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, 2001, we owned interests in 31 domestic and 49 international operating power projects with an aggregate generating capacity of 23,967 Megawatts, or MW, of which our share was 19,019 MW. At that date, one domestic and six international projects, totaling 1,153 MW of generating capacity, of which our anticipated share will be approximately 668 MW, were under construction. At December 31, 2001, we had consolidated assets of $10.7 billion and total shareholder's equity of $1.6 billion.
We are incorporated under the laws of the State of Delaware. 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:
•our ability to maintain an investment grade rating;
•our ability to refinance short-term debt or raise additional financing for our future cash requirements;
•supply, demand and price for electric capacity and energy in the markets served by our generating units;
•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;
•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; and
•the cost, availability and pricing of fuel and fuel transportation services for our generating units.
We use words like "anticipate," "estimate," "project," "plan," "expect," "will," "believe" 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, and for other risk factors affecting our business and financial condition, you should read "Management's Discussion and Analysis of Results of Operations and Financial Condition-Risk Factors and -Critical Accounting Policies" contained in Part II, Item 7 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.
Description of Business
Electric Power Industry
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 ourselves, 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. In deregulating markets, industry trends and regulatory initiatives have caused vertically integrated, price regulated utilities, to enter into markets in which generators complete with each other for their principal customers (wholesale power suppliers, distribution companies, and major end-users) on the basis of price, reliability and other factors. As a result of the recent energy crisis in California, some states have either discontinued or delayed implementation of initiatives involving retail deregulation. These developments have generally not affected the market structures in Illinois and Pennsylvania, where many of our of power plants are located.
The movement toward privatization of existing power generation capacity in many foreign countries and the growing need for new capacity has also led to the development of significant new markets for independent power producers outside the United States. We have developed or acquired power plants in the Asia-Pacific region and in Europe and the Middle East regions as a result of these developments.
Competition
We and our subsidiaries are subject to intense competition in the United States and overseas from energy marketers, utilities, industrial companies and other independent power producers. Over the past several years, the restructuring of energy markets has led to the sale of utility-owned assets to us and our competitors. More recently, in response to market conditions, we and other power generators have changed focus from acquisition and growth to concentrating on selective asset dispositions as well as postponing or canceling power plants under development. This trend is in response to credit concerns
in the wake of the bankruptcy of Enron Corp., economic recession in the United States, and a potential oversupply of new generating capacity.
In markets where we sell power from plants where the output is not committed to be sold under long-term contracts, commonly referred to as merchant plants, we are subject to substantial competition with independent power producers with power plants located in the same geographic region. We compete primarily based on price, reliability and other factors which are heavily influenced by electricity demand and supply, which is commonly referred to as capacity. Our customers include large electric utilities or regional distribution companies. In some cases, the electric utilities and distribution companies have their own generation capacity, including nuclear generation, that affects the amount of generation available to meet demand and may affect the price of electricity in a particular market.
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 services, could also lead to increased competition in the independent power market. See "-Regulatory Matters-Retail Competition."
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 and Middle East. 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 19. Business Segments."
Regional Overview of Business Segments
As of December 31, 2001, we had ownership or leasehold interests in the following domestic operating projects:
(1)Operated by subsidiaries or affiliates of Edison Mission Energy; all other projects are operated by unaffiliated third parties.
(2)Currently offered for sale.
(3)Sold subsequent to December 31, 2001.
(4)Electric purchaser abbreviations are as follows:
CDWR
California Department of Water Resources
CE
Consolidated Edison Company of New York, Inc.
EG
Exelon Generation Company
MPC
Monongahela Power Company
PG&E
Pacific Gas & Electric Company
Pool
Regional electricity trading market
PREPA
Puerto Rico Electric Power Authority
PSE
Puget Sound Energy, Inc.
SCE
Southern California Edison Company
VEPCO
Virginia Electric & Power Company
(5)All the cogeneration projects are gas-fired facilities, except for the James River project, which we recently sold, which used coal. All the exempt wholesale generator (EWG) projects are gas-fired facilities, except for the Homer City facilities and six of the Illinois plants, which use coal.
As of December 31, 2001, we had ownership or leasehold interests in the following international operating projects:
(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:
EGAT
Electricity Generating Authority of Thailand
Pool
Electricity trading markets for England,
FECSA
Fuerzas Electricas de Cataluma, S.A.
Wales, Australia and New Zealand
GRTN
Gestore Rete Transmissione Nazionale
SE
Southern Electric plc.
NORWEB
North Western Electricity Board
TEAS
Turkiye Elektrik Urehm A.S.
NPC
National Power Corp.
WP
Western Power
PLN
PT PLN
(3)Sells to the pool with a long-term contract with SE.
(4)Sells to the pool with a long-term contract with NORWEB.
(5)Sells to the pool with a long-term contract with the State Electricity Commission of Victoria.
(6)Minority interest in three projects.
(7)Minority interest in one project. Americas
As of December 31, 2001, we had 31 operating projects in this region, all of which are presently located in the United States and its territories. Our Americas region is headquartered in Chicago,
Illinois, with additional offices located in Irvine, California, and Boston, Massachusetts. A description of our power plants and major investments in energy projects in the Americas region is set forth below.
Illinois Plants
On December 15, 1999, we completed a transaction with Commonwealth Edison, now 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 are located in the Mid-America Interconnected Network, which has transmission connections to the East Central Area Reliability Council and other regional markets. In connection with this transaction, we entered into three power purchase agreements with Commonwealth Edison with terms of up to five years expiring in 2004, 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. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement. Our power purchase agreements with Exelon Generation accounted for 36% and 42% of our electric revenues for 2001 and 2000, respectively. See further discussion of the power purchase contracts with Exelon Generation under "Management's Discussion and Analysis of Results of Operations and Financial Condition-Market Risk Exposures."
The Illinois plants are comprised of the following:
As part of the purchase of the Illinois plants, we assigned our right to purchase the Collins Station to third-party entities and our subsidiary simultaneously entered into long-term lease of the Collins Station. We also completed sale-leaseback transactions with respect to our Illinois peaker units in July 2000 and our Powerton and Joliet power facilities in August 2000. We sold these assets and entered into long-term leases to provide capital to finance our acquisition or to repay corporate debt while maintaining control of the use of the power plants during the terms of the leases. See further
discussion of these sale-leaseback transactions under "Management's Discussion and Analysis of Results of Operations and Financial Condition-Off-Balance Sheet Financing."
Homer City Facilities
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. These facilities consist of three coal-fired steam turbine units, one coal preparation facility, an 1,800-acre site and associated support facilities in the mid-Atlantic region of the United States and have 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. For further discussion of the risks related to the sale of electricity from the Homer City facilities, see "Management's Discussion and Analysis of Results of Operations and Financial Condition-Market Risk Exposures."
On December 7, 2001, our subsidiary completed a sale-leaseback of the Homer City facilities to third-party lessors. We sold the Homer City facilities and entered into long-term leases to provide capital to repay corporate debt while maintaining control of the use of the facilities during the terms of the leases. See "Management's Discussion and Analysis of Results of Operations and Financial Condition-Off-Balance Sheet Financing."
Major Investments in California Cogeneration Projects
We own partnership investments in the Kern River Cogeneration Company, Midway Sunset Cogeneration Company, Sycamore Cogeneration Company and Watson Cogeneration Company, as described below. These projects have similar economic characteristics and have been used, collectively, to obtain bond financing by a special purpose entity, Edison Mission Energy Funding Corp., a special purpose entity that we include in our consolidated financial statements. Due to similar economic characteristics and the bond financing related to our equity investments, we view these projects collectively and refer to them as the Big 4 projects.
Kern River Project-We own a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which we refer to as the Kern River project. Kern River Cogeneration sells electricity to Southern California Edison Company under a power purchase agreement that expires in 2005 and sells steam to Texaco Exploration and Production Inc. under a steam supply agreement that also expires in 2005.
Midway-Sunset Project-We own a 50% partnership interest in Midway Sunset Cogeneration Company, which owns a 225 MW natural gas-fired cogeneration facility located near Taft, California, which we refer to as the Midway-Sunset project. Midway-Sunset sells electricity to Southern California Edison, Aera Energy LLC and Pacific Gas & Electric Company under power purchase agreements that expire in 2009 and sells steam to Aera under a steam supply agreement that also expires in 2009.
