual value guarantee to the lessor at the end of the lease term. We are required to deposit treasury notes equal to 103% of the construction costs as collateral for the lessor which can only be used under circumstances involving our default of our obligations we have agreed to perform during the construction of each project. Lease payments are scheduled to begin in November 2003. Minimum lease payments (included in the table above) are $3.1 million in 2003, $27.7 million in 2004, and $50.2 million in 2005. The term of the master lease ends in 2010. The master lease grants us, as lessee, a purchase option based on the lease balance which can be exercised at any time during the term.
NOTE 15. 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 employees are sometimes directly requested by us and these services are performed for our benefit. Labor and expenses of these directly requested services are specifically identified and billed at cost. We believe the allocation methodologies utilized are reasonable. We made reimbursements for the cost of these programs and other services, which amounted to $65.3 million, $34.6 million and $29.7 million in 2000, 1999 and 1998, respectively. Accounts payable--affiliates associated with these administrative services totaled $25.5 million and $7.8 million at December 31, 2000 and 1999, 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 $226.3 million, $75.5 million and $29.5 million for 2000, 1999 and 1998, respectively. See
Note 10. Amounts included in Accounts receivable--affiliates associated with these tax benefits totaled $149.9 million and $1.9 million at December 31, 2000 and 1999, respectively.
Edison Mission Operation & Maintenance, Inc., an indirect, wholly-owned affiliate of Edison Mission Energy, has entered into operation and maintenance agreements with partnerships in which Edison Mission Energy has a 50% or less ownership interest. Pursuant to the negotiated agreements, Edison Mission Operation & Maintenance shall perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements will continue until terminated by either party. Edison Mission Operation & Maintenance paid for all costs incurred with operating and maintaining the facility and may also earn an incentive compensation as set forth in the agreements. We recorded revenues under the operation and maintenance agreements of $27.9 million, $28.9 million and $29.8 million in 2000, 1999 and 1998, respectively. Accounts receivable--affiliates for Edison Mission Operation & Maintenance totaled $4.9 million and $5.1 million at December 31, 2000 and 1999, respectively.
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 these partnerships to Southern California Edison Company under these agreements amounted to $715.9 million, $512.6 million and $534.8 million in 2000, 1999 and 1998, respectively.
NOTE 16. SUPPLEMENTAL STATEMENTS OF CASH FLOWS INFORMATION
NOTE 17. BUSINESS SEGMENTS
We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic region: Americas, Asia Pacific and Europe, Central Asia, Middle East and Africa. 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 power purchase agreements with Commonwealth Edison, which assigned its rights and obligations under these power purchase agreements to Exelon Generation Company, which began December 15, 1999 and have a term of up to five years. We currently derive a significant source of our revenues from the sale of energy and capacity to Exelon Generation Company under the power purchase agreements terminating in December 2004. Our revenues from Commonwealth Edison were $1.1 billion for the year ended December 31, 2000. This represents 33% of our consolidated revenues in 2000. Our share of equity in earnings from partnerships that have long-term power purchase agreements with Southern California Edison were $153.0 million, $132.4 million and $112.7 million for the years ended December 31, 2000, 1999 and
1998, respectively. This represents 5% in 2000, 8% in 1999 and 13% in 1998 of our consolidated revenues. Both companies' revenues are included in the Americas region shown below.
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.
During 2000, Edison Mission Energy changed its presentation of segment performance by presenting the measure of profit or loss for each reportable segment as income (loss) from operation compared to net income (loss) as reported in 1999 and 1998.
GEOGRAPHIC INFORMATION
Foreign operating revenues and assets by country included in the table above are shown below.
NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)
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(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 an increase in interest expense as the result of additional debt financings due to the acquisitions throughout 1999.
(iii) Reflects the operations of the Homer City plant acquired in March 1999.
(iv) 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.
(v) 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.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
POSITIONS WITH EDISON MISSION ENERGY
Listed below are our current directors and executive officers and their ages and positions as of March 20, 2001.
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. BRYSON has been director and chairman of the board of Edison Mission Energy since January 2000. Mr. Bryson was director of Edison Mission Energy from January 1986 to January 1998. Mr. Bryson has been president of Edison International since January 2000 and chairman of the board and chief executive officer of Edison International since 1990. Mr. Bryson served as chairman of the board, chief executive officer and a director of Southern California Edison from 1990 to January 2000. Mr. Bryson is a director of The Walt Disney Company, The Boeing Company, and Pacific American Income Shares, Inc. and LM Institutional Fund Advisors I, Inc.
MR. CHRISTIANSEN has been director of Edison Mission Energy since January 2001 and serves as Edison Mission Energy's independent director. Mr. Christiansen has been president of Lord Securities since October 2000 and has been president of Acacia Capital since May 1990. Mr. Christiansen has been a director of Capital Markets Engineering & Trading, New York since August 1999 and has been director of Structural Concepts Corporation of Muskegon, Michigan since May 1995.
MR. CRAVER has been director of Edison Mission Energy since January 2001. Mr. Craver has been senior vice president, chief financial officer, and treasurer of Edison International since January 2000. Mr. Craver has been chairman of the board and chief executive officer of Edison Enterprise since September 1999. Mr. Craver served as senior vice president and treasurer of Edison International from February 1998 to January 2000. Mr. Craver served as senior vice president and treasurer of Southern California Edison from February 1998 to September 1999. Mr. Craver served as vice president and treasurer of Edison International and Southern California Edison from September 1996 to February 1998. Mr. Craver was executive vice president and corporate treasurer of First Interstate Bancorp from September 1990 to April 1996.
MR. DANNER has been director of Edison Mission Energy since May 1993. Mr. Danner has been executive vice president and general counsel of Edison International since June 1995. Mr. Danner was executive vice president and general counsel of Southern California Edison from June 1995 until January 2000. Mr. Danner was senior vice president and general counsel of Edison International and Southern California Edison from July 1992 until May 1995.
MR. EDGELL has been executive vice president of Edison Mission Energy since April 1988. Mr. Edgell served as director of Edison Mission Energy from May 1993 to January 2001. Mr. Edgell was named division president of Edison Mission Energy's Asia Pacific region in January 1995.