Sycamore Project-We own a 50% partnership interest in Sycamore Cogeneration Company, which owns and operates a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California, which we refer to as the Sycamore project. Sycamore Cogeneration sells electricity to Southern California Edison under a power purchase agreement that expires in 2007 and sells steam to Texaco Exploration and Production Inc. under a steam supply agreement that also expires in 2007.
Watson Project-We own a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural gas-fired cogeneration facility located in Carson, California, which we refer to as the Watson project. Watson Cogeneration sells electricity to Southern California Edison and to the adjacent British Petroleum refinery under power purchase agreements that expire in 2008 and sells steam to ARCO Products Company under a steam supply agreement that also expires in 2008.
We have a partnership interest in Sunrise Power Company that resulted from our efforts to add additional capacity in California in response to the California power crisis. See "Management's Discussion and Analysis of Results of Operations and Financial Condition-The California Power Crisis."
Sunrise Project-We own a 50% partnership interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern County, California, which we refer to as the Sunrise project. The Sunrise project consists of two phases. Phase I, a simple-cycle gas-fired facility (320 MW) was completed on June 27, 2001. Phase II, conversion to a combined-cycle gas-fired facility (560 MW), is currently scheduled to be completed in July 2003. Sunrise Power entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. For further discussion related to this agreement, see "Legal Proceedings-Sunrise Regulatory Proceedings."
Other Small Investments in Energy Projects
We also own 50% investments in seven other small energy projects (less than 100 MW of net electric capacity) that are located in the United States. Each project sells electricity under a long-term power purchase agreement with the local electric utility.
Americas Projects Offered For Sale
Our remaining projects in the Americas region consist of our Brooklyn Navy Yard, Gordonsville and EcoEléctrica projects described below. We are currently offering all of our interests in these projects for sale.
Brooklyn Navy Yard Project-We own a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners L.P., which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York, which we refer to as the Brooklyn Navy Yard project. Brooklyn Navy Yard sells electricity and steam to Consolidated Edison Company of New York, Inc. under a power purchase agreement that expires in 2039. See "Legal Proceedings-PMNC Litigation" for information regarding disputes related to the construction of this facility.
Gordonsville Project-We own a 50% partnership interest in Gordonsville Energy, L.P., which owns a 240 MW natural gas-fired cogeneration facility located in Gordonsville, Virginia, which we refer to as the Gordonsville project. Gordonsville Cogeneration sells electricity to Virginia Electric & Power Company under a power purchase agreement that expires in 2024 and sells steam to Rapidan Service Authority under a steam supply agreement that also expires in 2024.
EcoEléctrica Project-We own a 50% partnership interest in EcoEléctrica L.P., which owns a 540 MW power plant located Peñuelas, Puerto Rico, which we refer to as the EcoEléctrica project. EcoEléctrica sells electricity to Puerto Rico Electric Power Authority under a power purchase agreement that expires in 2018 and sells water to Puerto Rico Water & Sewer Authority under a water supply agreement that also expires in 2018.
Asset Sales
During 2001, we decided to offer for sale some of our non-strategic investments in energy projects to reduce debt. At December 31, 2001, we had agreements to sell five of our projects. Subsequent to December 31, 2001, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project. The sales of our interests in the EcoEléctrica and Gordonsville projects did not close, and in each case, the sales agreement has terminated and we have recommenced marketing efforts. On March 8, 2002, we filed a complaint against Mirant Corporation and two of its affiliates, alleging that Mirant wrongfully terminated the sale agreement for the purchase of the EcoEléctrica project. See "Management's Discussion and Analysis of Results of Operations and Financial Condition-Dispositions" for further details about our asset sales.
Investment in Four Star Oil and Gas Company
We own a 37.2% direct and indirect interest, with 36.05% voting stock, in Four Star Oil and Gas Company, with majority control held by affiliates of ChevronTexaco Corp. Four Star Oil and Gas owns oil and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and Alabama. Under a long-term service contract, the majority of Four Star Oil and Gas's properties are operated through Texaco Exploration & Production Inc. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements-Note 7. Investments" for financial information on our oil and gas investments.
Asia-Pacific
As of December 31, 2001, we had 15 operating projects in this region that are located in Australia, Indonesia, Thailand and New Zealand. Our Asia-Pacific region is headquartered in Singapore, with additional offices located in Australia, Indonesia and the Philippines. A description of our power plants, investment in Contact Energy and investments in energy projects in the Asia-Pacific region is set forth below.
Australia
Loy Yang B Project-We own a 1,000 MW coal-fired power station in located in Traragon, Victoria, Australia, which we refer to as the Loy Yang B project. The project sells electricity to 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 spot price each half-hour. We have entered into an agreement with the State Electricity Commission of Victoria, which agreement we refer to as the State Hedge, that provides through October 16, 2016 for the project to receive a fixed price for a portion of its electricity in exchange for payment to the State of the spot price applicable to such portion. For further discussion of risks related to the sale of electricity from the Loy Yang B project, see "Management's Discussion and Analysis of Results of Operations and Financial Condition-Market Risk Exposures."
Valley Power Peaker Project-During 2001, we began construction of a 300 MW gas-fired peaker plant located at the Loy Yang B coal-fired power plant site, which we refer to as the Valley Power Peaker project. The peaker units will service peaking demand within the National Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the peakers directly into the pool and by entering into financial contracts related to pool prices with other power generators and distribution businesses. We own a 60% interest in the Valley Power Peaker project, with the remaining interest held by our 51.2%-owned affiliate, Contact Energy.
Kwinana Project-We own a 70% interest in a 116 MW gas-fired cogeneration plant in Perth, Australia, which we refer to as the Kwinana project. We sell electricity to Western Power under a power purchase agreement that expires in 2021 and sell steam to the British Petroleum Kwinana refinery under a steam supply agreement which also expires in 2021.
New Zealand
Contact Energy-We own a 51.2% majority interest in Contact Energy Limited. The remaining shares of Contact Energy are publicly held and traded on the New Zealand stock exchange. Contact
Energy is the largest wholesaler and retailer of natural gas in New Zealand and generates about one-quarter of New Zealand's electricity. Contact Energy owns the following power plants:
(1)Located in Australia.
Contact Energy also owns a 40% interest in the Valley Power Peaker project under construction in Australia with the remaining interest held by a wholly-owned subsidiary of ours.
Indonesia
The Paiton Project-We own a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia, which we refer to as the Paiton project. Paiton Energy sells electricity to PT PLN, the state-owned electric utility company, under a power purchase agreement that expires in 2029. PT PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN as well as settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the terms of the power purchase agreement from 2029 to 2039. For a further discussion of the Paiton project, see "Management's Discussion and Analysis of Results of Operations and Financial Condition-Contingencies."
Philippines
CBK Project-In February 2001, we purchased a 50% interest in CBK Power Co. Ltd. CBK Power has entered into a 25-year build-rehabilitate-operate-transfer (BROT) agreement with National Power Corporation related to the 728 MW Caliraya-Botocan-Kalayaan hydroelectric project located in the Philippines, which we refer to as the CBK project. CBK Power is paid capital recovery fees and operations and maintenance fees for generating electricity and providing other services under the BROT agreement. At December 31, 2001, 168 MW have been commissioned and are operational.
Thailand
Tri Energy Project-We own a 25% interest in Tri Energy Company Limited, which owns a 700 MW gas-fired cogeneration plant located west of Bangkok, Thailand, which we refer to as the Tri Energy project. Tri Energy sells electricity to Electricity Generating Authority of Thailand, which is known as EGAT, under a power purchase agreement that expires in 2020.
Europe and Middle East
As of December 31, 2001, we had 34 operating projects in this region that are located in the U.K., Turkey, Spain and Italy. Our Europe and Middle East region is headquartered in London, England, with additional offices located in Italy, Spain and Turkey. The London office was established in 1989. A description of our power plants and investments in energy projects in the Europe and Middle East region is set forth below.
United Kingdom
First Hydro Project-We own two pumped storage stations in North Wales at Dinorwig and Ffestiniog which have a combined capacity of 2,088 MW, which we refer to as the First Hydro project. Pump storage stations consume electricity when it is comparatively less expensive in order to pump water up for storage in an upper reservoir. Water is then allowed to flow back through turbines in order to generate electricity when its market value is higher. We sell electricity and ancillary services to regional electricity companies, other generators and into short-term markets. For further discussion of the risks related to the sale of electricity from the First Hydro project, see "Management's Discussion and Analysis of Results of Operations and Financial Condition-Market Risk Exposures."
Lakeland Project-We own a 220 MW combined-cycle natural gas-fired power plant located in Barrow-in-Furness, Cumbria, United Kingdom, which we refer to as the Lakeland project. We sell electricity to North Western Electricity Board under a power purchase contract that expires in 2006.
Derwent Project-We own a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW gas-fired cogeneration plant in Derby, England, which we refer to as the Derwent project. Derwent sells electricity to Southern Electric plc under a power purchase agreement that expires in 2010 and sells steam to Courtaulds Chemicals (Holdings) Limited under a steam supply contract that also expires in 2010.
Italy
ISAB Project-We own a 49% interest in ISAB Energy S.r.l. which owns a 512 MW integrated gasification combined cycle power plant in Sicily, Italy, which we refer to as the ISAB project. ISAB sells electricity to Gestore Rete Transmissione Nazionale, Italy's state transmission company, under a power purchase agreement that expires in 2020. The ISAB project is located at an oil refinery owned by ERG Petroli SpA.
Italian Wind Project-In 2000, we purchased Edison Mission Wind Power Italy B.V., which owns a 50% interest in a series of power projects that are in operation or under development in Italy by UPC International Partnership CV II, which we collectively refer to as the Italian Wind project. The projects use wind to generate electricity from turbines, which is sold under fixed-price, long-term tariffs to Gestore Rete Transmissione Nazionale. At December 31, 2001, 230 MW have been commissioned and are operational. Assuming all the projects under construction at December 31, 2001 are completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW.
Spain
Spanish Hydro Project-We own 18 small, run-of-the-river hydroelectric plants regionally dispersed in Spain totaling 86 MW, which we refer to as the Spanish Hydro project. We sell electricity to Fuerzas Electricas de Cataluma, S.A. under concessions that have various expiration dates ranging from 2030 to 2065.
Turkey
Doga Project-We own an 80% interest in Doga Enerji, which owns a 180 MW gas-fired cogeneration plant in Istanbul, Turkey, which we refer to as the Doga project. Doga Enerji sells electricity to Turkiye Elektrik Urehm, A.S., commonly known as TEAS, under a power purchase agreement that expires in 2018.
In addition to the facilities and power plants that we own, we use the term "our" in regard to facilities and power plants that we operate under sale-leaseback arrangements.
Discontinued Operations
As a result of the change in the prices of power in the U.K. and the anticipated negative impacts of such changes on earnings and cash flow, we offered for sale through a competitive bidding process
the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in our consolidated financial statements. See, "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements-Note 6. Discontinued Operations."
Trading and Risk Management Activities
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 general policy to deal with investment grade counterparties or counterparties that have equivalent credit quality. Our risk management committees grant exceptions to the policy only after review and scrutiny. Most entities that have received exceptions are typically organized power pools and quasi-governmental agencies. We hedge a portion of the electric output of our merchant plants in order to provide more predictable earnings and cash flow. 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 domestic power marketing and trading organization, Edison Mission Marketing & Trading, Inc., markets and trades electric power and energy related to commodity products, including forwards, futures, options and swaps. It also provides services and price risk management capabilities to the electric power industry. We segregate our activities into two categories:
•Marketing and Fuel Management-Edison Mission Marketing & Trading engages in the sale of electricity and purchase of fuels through intercompany contracts with our subsidiaries that own or lease the Illinois plants and the Homer City facilities. The objective of these activities is to sell the output of the power plants on a forward basis, thereby increasing the predictability of earnings and cash flows. Edison Mission Marketing & Trading also conducts risk management activities to manage the price risk associated with the purchase of fuels, including natural gas and fuel oil. Transactions entered into related to marketing and fuel management activities are designated separately from Edison Mission Marketing & Trading's trading activities and recorded in what Edison Mission Marketing & Trading calls its hedge book (we record these transactions on an accrual basis unless fair value accounting is required). •Trading-In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. Edison Mission Marketing & Trading generally balances forward sales and purchases contracts and manages its exposure through a value at risk analysis, as described further below. Edison Mission Marketing & Trading also conducts price risk management activities for third parties including restructuring of power sales and power supply agreements. Collectively, Edison Mission Marketing & Trading refers to these as its trading activities and records these transactions in what it calls its proprietary book.
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. Edison Mission Marketing & Trading has systems in place which monitor real time spot and forward pricing and perform option valuations. Edison Mission Marketing & Trading also has a wholesale power scheduling group that operates on a 24-hour basis.
Internationally, we also conduct price risk management activities through subsidiaries that are primarily focused on marketing and fuel management activities in the same manner described above.
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 stress testing and worst-case scenario analysis, as well as stop limits and counterparty credit exposure limits.
Seasonality
Due to warmer weather during the summer months, electric revenues generated from the Homer City facilities 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 the summer months. The First Hydro plants and the Iberian Hy-Power plants provide for higher electric revenues during the winter months.
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 operating 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 facilities, the Illinois plants, and Brooklyn Navy Yard 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 ultimate 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 might develop or 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 MW 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 from 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 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-Many 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, California Deregulation and Recent Foreign Regulatory Matters
See the discussion on state regulation, California deregulation and recent foreign regulatory matters in "Management's Discussion and Analysis of Results of Operations and Financial Condition-The California Power Crisis," and "Management's Discussion and Analysis of Results of Operations and Financial Condition-Market Risk Exposures."
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.
In issuing Order No. 888 et al., the Federal Energy Regulatory Commission determined that the open-access rules set forth in the Order would apply to transmission with respect to wholesale sales and also with respect to retail transactions where the transmission component had been unbundled from the
retail sale by state regulatory action or voluntarily by the utility making the retail sale. The Commission declined to assert jurisdiction over retail transmission that remained bundled into the retail sale. Subsequent court appeals of Order No. 888 have been brought by parties challenging the Order on the basis that the Commission had no authority to regulate the transmission of unbundled retail sales and by those challenging the Commission's failure to include the transmission of bundled retail sales in the order. On June 30, 2000, the U.S. Court of Appeals for the District of Columbia Circuit upheld the decision by the Federal Energy Regulatory Commission in both respects, finding that the Commission did have jurisdiction to regulate transmission of unbundled retail transactions, and that it was not required to assert jurisdiction over transmission embedded in bundled retail sales. In an opinion issued on March 4, 2002, the Supreme Court affirmed the decision of the Court of Appeals.
In the meantime, while Order No. 888 was pending judicial review, it became apparent to the Federal Energy Regulatory Commission that the Order was not having the desired effects of eliminating discriminatory behavior by transmission owning utilities and in promoting the development of competitive wholesale electricity markets. Accordingly, in an effort to remedy the shortcomings it perceived, the Commission, on December 20, 1999, issued Order No. 2000, which required all transmission-owning utilities to file by December 15, 2000, a statement of their plans with respect to placing their transmission assets under a Regional Transmission Organization, or RTO, meeting certain criteria set forth in the Order. Although Order No. 2000 did not mandate that a utility join an RTO, it set forth various incentives for voluntary action by utilities to take such action and required them to explain in detail their reasons for deviating from the objectives set forth in the Order. RTOs meeting the Commission's criteria in Order No. 2000 were required to be operationally independent of the transmission-owning utilities whose assets they controlled and to possess other essential attributes, such as regional scope and configuration, the authority to receive and rule upon requests for service, a separate tariff governing all transactions of the RTO, a market monitoring capability, and other features. In subsequent orders, the Commission has progressively tightened its policies in favor of RTO formation, by such means as an explicit proposal that approvals of market-based rate authority for affiliates of utilities owning transmission should be tied to such utilities' placing their transmission assets in an RTO meeting the criteria of Order No. 2000. These and other regulatory initiatives by the Federal Energy Regulatory Commission are ongoing, and it is not possible to predict the extent of future developments. However, the direction of regulatory policy at the Commission appears generally positive for continued progress toward competitive wholesale electricity markets.