MR. FOHRER has been director, president and chief executive officer of Edison Mission Energy since January 2000. 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 from June 1995 until January 2000. Effective February 1996 and June 1995, Mr. Fohrer also served as treasurer of Southern California Edison and Edison International, respectively, until August 1996. Mr. Fohrer was senior vice president, treasurer and chief financial officer of Edison International, and senior vice president and chief financial officer of Southern California Edison from January 1993 until May 1995. Mr. Fohrer was Edison Mission Energy's interim chief executive officer between May 1993 and August 1993. From 1991 until 1993, Mr. Fohrer was vice president, treasurer and chief financial officer of Edison International and Southern California Edison.
MR. HELLER has been senior vice president and division president of Edison Mission Energy, Europe, Central Asia, Middle East and Africa since February 2000. Mr. Heller was elected director of Edison Mission Energy's board, effective December 9, 1999, and subsequently resigned effective February 7, 2000. Mr. Heller was senior vice president of Strategic Planning and New Business Development for Edison International from January 1996 until February 2000. Prior to joining Edison International, Mr. Heller was with McKinsey and Company, Inc. from 1982 to 1995, serving as principal and head of McKinsey's Los Angeles Energy Practice from 1991 to 1995.
MR. LITZINGER has been senior vice president of Edison Mission Energy's Worldwide Operations since June 1999. Mr. Litzinger served as vice president of 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 of O&M Business Development and manager of O&M Business Development until December 1998. Prior to joining Edison Mission Energy, Mr. Litzinger was a reliability supervisor with Texaco Refining and Marketing, Inc. from March 1995 to October 1995 and prior to that held numerous management positions with Southern California Edison since June 1986.
MS. NELSON has been senior vice president of Edison Mission Energy since January 1996 and has been president of Midwest Generation EME, LLC since May 1999. From January 1996 until June 1999, Ms. Nelson was senior vice president of Worldwide Operations. Ms. Nelson was division president of Edison Mission Energy's Americas region from January 1996 to January 1998. Prior to joining Edison Mission Energy, Ms. Nelson served as senior vice president of Southern California Edison from June 1995 until December 1995 and vice president of Southern California Edison from June 1993 until May 1995.
MR. SMITH has been senior vice president and chief financial officer of Edison Mission Energy since May 1999. Mr. Smith 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 of the Americas region.
MR. VICKERS has been senior vice president and general counsel of Edison Mission Energy since March 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.
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 2000:
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 2000, 1999 and 1998 for services rendered by such persons in all capacities to Edison Mission Energy and its subsidiaries.
SUMMARY COMPENSATION TABLE
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(1) On January 17, 2000, Mr. Muller resigned as president and chief executive officer of Edison Mission Energy and Mr. Fohrer was elected president and chief executive officer of Edison Mission Energy.
(2) On February 23, 2001, Mr. Maisto resigned as president of Edison Mission Marketing & Trading, Inc.
(3) Includes perquisites if in total they exceed the lesser of $50,000 or 10% of annual salary and bonus, plus reimbursed taxes.
(4) No Stock Appreciation Rights have been awarded. Amounts shown are comprised of Edison International nonqualified stock options and Edison Mission Energy phantom stock options for
1999 and 1998. As discussed in footnote (3) in the table below entitled "Aggregated Option Exercises in 2000 and Year-End Option Values," all phantom stock options have been canceled pursuant to an exchange offer. The terms and conditions for the 2000 Option Awards are described in footnotes to the table below entitled "Option Grants in 2000." For 2000, Mr. Fohrer, Mr. Muller, Mr. Edgell, Mr. Vickers, Ms. Nelson and Mr. Maisto received 496,672; 98,000; 61,200; 51,200; 50,300 and 0 Edison International stock options pursuant to the Edison International Equity Compensation Plan, respectively, and 1,128; 0; 122,400; 110,000; 100,600 and 30,000 Edison International stock options pursuant to the Edison International 2000 Equity Plan, respectively. For 1999, Mr. Muller, Mr. Edgell, Mr. Vickers and Ms. Nelson received 23,100; 16,100; 15,500 and 9,300 Edison International stock options, respectively, and 10,680; 7,480; 7,190 and 4,310 Edison Mission Energy phantom stock options, respectively. For 1998, Mr. Muller, Mr. Edgell and Ms. Nelson received 13,300; 8,700 and 5,400 Edison International stock options, respectively; and 7,860; 6,060 and 3,180 Edison Mission Energy phantom stock options, respectively.
(5) 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 2000, Mr. Fohrer, $31,801; Mr. Muller, $2,984; Mr. Edgell, $25,870; Mr. Vickers, $14,961; Ms. Nelson, $20,984 and Mr. Maisto, $1,846. For 1999, Mr. Muller, $30,374; Mr. Edgell, $16,384; Mr. Vickers, $0 and Ms. Nelson, $19,779. For 1998, Mr. Muller, $26,373; Mr. Edgell, $14,550 and Ms. Nelson, $15,461.
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 2000, Mr. Fohrer, $23,743; Mr. Muller, $4,769; Mr. Edgell, $840; Mr. Vickers, $1,110; Ms. Nelson, $3,856 and Mr. Maisto, $0. For 1999, Mr. Muller, $5,272; Mr. Edgell, $338; Mr. Vickers, $231 and Ms. Nelson, $2,353; For 1998, Mr. Muller, $13,520; Mr. Edgell, $1,116 and Ms. Nelson, $7,812.
(6) Includes an overseas service allowance of $65,311, $68,644 and $33,693 in 2000, 1999 and 1998, respectively.
(7) In January 2000, Edison Mission Energy entered into a separate agreement with Mr. Muller in connection with the end of his employment that is discussed below in the section entitled "Employment Contract and Termination of Employment Arrangements."
(8) No bonuses were paid under the Executive Incentive Compensation Plan to executive officers for 2000 performance. Mr. Maisto received an award for year 2000 performance pursuant to agreements entered into in connection with the acquisition of Citizens Power LLC by Edison Mission Energy.
EXECUTIVE STOCK OPTIONS
The following table presents information regarding Edison International stock options granted during 2000 pursuant to the Edison International Equity Compensation Plan and/or the Edison International 2000 Equity Plan adopted by the Edison International Board on May 18, 2000 to the executive officers named in the Summary Compensation Table above.