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.
Environmental Matters and Regulations
See discussion on environmental matters and regulations in "Management's Discussion and Analysis of Results of Operations and Financial Condition-Environmental Matters and Regulations."
Employees
At December 31, 2001, Edison Mission Energy employed 3,021 people, all of whom were full-time employees and 188, 152 and 1,236 of whom were covered by collective bargaining agreements in the United Kingdom, Australia and the United States, respectively. We believe we have good relations with our employees.
Between early June and mid-October of 2001, our subsidiary, Midwest Generation, and the union that represents the employees at the Illinois plants were in negotiations to replace the expired collective bargaining agreement, covering wages and working conditions. The union authorized a strike that began on June 28, 2001. Midwest Generation operated the Illinois plants during the strike. Negotiations have concluded with a new four-year agreement that was ratified by the represented employees on October 16, 2001. Pursuant to the reinstatement process, employees began returning to work on October 22, 2001.
Our Relationship with Certain Affiliated Companies
Edison Mission Energy is an indirect subsidiary of Edison International. Edison International is a holding company. Edison International is also the corporate parent of Southern California Edison, an electric utility that buys and sells power in California. Southern California Edison has faced material operating disruptions as a result of the California power crisis. For a description of the California power crisis, see "Management's Discussion and Analysis of Results of Operations and Financial Condition-The California Power Crisis."
Tax Sharing Agreement
We are also 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.
ITEM 2.
ITEM 2. PROPERTIES
We lease our principal office in Irvine, California. This lease covers 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 for approximately 41,000 square feet and expires on December 31, 2009. The Chantilly lease is for approximately 30,000 square feet and expires on March 31, 2010. The Boston lease is for approximately 40,500 square feet and expires on July 31, 2007. Both the Fairfax and the Washington D.C. leases are immaterial. At December 31, 2001, approximately 31% of the 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 and Middle East region lease office space in Barcelona, Spain; Istanbul, 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 projects. 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. Most of these properties are subject to mortgages or other liens or encumbrances granted to the lenders providing financing for the plant or project.
Description of Properties
(1)Currently offered for sale.
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 for the project 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. On February 14, 2002, PMNC moved to amend the complaint in the New York action to add us as a defendant and to seek a $43 million attachment against us. This motion is presently calendared for May 2002. 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.
EcoEléctrica Potential Environmental Proceeding
We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquified natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoEléctrica 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 EcoEléctrica. 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 are currently offering our interest in the EcoEléctrica project for sale.
Sunrise Regulatory Proceedings
Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleges that the contracts are "unjust and unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board complaint makes a similar allegation and requests that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. In response, on March 19, 2002, Sunrise filed a motion to dismiss with the Federal Energy Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion; however, we cannot predict what actions the Federal Energy Regulatory Commission may take at this proceeding.
Paiton Labor Suit
In April 2001, Paiton Energy was sued in the Central Jakarta District Court by the PLN Labor Union. PT PLN, the Indonesian Minister of Mines and Energy and the former President Director of PT PLN are also named as defendants in the suit. The union seeks to set aside the power purchase agreement between Paiton Energy and PT PLN and the interim agreement then in effect between Paiton Energy and its lenders, as well as damages and other relief. The initial preliminary hearing was held on April 30, 2001 in Jakarta. Paiton Energy and the other defendants filed challenges to jurisdiction and moved for a dismissal of the suit, but such actions were denied by an order dated July 23, 2001. Paiton Energy has filed a notice of appeal. Paiton Energy believes, based upon discussions with its Indonesian counsel, that the suit is without merit.
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 Mission Energy Holding Company, which is a wholly-owned subsidiary of The Mission Group, 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 $65 million and $88 million during 2001 and 2000, respectively, and after our change in ownership to Mission Energy Holding Company, we made cash dividend payments totaling $32.5 million in 2001.
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 investment grade ratings with respect to our senior unsecured long-term debt and receive rating agency confirmation that the dividend or distribution will not result in a downgrade; or
•such dividends and distributions 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.
Our interest coverage ratio for the four quarters ended December 31, 2001 was 1.64 to 1. Accordingly, until our interest coverage ratio exceeds 2.2 to 1 for the immediately preceding four quarters, we can only pay dividends if we have an investment grade rating and have received rating agency confirmation that a dividend will not result in a downgrade or have received unanimous approval of our board of directors, including our independent director. 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 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. No securities have been redeemed as of December 31, 2001. 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, with mandatory redemption in 2025 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have been redeemed as of December 31, 2001. 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 our common stock if at such time (i) we shall be in default with respect to our 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 our selection of an extended interest payment period as provided in the indenture and such period, or any extension thereof, shall be continuing.
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 "-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, 2001, we owned interests in 31 domestic and 49 international operating power projects with an aggregate generating capacity of 23,967 MW, of which our share was 19,019 MW. At that date, one domestic and six international projects, totaling 1,153 MW of generating capacity, of which our anticipated share will be approximately 668 MW, were under construction. At December 31, 2001, we had consolidated assets of $10.7 billion and total shareholder's equity of $1.6 billion.
Our operating revenues are derived primarily from electric revenues and equity in income from power projects. Electric revenues accounted for 85%, 89% and 79% of our total operating revenues during 2001, 2000 and 1999, respectively. Our consolidated operating revenues during those years also include equity in income from oil and gas investments, net gains (losses) from energy trading and price risk management activities and revenues attributable to operation and maintenance services.
Our current strategy is focused on strengthening our balance sheet through the selective disposition of assets, enhancing the performance of our existing portfolio of power projects and aligning our staffing needs to meet these objectives.
Acquisitions, Dispositions and Sale-Leaseback Transactions
Acquisition of Interest in CBK Power Co. Ltd.
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 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project comprises equity commitments of $110.6 million, of which our 50% share is $55.3 million, and debt financing which is in place for the remainder of the cost for this project. As of December 31, 2001, we have made equity contributions of $10 million. For a more detailed discussion of the commitment to contribute project equity, refer to "-Contractual Obligations, Commitments and Contingencies-Firm Commitments to Contribute Project Equity."
Acquisition of Sunrise Project
On November 17, 2000, we completed a transaction with Texaco Power & Gasification Holdings 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 had an option to repurchase, at cost, a 50% interest in the project prior to its commercial operation, which commenced on June 27, 2001. On June 25, 2001, Texaco exercised its option and repurchased a 50% interest for $84 million. As part of our acquisition of the Sunrise project, we also: (i) acquired from Texaco two gas turbines for the project and (ii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future power plant projects we designate. The Sunrise project consists of two phases, with Phase I, a simple-cycle gas-fired facility (320 MW), completed on June 27, 2001, and Phase II, conversion to a combined-cycle gas-fired facility (560 MW), currently scheduled to be completed in July 2003. We entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. See "-Legal Proceedings-Sunrise Regulatory Proceedings."
The total purchase price of the Sunrise project from Texaco was $27 million. We funded the purchase with cash. The total estimated construction cost of this project through 2003 is approximately $459 million. The project intends to obtain project financing for a portion of the capital costs.
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 operations beyond the traditional marketing of our electric power to include trading of electricity and fuels, although this represents a small portion of our consolidated operations. 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 Project
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. At December 31, 2001, 230 MW have been commissioned and are operational. Assuming all the projects under construction at December 31, 2001 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, with equity contribution obligations of up to 33 billion Italian Lira, depending on the number of projects that are ultimately developed. As of December 31, 2001, our payments in respect of these projects included 77 billion Italian Lira ($37.4 million) toward the purchase price and 33 billion Italian Lira ($16.3 million), which funded our entire equity contribution obligation.
Acquisition of Illinois Plants
On December 15, 1999, we completed a transaction with Commonwealth Edison, now 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 are located in the
Mid-America Interconnected Network which has transmission connections to the East Central Area Reliability Council and other regional markets. In connection with this transaction, we entered into three power purchase agreements with Commonwealth Edison with terms of up to five years expiring in 2004, 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. Exelon Generation provided us notice to continue the agreement related to the coal units and the Collins Station for 2002. In October 2001, Exelon Generation terminated the power purchase agreement for the peaker units with respect to 300 megawatts of oil peakers, effective January 2002, but continued the agreement for all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.
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 MW 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 our debt and $1.2 billion in equity contributions to us from Edison International.
Acquisition of Interest in Contact Energy
On May 14, 1999, we completed a transaction with the New Zealand government to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of Contact Energy's shares were sold in a New Zealand and 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. 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 2,302 MW.
Consideration for our interest in Contact Energy consisted of a cash payment of approximately $635 million (NZ$1.2 billion), which was financed by $120 million of preferred securities, a $214 million (NZ$400 million 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.
During 2000, we increased our share of ownership in Contact Energy to 42.6%. Subsequently, during the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to 51.2%. Due to acquisition of a controlling interest, we began accounting for Contact Energy on a consolidated basis effective June 1, 2001. Prior to June 1, 2001, we used the equity method of accounting for Contact Energy. In order to finance the purchase of the additional shares, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which was syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held by us has been provided as collateral. On July 2, 2001, we redeemed NZ$400 million preferred securities issued by one of our subsidiaries, EME Taupo. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing documents
provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally funded as a revolving credit facility. From June 2001 to October 2001, we issued NZ$250 million of new preferred securities through one of our subsidiaries. The proceeds were used to repay borrowings outstanding under the NZ$400 million credit facility and to repay the bridge loan.
On October 12, 2001, we announced our intention to acquire the remaining 48.8% of Contact Energy that we do not own, thereby increasing our ownership interest to 100%. We proposed an offer of NZ$4.25 per share, including an interim dividend of NZ$0.11 per share, to the minority shareholders payable in cash. The offer commenced on November 6, 2001 and was extended until February 3, 2002. The offer was conditioned on our acquiring a 90% interest in Contact Energy, which would have enabled us to acquire the remaining minority interests through a merger. On February 4, 2002, we announced that we did not receive the necessary level of acceptances required to complete the transaction, and, therefore, we currently plan to continue with our current 51.2% ownership interest.
Acquisition of Homer City Facilities
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 facilities 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.
On December 7, 2001, we sold the Homer City facilities to third party lessors in a sale-leaseback transaction. See "-Sale-Leaseback Transactions" and "-Off-Balance Sheet Financing."
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 Sunrise beginning July 1, 2001, Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, the Homer City facilities beginning March 18, 1999, Contact Energy beginning May 1, 1999, and the Illinois plants beginning December 15, 1999. We began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest.
Dispositions
On December 21, 2001, we completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements. See "-Discontinued Operations." The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.148 billion after tax) related to the loss on disposal. Net proceeds from the sales of £643 million
were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants.
During 2001, we also sold our 50% interest in the Nevada Sun-Peak project, 50% interest in the Saguaro project and 25% interest in the Hopewell project for a total gain on sale of $45 million ($24.4 million after tax). In addition, we entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our interests in the Commonwealth Atlantic, EcoEléctrica, Gordonsville, Harbor and James River projects. During 2001, we recorded asset impairment charges of $33.7 million related to the Commonwealth Atlantic, Gordonsville, Harbor and James River projects based on the expected sales proceeds. Subsequent to December 31, 2001, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project for $47.7 million. The sales of our interests in the EcoEléctrica and Gordonsville projects have not closed, and in each case, the sales agreement has terminated and we have recommenced marketing efforts. On March 8, 2002, we filed a complaint against Mirant Corporation and two of its affiliates, alleging that Mirant wrongfully terminated the sale agreement for the purchase of the EcoEléctrica project. We are currently offering for sale our interests in the Brooklyn Navy Yard, EcoEléctrica and Gordonsville projects.
On June 25, 2001, we completed the sale of a 50% interest in the Sunrise project to Texaco Power & Gasification Holdings Inc. Proceeds from the sale were $84 million.
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 December 7, 2001, our subsidiary completed a sale-leaseback of our Homer City facilities to third-party lessors for an aggregate purchase price of $1.591 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809.3 million). Under the terms of the 33.67-year leases, our subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, we have a right of first refusal to acquire the interest at fair market value. Minimum lease payments during the next five years are $175.0 million for 2002, $174.0 million for 2003, $142.1 million for 2004, $151.9 million for 2005, and $151.6 million for 2006. At December 31, 2001, the total remaining minimum lease payments are $3.4 billion. Lease costs will be levelized over the terms of the leases. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.
On August 24, 2000, our subsidiary completed a sale-leaseback of our 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, which began January 2, 2001. We guarantee our subsidiary's payments under these 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 $97.3 million for 2002, $97.3 million for 2003, $97.3 million for 2004, $141.1 million for 2005, and $184.9 million for 2006. At December 31, 2001, the total remaining minimum lease payments are $2.3 billion. Lease costs of these power facilities will be levelized over the terms of the respective leases. The gain 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 the London Interbank Offered Rate, commonly referred to as LIBOR, plus 0.65% to 0.95%, depending on our credit rating. The notes are due and payable in 2005. The gain on the sale of equipment has been deferred and is being amortized over the term of the lease.
For more information on these sale-leaseback transactions, see "-Off-Balance Sheet Transactions-Sale-Leaseback Transactions."
Mission Energy Holding Company
On June 8, 2001, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset is our common stock. In July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security interest in our common stock. Any foreclosure on the pledge of our common stock by the holders of the senior secured notes or the lenders under the term loan could result in a change of control of us. A change in control of us could require us or our subsidiaries to prepay indebtedness in our or their debt agreements. For a discussion of the provisions in our formation documents that constrain our ability to pay dividends or make distributions to Mission Energy Holding, see "-Credit Ratings".
The respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with respect to our stock are governed by intercreditor arrangements. Both the senior secured notes and the term loan also have security interests in interest reserve accounts, covering the interest payable on those obligations for the first two years. We have not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to us. The net proceeds of the offering and the term loan not deposited into the respective interest escrow accounts were used to pay a dividend to Mission Energy Holding's parent, The Mission Group, which in turn loaned the net proceeds to its parent, Edison International. Edison International used the funds to repay a portion of its indebtedness that matured in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and the ability of our subsidiaries to enter into specified transactions or engage in specified business activities and require, in some instances, that we obtain the approval of the Mission Energy Holding's board of directors. Our articles of incorporation bind us to the restrictions in Mission Energy Holding's financing documents by restricting our ability to enter into specified transactions or engage in specified business activities, other than as permitted in Mission Energy Holding's financing documents, without shareholder approval.
RESULTS OF OPERATIONS
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.
As an aid in an understanding of our results of operations, the following table summarizes revenues and operating income during the past three years from major projects (in millions):
(1)Represents percentage of our consolidated operating revenues or operating income before Corporate general and administrative expenses, interest and other expenses not reflected in our regional operations, as applicable.
(2)Comprised of investments in Kern River project, Midway-Sunset project, Sycamore project and the Watson project. These projects are recorded on the equity method of accounting which means that we record our share of the income or loss from each partnership.
(3)Four Star is comprised of our equity in income from our investment in Four Star Oil and Gas Company and price risk management activities described under Americas below. We operate predominantly in one line of business, electric power generation, with reportable segments organized by geographic regions: Americas, Asia-Pacific and Europe and Middle East. The following discussion of our operating results is set forth by region with reference to the performance of our major projects described above.
Americas
Operating Revenues
Operating revenues increased $42.1 million in 2001 compared to 2000, and increased $1.2 billion in 2000 compared to 1999. The 2001 increase resulted from higher electric revenues from the Homer City facilities due to higher energy prices, as compared to the prior year. This increase was partially offset by lower electric revenues from the Illinois plants in 2001 due to lower dispatch of their coal units as a result of lower market prices for power. The 2000 increase resulted from a full-year of electric revenues from the Illinois plants acquired in December 1999 and the Homer City facilities acquired in March 1999.
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 each of the years ended December 31, 2001 and 2000. This represented 36% and 42% of our consolidated operating revenues in 2001 and 2000, respectively. For more information on these power purchase agreements, see "-Market Risk Exposures-Illinois Plants" and "-Risk Factors."
Net gains from energy trading activities were $10 million in 2001 and $62.2 million from September 1, 2000, the acquisition date of Citizens Power, to December 31, 2000. The 2001 decrease in gains primarily resulted from a reduction in our trading activity in 2001, as compared to 2000, due to volatility of power prices in the West Coast trading markets during the fourth quarter of 2000 and the adverse impact of the California power crisis on our credit in 2001.