OPTION GRANTS IN 2000(1)
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(1) No Stock Appreciation Rights were granted under the Equity Compensation Plan to any participant during 2000. Stock Appreciation Rights cannot be granted under the 2000 Equity Plan. This table reflects all awards made under the Edison International Equity Compensation Plan and/or the 2000 Equity Plan during 2000.
(2) Edison International nonqualified stock options granted in 2000 may be exercised when vested to purchase one share of Edison International common stock. Two Option Award grants were made during 2000 to the executive officers named in the table above. On January 3, 2000, the annual Option Award was made, and on May 18, 2000, a special Option Award was made in lieu of the 2001 and 2002 annual Option Awards. No dividend equivalents were included with either of these option grants.
The Edison International Compensation and Executive Personnel Committee administers the Equity Compensation Plan and the 2000 Equity Plan and has sole discretion to determine all terms and conditions of any grant, subject to plan limits. It may substitute cash that is equivalent in value to the Option Awards and, with the consent of the executive, may amend the terms of any award, including the post-termination term, and the vesting schedule.
(3) The January 3, 2000, Option Awards are subject to a four-year vesting period with one-fourth of the total award vesting and becoming exercisable annually beginning on January 2, 2001. If an executive retires, dies, or terminates employment following a permanent and total disability during the four-year vesting period, the unvested Option Awards will vest and be exercisable to the extent of 1/48 of the grant for each full month of service during the vesting period. Upon retirement, death or permanent and total disability, the vested Option Awards 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, Option Awards that were vested as of the prior anniversary date of the grant are forfeited unless exercised within 180 days of the date of termination. All unvested Option Awards are forfeited on the date of termination. The Option Awards of Mr. Fohrer are transferable to a spouse, child or grandchild.
Appropriate and proportionate adjustments may be made by the Edison International Compensation and Executive Personnel Committee to the Option Awards 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 Option Awards then outstanding will become vested and be exercisable unless provisions are made as part of the transaction to substitute options of the successor corporation with appropriate adjustments as to the number and price of the options. Notwithstanding the foregoing, the January 3, 2000 Option Awards provide that 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. In no event, however, may an Option Award be exercised beyond its original term.
(4) The May 18, 2000, Option Awards are subject to a five-year vesting period with one-fourth of the total award vesting annually beginning on May 18, 2002. The Option Awards may not be exercised prior to May 18, 2005, unless the closing price of Edison International Common Stock has averaged at least $25 per share over 20 consecutive trading days. If an executive retires, dies, or terminates employment following a permanent and total disability (a "Separation Event") during the five-year vesting period, the unvested Option Awards will vest and be exercisable (subject to the stock price appreciation requirement) to the extent of 1/60 of the grant for each full month of service during the vesting period, taking into consideration prior vesting and exercises (the "regular vesting rule"). Unvested Option Awards of Mr. Fohrer will vest and be exercisable upon a Separation Event in two equal blocks, the 2001 block and the 2002 block. Both blocks will vest and be exercisable to the extent provided under the regular vesting rule if the Separation Event occurs prior to January 1, 2001. If the Separation Event occurs during 2001, the 2001 block will be fully vested and exercisable (subject to the stock price appreciation requirement), and the 2002 block will vest and be exercisable to the extent determined under the regular vesting rule. If the Separation Event occurs after 2002, both blocks will be fully vested and exercisable (subject to the stock price appreciation requirement). Following a Separation Event, the vested Option Awards may be exercised within their original term by the recipient or beneficiary. If an executive terminates employment other than by a Separation Event, Option Awards that were vested as of the prior anniversary date of the grant are forfeited unless exercised within 180 days of the date employment is terminated. All unvested Option Awards are forfeited on the date employment is terminated. The Option Awards of Mr. Fohrer are transferable to a spouse, child or grandchild.
Appropriate and proportionate adjustments may be made by the Edison International Compensation and Executive Personnel Committee to the Option Award to reflect any impact resulting from various corporate events such as reorganizations, stock splits and so forth. In the event of a change in control of Edison International, the May 18, 2000, Option Awards then outstanding will vest and be exercisable unless provisions are made as part of the transaction for the assumption or substitution of the Option Awards with options of the successor corporation with appropriate adjustments as to the number and price of the options. If an involuntary severance occurs during a protected period, but prior to a change in control, unvested Option Awards and vested Option Awards reaching the end of their 180-day exercise period will be suspended and unexercisable. If a change in control occurs within 24 months after the involuntary severance, the Option Awards will vest and be exercisable for 60 days after the change in control, or until the end of the 180-day period following employment termination, whichever date is later. In no event, however, may an Option Award be exercised beyond its original term.
(5) The Option Awards are subject to earlier expiration upon termination of employment as described in footnotes (3) and (4) above.
(6) The grant date value of each Edison International stock option for the January 3, 2000, Option Award was calculated to be $5.28 per option share using the Black-Scholes stock option pricing model. For purposes of
this calculation, it was assumed that the average exercise period was ten years, the volatility rate was 23.48%, the risk-free rate of return was 5.58%, the dividend yield was 4.02% and the stock price and exercise price were $25.1875.
The grant date value of each Edison International stock option for the January 18, 2000, Option Award was calculated to be $5.73 per option share using the Black-Scholes stock option pricing model. For purposes of this calculation, it was assumed that the average exercise period was ten years, the volatility rate was 23.48%, the risk-free rate of return was 5.65%, the dividend yield was 4.02% and the stock price and exercise price were $27.125.
The grant date value of each Edison International stock option for the May 18, 2000, Option Award was calculated to be $5.82 per option share using the Black-Scholes stock option pricing model. For purposes of this calculation, it was assumed that the average exercise period was ten years, the volatility rate was 36.67%, the risk-free rate of return was 6.01%, the dividend yield was 4.21% and the stock price and exercise price were $20.0625.
The grant date value of each Edison International stock option for the September 1, 2000, Option Award was calculated to be $5.99 per option share using the Black-Scholes stock option pricing model. For purposes of this calculation, it was assumed that the average exercise period was ten years, the volatility rate was 38.12%, the risk-free rate of return was 6.06%, the dividend yield was 4.35% and the stock price and exercise price were $20.500.
(7) Mr. Fohrer was granted an additional increment of Edison International stock options on January 18, 2000, upon his election as president and chief executive officer of Edison Mission Energy.