Total gains and losses from price risk management activities recorded at fair value under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133) were $25.3 million, ($79.5) million and ($6.4) million in 2001, 2000 and 1999, respectively. The 2001 gain was primarily due to realized and unrealized gains for a gas swap purchased to hedge 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 transactions of investments accounted for on the equity method, and thus, we were required to record changes in fair value of these positions through the income statement (commonly referred to as mark-to-market accounting). During 2000, we recorded a loss on these gas swaps of $87 million due to a substantial increase in gas prices in the fourth quarter of 2000. As gas prices decreased in 2001, we recorded a gain of $44.7 million on these positions resulting in a year-over-year increase in our earnings in 2001 from 2000 of $131.7 million. Partially offsetting this gain in 2001 was a
loss resulting from the change in market value of future contracts entered into with respect to a portion of our anticipated fuel purchases through 2002 at the Illinois plants that did not qualify for hedge accounting under SFAS No. 133.
The 2000 losses from price risk management activities recorded at fair value increased from 1999 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 discussed above. Partially offsetting the 2000 loss was a gain realized on financial options entered into beginning August 2000 as a hedge of our price risk associated with expected natural gas purchases at the Illinois plants for 2001. 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 was deferred as required by hedge accounting and was recognized during 2001 based on the date of the occurrence of the original anticipated transaction. 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 of 2000. 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 increased $96.1 million in 2001 over 2000, and increased $32.4 million in 2000 over 1999. The 2001 increase was primarily the result of higher revenues from cogeneration projects due to higher energy pricing on the West Coast during 2001 and revenues from the Sunrise project, which commenced operations in June 2001. We had no comparable results for the Sunrise project in 2000. 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.
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 2001, 2000 and 1999 are with Southern California Edison. Our share of equity in earnings from these projects accounted for 8% in 2001, 6% in 2000 and 10% in 1999 of our consolidated revenues for the respective years. For more information on these projects and other projects in California, see "-Contractual Obligations, Commitments and Contingencies-The California Power Crisis."
Due to warmer weather during the summer months, electric revenues generated from the Homer City facilities 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 costs increased $33.6 million in 2001 compared to 2000, and increased $893.9 million in 2000 compared to 1999. The 2001 increase was primarily due to an increase in plant operations at the Illinois plants, partially offset by lower fuel costs at these plants. The 2001 increase in plant operations resulted from lease costs related to the sale-leaseback commitments for the Powerton-Joliet power facilities and the Collins gas and oil-fired power plant. There were no comparable lease costs for the Powerton-Joliet power facilities through the period ended August 2000. See "-Off-Balance Sheet Transactions-Sale-Leaseback Transactions" for discussion of the financial impact
of sale-leaseback transactions. In addition, plant operations costs increased due to higher maintenance costs at the Illinois plants in 2001 from planned outages and costs of additional security related to a strike at the Illinois plants during June through October 2001. Fuel costs were lower at the Illinois plants in 2001 due to less dispatch of their coal units as compared to 2000 and decreased generation from the Collins Station and peaker plants. The 2000 increase resulted from a full year of expenses at the Illinois plants and the Homer City facilities.
Depreciation and amortization expense decreased $24 million in 2001 compared to 2000, and increased $138.7 million in 2000 compared to 1999. The 2001 decrease resulted from lower depreciation expense at the Illinois plants related to the sale-leaseback transaction for the Powerton-Joliet power facilities with third-party lessors on August 24, 2000. The 2000 increase was primarily due to a full year of depreciation and amortization expense related to the Illinois plants.
Asset impairment and other charges of $59.1 million consisted of $33.7 million to write down our investments to the estimated net proceeds from the planned sale of the Commonwealth Atlantic, Gordonsville, Harbor and James River projects and $25.4 million related to a loss on the termination of a portion of the Edison Mission Energy Master Turbine Lease. For more information on the termination of the lease, see "-Contractual Obligations, Commitments and Contingencies-Edison Mission Energy-Master Turbine Lease." There were no comparable asset impairment and other charges for the same prior year periods.
Administrative and general expenses consist of administrative and general expenses incurred at our trading operations in Boston, Massachusetts and a provision for bad debts. In 2001, we recorded a provision of $8.5 million for bad debts from Enron as a result of its bankruptcy. The 2001 increase also included a full year of trading operations partially offset by higher bonuses during 2000. Prior to the September 1, 2000 acquisition of Citizens Power, administrative and general expenses incurred by our own marketing operations were reflected in Corporate/Other administrative and general expenses.
Operating Income
Operating income increased $110.7 million in 2001 compared to 2000, and increased $160.2 million in 2000 compared to 1999. The 2001 increase was primarily due to increases in operating income from the Homer City facilities, equity in income from investments in energy projects and gains from price risk management activities discussed above. The 2000 increase was primarily due to a full year of operating income from the Illinois plants and the Homer City facilities and increased equity in income from our oil and gas investments due to higher oil and gas prices.
Asia-Pacific
Operating Revenues
Operating revenues increased $280.2 million in 2001 compared to 2000, and decreased $29.4 million in 2000 compared to 1999. The 2001 increase was primarily due to consolidating Contact Energy operating revenues as a result of us acquiring a controlling interest in the company, effective June 1, 2001. Electric revenues generated by Contact Energy benefited in 2001 from higher energy prices in New Zealand caused by dry and cold conditions during the third quarter of 2001. The increase was partially offset by lower U.S. dollar electric revenues from the Loy Yang B plant in Australia due to a 11.1% decrease in the average exchange rate of the Australian dollar compared to the U.S. dollar during 2001, compared to 2000. The 2000 decrease was attributable to lower electric revenues from our Loy Yang B plant. During May 2000, we experienced a major unplanned outage due to damage to the generator at one of our two 500 MW units at the Loy Yang B power plant in Australia. The unit was restored to operation in September 2000. The repair costs in excess of our $2 million 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.
Net losses from price risk management activities recorded at fair value were $4.1 million in 2001. The losses primarily resulted from the change in the market value of interest rate swaps and options that did not qualify for hedge accounting under SFAS No. 133 and the ineffective portion of a long-term contract with the State Electricity Commission of Victoria entered into by the Loy Yang B plant, which is a derivative that qualified as a cash flow hedge under SFAS No. 133. See "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements-Note 4. Accumulated Other Comprehensive Income (Loss)" for further discussion.
Equity in income from investments decreased $7.1 million in 2001 compared to 2000, and decreased $3.5 million in 2000 compared to 1999. The 2001 decrease primarily reflects Contact Energy being accounted for on a consolidated basis effective June 1, 2001, compared to the equity method of accounting prior to the acquisition of a controlling interest. The 2000 decrease was primarily due to lower profitability of our interest in Contact Energy resulting from lower electricity prices caused by milder winter weather conditions.
Operating Expenses
Fuel and plant operations costs increased $204.4 million in 2001 compared to 2000, and decreased $12.3 million in 2000 compared to 1999. The 2001 increase was primarily due to consolidating Contact Energy operating expenses, effective June 1, 2001. The 2000 decrease resulted primarily from lower fuel costs at the Loy Yang B plant due to the major unplanned outage at one of its two 500 MW units.
Depreciation and amortization expense increased $16.9 million in 2001 compared to 2000, and decreased $5.5 million in 2000 compared to 1999. The 2001 increase primarily reflects the consolidation of Contact Energy depreciation and amortization expenses, effective June 1, 2001. The 2000 decrease was primarily due to favorable changes in foreign exchange rates.
Operating Income
Operating income increased $47.7 million in 2001 compared to 2000, and decreased $15.1 million in 2000 compared to 1999. The 2001 increase was primarily due to consolidating Contact Energy's results of operations, effective June 1, 2001, and the favorable impact of higher energy prices in New Zealand discussed above. The increase was partially offset by lower operating income from the Loy Yang B plant, resulting primarily from lower electric revenues due to a decrease in the value of the Australian dollar compared to the U.S. dollar. The 2000 decrease was due to lower operating income from the Loy Yang B plant resulting from the major unplanned 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.
Europe and Middle East (1)
(1)The results of Ferrybridge and Fiddler's Ferry are not included in this table since the operations are classified as discontinued operations for all historical periods presented. For more information on Ferrybridge and Fiddler's Ferry, see "-Discontinued Operations." Operating Revenues
Operating revenues decreased $86.3 million in 2001 compared to 2000, and increased $53.0 million in 2000 compared to 1999. The 2001 decrease resulted primarily from lower capacity revenues from the First Hydro plant. On March 27, 2001, the United Kingdom pool pricing system was replaced with a bilateral physical trading system referred to as the new electricity trading arrangements. The new electricity trading arrangements are described in further detail under "-Market Risk Exposures-United Kingdom." These new electricity trading arrangements resulted in lower capacity prices in 2001, compared to 2000. The 2000 increase resulted from a full year of electric revenues from the Doga project, which commenced commercial operation in May 1999, and by higher capacity revenues from the First Hydro plants due to favorable market conditions. The First Hydro plants and the Iberian Hy-Power plants are expected to provide for higher electric revenues during the winter months.
Net gains from price risk management activities recorded at fair value were $3.3 million in 2001. The gains primarily represent the change in market value of long-term commodity contracts entered into by the First Hydro plant for the purchase and sale of electricity that were recorded at fair value under SFAS No. 133 with changes in fair value recorded through the income statement, effective July 1, 2001. The related cumulative effect of change in accounting for these contracts is described in further detail under "-Cumulative Effect of Change in Accounting Principle-Accounting for Derivatives."
Equity in income from investments increased $18.3 million in 2001 compared to 2000, and decreased $6.4 million in 2000 compared to 1999. The 2001 increase primarily reflects gains from the ISAB project. In 2001, the operational performance of the project substantially improved as expected, thereby achieving profitability. During 2000, we recorded losses from this project. Commercial operation of the ISAB project commenced in April 2000. The 2000 decrease was primarily due to losses incurred primarily from extended start-up and commissioning activities of the ISAB project during 2000, its first year of operation.
Operating Expenses
Fuel and plant operations costs increased $27.1 million in 2001 compared to 2000, and increased $22.8 million in 2000 compared to 1999. The 2001 increase was primarily due to higher fuel costs at the First Hydro plant and Doga plant. The increase in fuel costs at the First Hydro plant reflects the changes under the new electricity trading arrangements. Under the new trading arrangements, fuel
costs include contracts to purchase electricity which we used to meet sales commitments when it was more cost-effective to purchase as compared to generate electricity, thus, reducing the need for physical pumping or generating. In addition, due to the new trading arrangements, some costs previously paid by suppliers now are being paid by generators and all market participants are being charged imbalance costs when their metered position differs from their contracted position. The new electricity trading arrangements are described in further detail under "-Market Risk Exposures-United Kingdom." Fuel costs increased at the Doga plant primarily due to increased production in 2001, compared to the same prior year period. The 2000 increase resulted from a full year of expenses at the Doga project, partially offset by lower fuel expense at the First Hydro plant. Fuel expense at First Hydro decreased primarily due to lower generation levels in 2000, resulting in a lower pumping requirement.
Operating Income
Operating income decreased $89.7 million in 2001 compared to 2000, and increased $21.3 million in 2000 compared to 1999. The 2001 decrease was primarily due to lower operating income of $105.9 million from the First Hydro plant due to lower energy and capacity prices resulting from the new electricity trading arrangements. The 2000 increase was primarily due to operating income from the Doga project and higher operating income from the First Hydro plant.
Corporate/Other
Net gains from price risk management activities were $1.7 million in 2001. The gains primarily resulted from the change in market value of our interest rate swaps with respect to our $100 million senior notes that did not qualify for hedge accounting under SFAS No. 133.
Long-term incentive compensation expense consists of charges related to our terminated phantom option plan. Long-term incentive compensation expenses increased $62 million in 2001 compared to 2000, and decreased $192.3 million in 2000 compared to 1999. The 2001 increase was due to a reduction in the liability for previously accrued incentive compensation by approximately $60 million recorded during 2000 and additional 2001 compensation expense related to deferred payments and annual vesting of benefits. The 2000 decrease was due to the absence of new accruals, as the plan had been terminated, and to a reduction in the liability. This reduction 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.
Administrative and general expenses increased $1.8 million in 2001 compared to 2000, and increased $25 million in 2000 compared to 1999. There were no material changes in 2001 administrative and general expenses from 2000. The 2000 increase was primarily due to additional salaries and facilities costs incurred to support the 1999 acquisitions. We recorded a pre-tax 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)
Interest and other income increased $4.5 million in 2001 compared to 2000, and decreased $13.7 million in 2000 compared to 1999. The 2000 decrease was primarily due to fees incurred in December 2000 related to the liquidation of Edison Mission Energy Global Management, Inc. in connection with the redemption of the $120 million Flexible Money Market Cumulative Preferred Stock.
Gains on sale of assets were $41.3 million, $25.8 million and $7.6 million in 2001, 2000 and 1999, respectively. Gains on sale of assets for 2001 and 2000 included:
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 continued 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 the profits and losses of Four Star Oil & Gas 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 decreased $10.9 million in 2001 compared to 2000, and increased $250.6 million in 2000 compared to 1999. The 2001 decrease was due to a combination of the following:
•A reduction in corporate debt of $1.667 billion using the proceeds of the sale-leaseback of the Powerton-Joliet power plants in August 2000 and the Illinois peaker power units in July 2000; and
•Lower interest rates on variable rate debt generally tied to LIBOR primarily related to financing for our Illinois plants and our corporate line of credit; and
•Favorable changes in foreign exchange rates which reduced the U.S. dollar equivalent of foreign borrowings; partially offset by
•Higher-cost borrowings resulting from the California power crisis, including refinancing of short-term debt through the issuance of $1 billion in new fixed rate debt in 2001 and higher interest margins on our corporate line of credit.
The 2000 increase was primarily the result of additional debt financing associated with the acquisitions of the Illinois plants and the Homer City facilities.
Dividends on mandatorily redeemable preferred securities decreased $9.8 million in 2001 compared to 2000 and increased $9.7 million in 2000 compared to 1999. The 2001 decrease reflects the
redemption of the NZ$400 million EME Taupo preferred securities in July 2001. The 2000 increase reflects the issuance of preferred securities in connection with the original Contact Energy acquisition.
Provision (Benefit) for Income Taxes
We had effective tax provision (benefit) rates of 45.6%, 49.7% and (43.0)% in 2001, 2000 and 1999, respectively. The lower effective income tax rate in 2001 is largely due to changes in income levels in different international tax jurisdictions. 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 facilities and Illinois plants. 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, we benefited from lower foreign income taxes that resulted 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 decreased from 34% to 30% effective in July 2001. In accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the reductions in the Australian income tax rates resulted in reductions in income tax expense of approximately $5.9 million in 1999.
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.
Minority Interest
Minority interest expense increased $19 million in 2001 compared to 2000 and increased $0.2 million in 2000 compared to 1999. The 2001 increase was due to accounting for Contact Energy on a consolidated basis, effective June 1, 2001, due to the purchase of additional shares of Contact Energy that increased our ownership interest from 42.6% to 51.2%.
Discontinued Operations
As a result of the change in the prices of power in the U.K. and the anticipated negative impacts of such changes on earnings and cash flow, we offered for sale through a competitive bidding process the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, we completed the sale of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements.
The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.148 billion after tax) related to the loss on disposal. Included in the loss on disposal is the asset impairment charge of $1.9 billion ($1.154 billion after tax) we recorded in the third quarter of 2001 to reduce the carrying amount of the power plants to reflect the estimated fair value less the cost to sell and related currency adjustments.
Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. The early repayment of the projects' existing debt facility of £682.2 million at December 21, 2001 resulted in an extraordinary loss of $28 million, after tax, attributable to the write-off of unamortized debt issue costs.
Effective January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges under SFAS No. 133. We could not conclude, based on information available at December 31, 2000, that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.
Effective January 1, 2000, we recorded a $4.1 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting for major maintenance costs. Through December 31, 1999, we accrued for major maintenance costs incurred during the period at the Ferrybridge and Fiddler's Ferry power plants between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred.
Cumulative Effect of Change in Accounting Principle
Accounting for Derivatives and SFAS No. 133
Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates 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. Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also 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.