The following table presents information regarding the exercise of Edison International stock options and Edison Mission Energy phantom stock options during 2000 by the executive officers named in the Summary Compensation Table above and unexercised options held as of December 31, 2000 by any of the named officers. No Stock Appreciation Rights were exercised during 2000 or held at year-end 2000 by any of the named officers.
AGGREGATED OPTION EXERCISES IN 2000 AND YEAR-END OPTION VALUES
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(1) Each Edison International stock option may be exercised for one share of Edison International Common Stock at an exercise price equal to the fair market value of the underlying Common Stock on the date the option was granted. Dividend equivalents that may accrue on some of the Edison International stock options accumulate without interest and are paid in cash. The option terms for current year awards are discussed in footnotes (3) and (4) in the table above entitled "Option Grants in 2000." Each Edison Mission Energy phantom stock option represents a right to exercise an option to realize any appreciation in the deemed value of one hypothetical share of Edison Mission Energy phantom stock. Outstanding Edison Mission Energy phantom stock options were canceled pursuant to an exchange offer that is discussed in footnote (3) below.
(2) Edison International stock options have been treated as in-the-money if the fair market value of the underlying stock at December 31, 2000 exceeded the exercise price of the options. The dollar amounts shown for Edison International stock 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 2000 and (ii) the exercise prices of those options. The aggregate value at
year-end 2000 of all accrued dividend equivalents, exercisable and unexercisable, for the named officers was:
Edison Mission Energy phantom stock options were canceled during 2000 pursuant to the terms of an exchange offer described below in footnote (3). The amounts shown in Column (e) reflect the value of the exchange offer on December 31, 2000.
(3) In July 2000, an exchange offer was made for all outstanding Edison Mission Energy phantom stock options. Holders of 100 percent of the outstanding options accepted the exchange offer, and all conditions for completion of the exchange offer were satisfied on August 8, 2000. Because all of the phantom stock options have been terminated, no future phantom stock option exercises will occur. The exchange offer was principally for cash with a portion to be exchanged for stock equivalent units related to Edison International Common Stock. The number of stock units was determined on a basis of $20.50 per share. Each stock unit represents the value of one share of Edison International Common Stock. The stock equivalent units accrue dividend equivalents that are converted to additional stock equivalent units. The vested cash, plus accrued interest from August 8, 2000, was paid on March 13, 2001. Amounts attributable to unvested phantom stock options will vest according to the original schedule and will be paid with interest at that time. Participants may elect to receive payment for their stock equivalent units on either the first- or third-year anniversary of the August 8, 2000 exchange date. The stock equivalent units will be converted to cash in an amount equal to the number of stock equivalent units multiplied by the sum of the daily average of the high and low trading prices of Edison International Common Stock on the New York Stock Exchange for the 20 trading days preceding the elected payment date divided by 20. Some phantom stock option holders elected to defer payments of the cash and/or stock equivalent units, and the payment schedules for them will differ from that described above.
(4) Edison Mission Energy made payments in settlement of the phantom stock options held by Mr. Muller who resigned by mutual agreement in January 2000. See the section entitled "Employment Contract and Termination of Employment Arrangements" below for further information regarding the terms of this agreement.
(5) Messrs. Edgell and Vickers, and Ms. Nelson accepted the exchange offer described above in footnote (3), and their Edison Mission Energy phantom stock options have therefore been canceled.
The following table presents information regarding Edison International performance shares granted in part under the Edison International Equity Compensation Plan during 2000 to the executive officers named in the Summary Compensation Table above.
LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR(1)
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(1) Twenty-five percent of each Executive Officer's long-term incentive compensation for 2000 was awarded in the form of Edison International performance shares, with the balance being granted in the form of Edison International Stock Options. The stock options are discussed in the footnotes to the table above entitled "Option Grants in 2000." Performance shares are stock-based units with each unit worth one share of Edison International Common Stock. No dividend equivalents were included with these grants. Two payment dates were established for this initial grant of performance shares, each covering one-half of the performance shares awarded. The first payment date is December 31, 2001; the second payment date is December 31, 2002. One-half of the performance shares will be paid in Edison International Common Stock under the Equity Compensation Plan, and one-half will be paid in cash equal to the value of such stock outside of the plan.
The initial grant and payment of performance shares was conditioned on certain performance targets being met including total shareholder return. However, effective January 2, 2001, the Edison International Compensation and Executive Personnel Committee restructured the performance shares into retention incentives as an inducement to Executive Officers to continue working through resolution of the California power crisis. The downside and upside potential was eliminated, and the performance shares will pay at target levels on the first and second payment dates if the executive officer remains employed by Edison Mission Energy on those dates. Pro rata payments will be made in the event of death, disability, or involuntary severance without cause, but no payment will be made in the event of a voluntary separation or a separation for cause.
(2) Mr. Maisto was not awarded any Edison International performance shares in 2000.
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)
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(1) Estimates are based on the terms 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. For purposes of the executive retirement plan, as of December 31, 2000, the years of service completed for: Mr. Fohrer, 27; Mr. Muller, 6; Mr. Edgell, 30; Mr. Vickers, 2 and Ms. Nelson, 30. Amounts in the Pension Plan Table include neither the Income Continuation Plan nor the Survivor Income/Retirement Income plans, which provide post-retirement death benefits and supplemental retirement income benefits. These plans are discussed in "--Other Retirement Benefits."
The retirement plans provide monthly benefits at normal retirement age, 65 years, determined by a percentage of the average of the executive's highest 36 consecutive months of regular salary and, in the case of the executive retirement plan with respect to senior officers, the executive's highest 36 consecutive months of salary and bonus prior to attaining age 65. Compensation used to calculate combined benefits under the plans 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. Senior officers receive an additional service percentage of 3/4 percent per year for the first ten years of service (7.5% upon completion of ten years of service). The actual benefit is 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.
Messrs. Fohrer and Edgell have elected to retain coverage under a prior benefit program. This program provided, among other benefits, the post-retirement benefits discussed in the following section. The retirement benefits provided under the prior program are less than the benefits shown in the Pension Plan Table in that they do not include the additional 7.5% service percentage. 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%.
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 23% 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. Messrs. Fohrer and Edgell have elected coverage under this plan.
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. Messrs. Fohrer and Edgell have elected coverage under this plan.
EMPLOYMENT CONTRACT 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 agreement with Mr. Muller also provided 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.
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 officers of Edison Mission Energy named in the Summary Compensation Table in Item 11 and all directors and executive officers of Edison Mission Energy as a group as of December 31, 2000. The table includes shares that can be acquired through March 1, 2001; through the exercise of stock options. Unless otherwise indicated, each named person has sole voting and investment power.
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(a) No named person or group owns more than 1% of the outstanding shares of the class.
(b) Includes 16,025 shares credited under the Stock Savings Plus Plan and 839,501 shares that can be acquired through the exercise of options. Includes 14,000 shares held as co-trustee of trust with shared voting and investment power, 6,000 shares held as trustee of trust with shared voting and sole investment power, 40,409 shares held as co-trustee and co-beneficiary of trust with shared
voting and investment power, and 200 shares held by spouse with shared voting and investment power.
(c) Includes 103,751 shares that can be acquired through the exercise of options. Includes 6,000 shares held as co-trustee and co-beneficiary of trust with shared voting and investment power.
(d) Includes 3,139 shares credited under the Stock Savings Plus Plan and 269,451 shares that can be acquired through the exercise of options.
(e) Includes 28,889 shares credited under the Stock Savings Plus Plan and 267,426 shares that can be acquired through the exercise of options.
(f) Includes 42,262 shares credited under the Stock Savings Plus Plan and 65,575 shares that can be acquired through the exercise of options.
(g) Includes 852 shares credited under the Stock Savings Plus Plan and 20,551 shares that can be acquired through the exercise of options.
(h) Includes 5,220 shares credited under the Stock Savings Plus Plan and 27,942 shares that can be acquired through the exercise of options.
(i) Includes 48 shares credited under the Stock Savings Plus Plan and 7,500 shares that can be acquired through the exercise of options.
(j) Includes 102,166 shares credited under the Stock Savings Plus Plan and 1,768,348 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.
(k) Mr. Christiansen was elected as an independent director of Edison Mission Energy's Board, effective January 15, 2001.
(l) Mr. Maisto resigned as president of Edison Mission Marketing & Trading, Inc., effective February 23, 2001.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In July 1999, Edison Mission Energy 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.
In October 2000, we made a loan to Gregory C. Hoppe, Vice President of Edison Mission Energy, and Director, Australia, in the amount of $350,000 in exchange for a secured promissory note executed by Mr. Hoppe and payable to us at simple interest of 6.37%. The entire note, together with accrued interest, is due January 2002.
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 items are 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, 2000, 1999 and 1998.
- Four Star Financial Statements as of December 31, 2000, 1999 and 1998.
Schedule I--Condensed Financial Information of Parent 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
No reports on Form 8-K were filed during the quarter ended December 31, 2000.
(c) Exhibits
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* Filed herewith.
(d) Financial Statement Schedules
Financial information for the Cogeneration Group and Four Star Oil & Gas Company is for the years ended December 31, 2000, 1999 and 1998. The financial statements of the Cogeneration Group present the combination of those entities that are energy projects and 50% or less owned by Edison Mission Energy and that met the requirements of Rule 3-09 of Regulation S-X in 2000 and 1999. The financial statements of Four Star Oil & Gas Company represent an oil and gas investment that is 50% or less owned by Edison Mission Energy and that met the requirements of Rule 3-09 of Regulation S-X in 2000. 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.
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), Watson Cogeneration Company (a general partnership between Camino Energy Company and Products Cogeneration Company) and CPC Cogeneration LLC (a Delaware limited liability company, (collectively the Cogeneration Group) as of December 31, 2000 and 1999, and the related combined statements of income, partners' equity and cash flows for the years 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, 2000 and 1999, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.
As more fully disclosed in Note 2 to the financial statements, effective January 1, 2000, Kern River Cogeneration Company and Sycamore Cogeneration Company changed their method of accounting for major maintenance costs from the "accrue in advance" method to the "expense as incurred" method.
ARTHUR ANDERSEN LLP
Los Angeles, California March 21, 2001
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 STATEMENTS OF PARTNERS' EQUITY AND MEMBERS' 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 accompanying notes are an integral part of these combined financial statements.
THE COGENERATION GROUP NOTES TO COMBINED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 (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 (SCE), has a general partnership interest in Kern River Cogeneration Company, Sycamore Cogeneration Company, Watson Cogeneration Company and CPC Cogneration LLC(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.
Background of operations
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.
Effective January 1, 2000, the partners in Watson created CPC Cogeneration LLC (commonly referred to as CPC). Watson's partners own CPC in the same percentage in which they own Watson. The general purpose of CPC is to act as an intermediary between Watson and ARCO by purchasing power from Watson and selling it to ARCO.
Current developments
The three projects making up the Cogeneration Group sell the majority of their electricity to SCE. As a result of Southern California Edison's current liquidity crisis, SCE has failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the Cogeneration Group. Southern California Edison did not pay any of the amounts due to the Cogeneration Group in January, February and March of 2001 and may continue to miss future payments.
Southern California Edison's failure to pay has adversely affected the operations of the Cogeneration Group. Continuing failures to pay could have an adverse impact on the operations of the California qualifying facilities. Some of the partnerships in the Cogeneration Group have sought to minimize their exposure to Southern California Edison by reducing deliveries under their power purchase agreements. It is unclear at this time what additional actions, if any, the Cogeneration Group will take in regard to the utility's suspension of payments due to the qualifying facilities. As a result of the utility's failure to make payments due under these power purchase agreements, the Cogeneration Group has called on the partners to provide additional capital to fund operating costs of the power plants. From January 1, 2001 through March 21, 2001, partners have contributed $93 million to meet capital calls by the Cogeneration Group.
Southern California Edison has stated that it is attempting to avoid bankruptcy and, subject to the outcome of regulatory and legal proceedings and negotiations regarding purchased power costs, it intends to pay all its obligations once a permanent solution to the current energy and liquidity crisis has been reached. It is possible that the utility will not pay all its obligations in full. In addition, it is possible that Southern California Edison could be forced into bankruptcy proceedings. If this were to occur, payments to the qualifying facilities, including the Cogeneration Group, could be subject to significant delays associated with the lengthy bankruptcy court process and may not be paid in full. At February 28, 2001, accounts receivable from Southern California Edison were $349 million. Furthermore, Southern California Edison's power purchase agreements with the qualifying facilities could be subject to review by a bankruptcy court. While we believe that the generation of electricity by the qualifying facilities, including the Cogeneration Group, is needed to meet California's power needs, we cannot assure you either that the Cogeneration Group will continue to generate electricity without payment by the purchasing utility, or that the power purchase agreements will not be adversely affected by a bankruptcy or contract renegotiation as a result of the current power crisis.
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.
Intangible Assets
Intangible assets are stated net of accumulated amortization of $16.4 million and $15.2 million at December 31, 2000 and 1999, 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
Through December 31, 1999 two of the partnerships included in the Cogeneration Group accrued for major maintenance costs during the period between turnarounds (referred to as "accrue in advance" accounting method). Such accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the Securities Exchange Commission issued a letter to the Accounting Standards Executive Committee, stating its position that the Securities Exchange Commission Staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance costs. The Accounting Standards Executive Committee agreed to add accounting for major maintenance costs as part of an existing project to issue authoritative guidance by August 2001. Due to the position taken by the Securities Exchange Commission Staff, the Cogeneration Group voluntarily decided to change their accounting policy to record major maintenance costs as an expense as incurred. Such change in accounting is considered preferable based on the recent guidance provided by the Securities Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," the Cogeneration Group has recorded a $13.8 million increase to net income, as a cumulative change in the accounting for major maintenance costs, during the year ended December 31, 2000.
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:
NOTE 4. LOANS PAYABLE
The fair value of the two Watson project notes was approximately $34.5 million and $52.5 million at December 31, 2000 and 1999, 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:
The above costs represent salaries and wages, labor related costs and overhead of personnel and related costs for services directly performed on behalf of each partnership. In addition, such charges from Southern California Edison Company and its affiliates include interconnection charges which are billed based on tariffs applicable to similar customers. Management believes the basis for charges between affiliates is reasonable.
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, 2000, 1999 and 1998.
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 01, 1996, the Amended and Restated Fuel Management Agreement, terminating on October 01, 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, 2000, Texas Natural Gas, Inc. received a fixed service fee of $.039 per MMBtu. The amounts incurred under the amended agreements were $315.3 million, $177.4 million and $168.8 million, which included fees earned by Texaco Natural Gas, Inc. of $2.5 million, $2.5 million and $2.5 million, for the three years ended December 31, 2000, 1999 and 1998, 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 $155.2 million, $32.4 million and $39.9 million for the three years ended December 31, 2000, 1999 and 1998, 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 $6.3 million, $6.1 million, and $6.1 million, which included incentive compensation earned by Edison Mission Operation & Maintenance, Inc. of $1.0 million, $.9million and $.9 million for the three years ended December 31, 2000, 1999 and 1998, 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 $5.7 million, $5.6 million, and $4.8 million for the three years ended December 31, 2000, 1999 and 1998, 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, 2000, 1999 and 1998.
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 there under. 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 2000, 1999 and to a limited extent 1998. Reductions in steam revenues based upon these agreements totaled $24.2 million, $20.9 million and $2.2 million for the three years ended December 31, 2000, 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 09, 1985 and January 01, 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, 2000,
would be approximately $97 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 01, 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, 2000, 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 based upon current projections for the operations of such Cogeneration Group's facilities.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Four Star Oil & Gas Company:
We have audited the accompanying consolidated balance sheets of Four Star Oil & Gas Company (a Delaware corporation) and subsidiary as of December 31, 2000 and 1999, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These 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 Four Star Oil & Gas Company and subsidiary as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas March 2, 2001
FOUR STAR OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS--DECEMBER 31, 2000 AND 1999
(IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN MILLIONS)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(IN MILLIONS)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF THE COMPANY:
The use in this report of the term "Texaco" refers solely to Texaco Inc., a Delaware corporation, and its consolidated subsidiaries or to subsidiaries and affiliates either individually or collectively.
In 1984, Texaco acquired all of the outstanding common stock of Four Star Oil & Gas Company (Four Star or the Company) for $10.2 billion. At the time of acquisition, Four Star was an integrated petroleum and natural gas company involved in the exploration for and production, transportation, refining and marketing of crude oil and petroleum products. The acquisition was accounted for as a purchase, and the Four Star assets and liabilities were recorded at fair market value.
Substantially all of Four Star's assets other than certain U.S. crude oil and natural gas exploration and producing properties and Four Star's interest in the Partitioned Neutral Zone were disposed of either through sales to third parties or sales and transfers to other Texaco subsidiaries in connection with Texaco's internal reorganization accomplished in late 1984. In 1989, Four Star's interest in the Partitioned Neutral Zone was transferred to Texaco, and Texaco sold 20 percent of its interest in Four Star to Edison Mission Energy (Mission Energy). Four Star was an 80 percent owned subsidiary of Texaco from December 31, 1989, through December 30, 1991.
Through a series of stock transactions among Four Star, Texaco Exploration and Production Inc. (TEPI), Texaco and Mission Energy, the ownership interest in Four Star was as follows as of December 31, 1997: Texaco--31.9 percent; TEPI--32.3 percent; and Mission Energy--35.8 percent.
During 1998, TEPI sold 20 shares of Four Star Class A common stock and 17 shares of Four Star Class B common stock to Mission Energy. This sale resulted in the following companies holding an interest in Four Star: Texaco--31.9 percent; TEPI--29.8 percent; and Mission Energy--38.3 percent.
In March 1999, Four Star issued 300 shares of preferred stock in exchange for TEPI's interest in the Hugoton Gas Field. In November 1999, Mission Energy sold 360 shares of Class A common stock to Four Star Oil & Gas Holdings Company. In December 1999, TEPI converted 42 Class A preferred shares to Class B common stock. The transactions in 1999 resulted in the following companies holding an interest in Four Star: Texaco--26.5 percent; TEPI--40.4 percent; Mission Energy--13 percent; and Four Star Oil & Gas Holdings Company (owned jointly by Texaco Inc. and Mission Energy)--20.1 percent.
During 2000, TEPI sold 28 shares of Four Star Class A and 12 shares Class B common stock to Mission Energy. Also, TEPI converted 80 shares of its Class A preferred stock into Class B common stock. The transactions resulted in the following companies holding an interest in Four Star: Texaco--26.5 percent; TEPI--38.2 percent; Mission Energy--15.2 percent; and Four Star Oil & Gas Holdings Company--20.1 percent.
2. SIGNIFICANT ACCOUNTING POLICIES:
CASH AND CASH EQUIVALENTS
Highly liquid investments with a maturity of three months or less when purchased are generally considered to be cash equivalents.
PROPERTIES, PLANT AND EQUIPMENT, AND DEPRECIATION, DEPLETION AND AMORTIZATION
The Company follows the successful-efforts method of accounting for its oil and gas exploration and production operations.
Lease acquisition costs related to properties held for oil and gas production are capitalized when incurred. Unproved properties with acquisition costs which are individually significant are assessed on a property-by-property basis, and a loss is recognized, by provision of a valuation allowance, when the assessment indicates an impairment in value. Unproved properties with acquisition costs which are not individually significant are generally aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized on an average holding period basis.
Exploratory costs, excluding the costs of exploratory wells, are charged to expense as incurred. Costs of drilling exploratory wells, including stratigraphic test wells, are capitalized pending determination of whether the wells have found proved reserves which justify commercial development. If such reserves are not found, the drilling costs are charged to exploratory expenses. Intangible drilling costs applicable to productive wells and to development dry holes, as well as tangible equipment costs related to the development of oil and gas reserves, are capitalized.
The costs of productive leaseholds and other capitalized costs related to production activities, including tangible and intangible costs, are amortized principally by field on the unit-of-production basis by applying the ratio of produced oil and gas to estimated recoverable proved oil and gas reserves. Estimated future restoration and abandonment costs are taken into account in determining amortization and depreciation rates.
Depreciation of properties, plant and equipment related to operations other than production is provided generally on the group plan, using the straight-line method, with depreciation rates based upon estimated useful lives applied to the cost of each class of property.
Normal maintenance and repairs of properties, plant and equipment are charged to expense as incurred. Renewals, betterments and major repairs that materially extend the life of properties are capitalized, and the assets replaced, if any, are retired.
When fixed capital assets representing complete units of property are disposed of, any profit or loss after accumulated depreciation and amortization is credited or charged to income. When miscellaneous business properties are disposed of, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
Four Star has adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." In accordance with SFAS No. 121, the Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. In 2000, the Company estimated the expected future cash flows of its oil and gas properties and compared such future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount was recoverable. The carrying amount of one property exceeded the estimated undiscounted future cash flows; therefore, the Company adjusted the carrying amount of the property to fair value as determined by discounting the estimated future cash flows. The factors used to determine fair value included, but were not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and a discount rate commensurate with the risk on those properties. As a result, the Company recorded an impairment of $25 million on its Green Canyon 184 property in 2000 due to downward reserve revisions. The Company did not record any impairment charge in 1999 or 1998.
USE OF ESTIMATES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.
NEW ACCOUNTING PRONOUNCEMENT
In June 1998, the Financial Accounting Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement also requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138, is effective for fiscal years beginning after June 15, 2000. Adoption of this standard will not have a material effect on the Company's financial position as the Company has no derivatives as of December 31, 2000, except for its physical sale contracts, which qualify as normal sales.
RECLASSIFICATIONS
Certain previously reported amounts have been reclassified to conform to current-year presentation.
3. RELATED-PARTY TRANSACTIONS:
Four Star has various business transactions with Texaco and other Texaco subsidiaries and affiliates. These transactions principally involve sales by Four Star of crude oil, natural gas and natural gas liquids, and billings by Texaco for management, professional, technical and administrative services, as well as direct charges for exploration and production-related activities.
Effective January 1, 1990, pursuant to a service agreement between Four Star and Texaco, Four Star pays $605,000 per month, escalating 5 percent per annum beginning in 1991 through expiration of the agreement on December 31, 1999, for management, professional, technical and administrative services, which amount is included as a component of operating expenses in the accompanying consolidated statements of income. Effective July 1, 1994, the first amendment to the service agreement provides for an additional $476,000 per month, escalating 4 percent per annum beginning July 1, 1994, through the expiration of the agreement.
Effective December 1, 1999, Four Star entered into a service agreement with TEPI for management, administrative, professional and technical services through November 1, 2004. Four Star paid a monthly fixed fee of $568,417 through December 1, 2000. Beginning November 15, 2000, the monthly fixed fee was adjusted to $579,785. In addition, Four Star paid a monthly unit fee of $612,368 until December 1, 2000. On November 15, 2000, Four Star commenced payment of a monthly unit fee of $645,015. This unit fee is adjusted monthly to reflect actual oil and gas production. The monthly fixed and unit fees are included as a component of operating expenses in the accompanying consolidated statements of income.
As described in Note 1, in March 1999, Four Star issued 300 shares of preferred stock in exchange for TEPI's interest in the Hugoton Gas Field.
As described in Note 1, during 2000, TEPI sold 28 shares of Four Star Class A common stock and 12 shares of Class B common stock to Edison.
As described in Note 5, the Company entered into a loan agreement with Texaco in September 1999.
Pursuant to the contractual agreement described in Note 10, certain tax benefits and liabilities are assumed by Texaco.
Texaco has an option to purchase, for $1.0 million, Four Star's interest in the Headlee Devonian unit. The option is exercisable during a two-year period commencing on the date that the accumulated production of natural gas from this unit totals 131.4 billion cubic feet (Bcf), as measured from January 1, 1990. As of December 31, 2000, accumulated production totaled 106.5 Bcf.
The following table summarizes sales to and purchases from affiliates during 2000, 1999 and 1998 (in millions):
4. PROPERTIES, PLANT AND EQUIPMENT:
In 1999, Four Star sold $2 million of its properties for $4 million, resulting in an approximate $2 million gain on the sale. In 2000, Four Star sold $5.9 million of its properties for $6.3 million, resulting in an approximate $400,000 gain on the sale.
5. LONG-TERM DEBT:
In September 1999, Four Star retired its loan with Chase Bank of Texas, N.A., and entered into a loan agreement with Texaco. The outstanding balance on the loan agreement was $239 million at December 31, 2000 and 1999. The loan bears interest at LIBOR plus 1 percent and matures on December 31, 2005. Interest expense during 2000, 1999 and 1998, was $18 million, $15 million and $20 million, respectively. Four Star pays Texaco an annual facility fee and administrative fee of $250,000.
The borrowing base will be determined on a yearly basis as set forth in the Four Star Oil & Gas Credit Agreement dated September 30, 1999. If the outstanding aggregate principal amount of the loan, excluding the amount of any debt permitted by the loan agreement, exceeds the amount of the borrowing base, Four Star must pay such excess to Texaco in four equal quarterly installments. In 2000, Four Star's borrowing based exceeded the amount of the loan, thus no principal payments were due.
Four Star has the right, subject to certain conditions, to prepay the note in whole or in part prior to the maturity date.
6. CONCENTRATION OF CREDIT RISK:
Credit risk represents the accounting loss that the Company would record if its customers failed to perform pursuant to contractual terms. Substantially all of the Company's accounts receivable at December 31, 2000, result from sales to the Company's two largest customers both of which are Texaco entities, as discussed in Note 3. This concentration of customers may impact the Company's overall credit risk either positively or negatively in that these entities may be similarly affected by industrywide changes in economic or other conditions. The Company's credit policy and relatively short duration of receivable mitigate the risk of uncollected receivables. At December 31, 2000, the Company had not incurred any credit losses on receivables.
Two customers, Texaco Natural Gas Inc. and Equilon Enterprises LLC, accounted for more than 10 percent of the Company's total revenues in 2000, 1999 and 1998. Texaco Natural Gas Inc. accounted for 52 percent, 58 percent and 59 percent of sales in 2000, 1999 and 1998, respectively. Equilon Enterprises LLC accounted for 17 percent, 22 percent and 23 percent of sales in 2000, 1999 and 1998, respectively.
7. INCOME TAXES:
The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under SFAS No. 109, deferred income taxes are determined utilizing a liability approach. This method gives consideration to the future tax consequences associated with utilization of energy tax credits and differences between financial accounting and tax bases of assets and liabilities. Such differences relate mainly to depreciable and depletable properties, intangible drilling costs and nonproductive leases.
The composition of deferred tax assets and liabilities and the related tax effects at December 31, 2000, 1999 and 1998, were as follows (in millions):
There are differences between income taxes computed using the statutory rate of 35 percent and the Company's effective income tax rates (31 percent in 2000, 22 percent in 1999 and 33 percent benefit in 1998), primarily as the result of certain tax credits available to the Company. Reconciliations of income taxes computed using the statutory rate to the effective tax rates are as follows (in millions):
8. STOCKHOLDERS' EQUITY:
In 1995, Four Star created four additional classes of stock: Class A common (voting), Class B common (voting), Class C common, and preferred. The Class A common stock was issued in exchange for the outstanding common stock as of May 15, 1995. Texaco sold 6 percent of its Class A common stock to Mission Energy effective January 1, 1995. In addition, 25 shares of Class C common stock, 117 shares of Class B common stock and 352 shares of preferred stock were issued in connection with property acquisitions.
In 1995, Texaco, TEPI and Mission Energy entered into an agreement granting Mission Energy the option to purchase shares of Class A common stock or Class B common stock of Four Star (class determined by Texaco), provided that Mission Energy's ownership interest in the voting common stock does not exceed 49 percent of all voting common stock outstanding. The option expires on December 23, 2006. As of December 31, 2000 and 1999, Mission Energy owned 20 percent and 18 percent, respectively, of all voting common stock outstanding. Four Star Oil & Gas Holdings
Company (owned jointly by Texaco Inc. and Mission Energy) owned 29 percent of all voting common stock in the Company.
Each share of preferred stock is convertible into one share of Class B common stock at any time on or after December 31, 1999. Each share of preferred stock shall be entitled to receive cumulative cash dividends of $5,112 per share per annum, payable semiannually. As described in Note 1, TEPI converted 80 shares of its Class A preferred stock into Class B common stock. In 2000, the Company distributed $140 million to its common stockholders and $4 million to its preferred stockholders.
9. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The Company's financial instruments consist of cash and cash equivalents, short-term receivables and payables and long-term debt. The carrying amounts approximate fair market value due to the highly liquid nature of the short-term instruments and the floating interest rates associated with the long-term debt which reflect market rates.
10. COMMITMENTS CONTINGENCIES:
Texaco has assumed any and all liabilities of Four Star incurred or attributable to periods prior to January 1, 1990, for state and federal income, windfall profit, ad valorem or franchise taxes, and legal proceedings. In addition, Texaco has assumed certain of the tax liabilities of Four Star arising from January 1, 1990, to March 1, 1990, attributable to Four Star's status as a member of the Texaco tax consolidated group.
In the opinion of the Company, while it is impossible to ascertain the ultimate legal and financial liability with respect to the above or other contingent liabilities, including lawsuits, claims, guarantees, federal taxes and federal regulations, the aggregate amount of such liability is not anticipated to be material in relation to the financial position or results of operations of the Company.
11. CHEVRON/TEXACO MERGER:
On October 15, 2000, Texaco and Chevron Corporation (Chevron) entered into a merger agreement. In the merger, Texaco stockholders will receive .77 shares of Chevron common stock for each share of Texaco common stock they own, and Chevron stockholders will retain their existing shares.
The merger is conditioned on, among other things, the approval of the stockholders of both companies, a pooling-of-interests accounting treatment for the merger, and the approvals of government agencies, such as the U.S. Federal Trade Commission (FTC). Texaco and Chevron anticipate that the FTC will require certain divestitures in the U.S. downstream in order to address market concentration issues, and the companies intend to cooperate with the FTC in this process.
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETS (IN THOUSANDS)
SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME (IN THOUSANDS)
SCHEDULE I
EDISON MISSION ENERGY AND SUBSIDIARIES
CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
SCHEDULE II
EDISON MISSION ENERGY AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
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(1) Through December 31, 1999 we accrued for major maintenance costs during the period between turnarounds (referred to as "accrue in advance" accounting method). The accounting policy has been widely used by independent power producers as well as several other industries. In March 2000, the Securities and Exchange Commission issued a letter to the Accounting Standards Executive Committee stating its position that the Securities and Exchange Commission staff does not believe it is appropriate to use an "accrue in advance" method for major maintenance costs. The Accounting Standards Executive Committee agreed to add accounting for major maintenance costs as part of an existing project and to issue authoritative guidance by August 2001. Due to the position taken by the Securities and Exchange Commission staff, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. Such change in accounting policy is considered preferable based on the recent guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we have recorded $17.7 million, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs during the quarter ended March 31, 2000.