Effective January 1, 2001, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the documentation requirements of SFAS No. 133 are met.
Accounting for derivatives under SFAS No. 133 is complex. Each transaction requires an assessment of whether it is a derivative according to the definition under SFAS No. 133, including amendments and interpretations. Transactions that do not meet the definition of a derivative are accounted by us on the accrual basis, unless they relate to our trading operations, in which case they are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, either do not meet the definition of a derivative or qualify for the normal purchases and sales exception.
As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under the prior accounting policy.
Discussion of Initial Adoption of SFAS No. 133
On January 1, 2001, we recorded a $0.2 million, after tax, increase to income from continuing operations and a $230.2 million, after tax, decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. The following material items were recorded at fair value:
•The forward sales contracts from our Homer City facilities qualified as cash flow hedges. We did not use the normal sales and purchases exception for these forward sales contracts due to our net settlement procedures with counterparties as discussed below under "Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133." As a result of higher market prices for forward sales from our Homer City facilities, we recorded a liability of $115.9 million at January 1, 2001, deferred tax benefits of $54.1 million and a decrease in other comprehensive income of $61.8 million.
•The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia qualified as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. As a result of higher market prices for forward sales from our Loy Yang B plant, we recorded a liability of $227 million at January 1, 2001, deferred tax benefits of $68.1 million and a decrease in other comprehensive income of $158.9 million.
•The majority of our activities related to the fuel contracts for our Collins Station in Illinois did not qualify for either the normal purchases and sales exception or as cash flow hedges. We could not conclude, based on information available at January 1, 2001, that the timing of generation from the Collins Station met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, these contracts were recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement. We have continued to record fuel contracts for our Collins Station at fair value.
Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133
Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in quantities that are expected to be sold in the normal course of business. This modification had two significant impacts:
•As a result of the new interpretation, our Homer City forward sales contracts qualified for the normal sales and purchases exception, commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we reversed the value of the Homer City forward sales contracts from our consolidated balance sheet. The cumulative effect of this change in accounting is reflected as a $15.5 million, after tax, decrease to other comprehensive income in 2001.
•For the period between January 1, 2001 through June 30, 2001, we applied the normal sales and purchases exception for long-term commodity contracts that included both selling and purchasing electricity by our First Hydro plant. However, the criteria applicable to the buyer of power outlined under Statement No. 133 Implementation Issue Number C15 precluded the contracts from qualifying under the normal sales and purchases exception as of July 1, 2001 because First Hydro is not contractually obligated to maintain sufficient capacity to meet electricity needs of a customer. Accordingly, we recorded a $14.9 million, after tax, increase to income from continuing operations as the cumulative effect of change in accounting for derivatives in our consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of
these contracts were reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.
Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, of a derivative's change in fair value is immediately recognized in earnings. We recorded a net loss of $1.4 million in 2001, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.
Accounting for Major Maintenance Costs
Through December 31, 1999, we accrued for major maintenance costs incurred during the period between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $21.8 million, after tax, increase to income from continuing operations, as the cumulative effect of change in accounting for major maintenance costs during the quarter ended March 31, 2000.
Accounting for Start-up Costs
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 in 1999 that resulted from adopting SOP 98-5 was $13.8 million, after tax.
Extraordinary Gain
As a result of the Homer City sale-leaseback transaction on December 7, 2001, we recorded an extraordinary gain of $5.7 million, net of income tax expense of $4.4 million, attributable to the extinguishment of debt that was assumed by the third party lessors in the sale-leaseback transaction. See "-Sale-Leaseback Transactions."
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2001, we had cash and cash equivalents of $372.1 million and had available a total of $554.3 million of borrowing capacity under our $750 million corporate credit facility. The credit facility includes a one-year $538.3 million component, Tranche A, that expires on September 17, 2002 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. The credit facility provides credit available in the form of cash advances or letters of credit. At December 31, 2001, Tranche A consisted of one borrowing of $80 million at one-month LIBOR of 1.9256%, plus the applicable margin as determined by our long-term credit ratings (an all in rate of 4.30%). Tranche B, which had no advances outstanding at December 31, 2001, included the issuance of letters of credit in the amount of $115.7 million. In addition to the interest payments, we pay a facility fee as determined by our long-term credit ratings (0.625% and 0.75% at December 31, 2001 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings. See "-Corporate Financing Plans."
Discussion of Historical Cash Flow
Cash Flows From Operating Activities
Net cash provided by (used in) operating activities:
Cash provided by continuing operating activities is derived primarily from operations of the Illinois plants and the Homer City facilities, distributions from energy projects and dividends from investments in oil and gas. The lower operating cash flow from continuing operations in 2001, compared to 2000, reflects lower distributions from energy projects and higher current income taxes payable due to the sale-leaseback of the Homer City facilities, partially offset by higher dividends from oil and gas investments. The change in operating cash flow in 2001 was also due to the timing of cash receipts and payables related to working capital items. Lower distributions from energy projects in 2001 primarily resulted from the delay in payments from the California utilities to our investments in California qualifying facilities. See "-The California Power Crisis" for further discussion. The higher operating cash flow from continuing operations in 2000, compared to 1999, primarily reflects higher pre-tax earnings from projects acquired in 1999 and higher dividends from oil and gas investments.
Net working capital at December 31, 2001 was $324.6 million compared to ($800.8) million at December 31, 2000. The increase primarily reflects the repayment on our corporate credit facilities that were classified as short-term obligations at December 31, 2000 with the proceeds from the issuance of long-term senior notes in 2001.
Cash used in operating activities from discontinued operations in 2001 reflects operating losses from the Ferrybridge and Fiddler's Ferry power plants in 2001 as compared to operating income during 2000, and the timing of cash payables related to working capital items.
Cash Flows From Financing Activities
Net cash provided by (used in) financing activities:
Cash used in financing activities from continuing operations in 2001 consisted of net proceeds from bond issuances totaling $1 billion, the proceeds of which were partially used to permanently repay $677 million under our former corporate credit facilities. In addition, we used the proceeds from the December 2001 Homer City sale-leaseback transaction to permanently repay $250 million under the Homer City facilities construction loan and to make a $350 million payment under our $750 million corporate credit facility. Dividends totaling $65 million and $32.5 million were paid to The Mission Group and Mission Energy Holding Company, respectively, and ultimately $96.5 million was paid to Edison International, our ultimate parent company, during 2001, compared to $88 million during 2000. As of December 31, 2001, we had recourse debt of $2.1 billion, with an additional $4 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.
Cash used in financing activities from discontinued operations in 2001 was primarily related to the early repayment of the term loan facility in connection with the sale of the Ferrybridge and Fiddler's Ferry power plants on December 21, 2001.
Payments made under 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 from continuing operations during 2000. We used the proceeds from the August 2000 Powerton and Joliet sale-leaseback transaction for a significant portion of the payments under our credit facilities and our floating rate notes. In 2000, we also had borrowings of $1.2 billion under our credit facilities and commercial paper facilities.
Cash provided by financing activities from discontinued operations in 2000 was primarily related to a loan from Edison Capital, an indirect affiliate. During 2001, the financing was repaid with interest.
In 1999, financings related to the acquisition of three new projects in 1999 contributed to net cash provided by financing activities from continuing operations. These financings included senior secured bonds totaling $830 million related to the Homer City facilities; $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 received $1.5 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 also issued $600 million of 7.73% Senior Notes due 2009.
Cash provided by financing activities from discontinued operations in 1999 resulted from the financing related to the acquisition of the Ferrybridge and Fiddler's Ferry power plants. The financing consisted of a term loan facility of $1.3 billion and a $500 million equity contribution from Edison International.
Cash Flows From Investing Activities
Net cash provided by (used in) investing activities:
Cash provided by investing activities from continuing operations in 2001 included proceeds of $782 million received from the sale-leaseback transaction with respect to the Homer City facilities in December 2001. In connection with this transaction, $139 million was deposited into a restricted cash account on the closing date. In June 2001, we also completed the sale of a 50% interest in the Sunrise project to Texaco for $84 million. Included in 2001 investing activities was cash used by us for equity contributions totaling approximately $134 million 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 "-The California Power Crisis" for further discussion. In addition, we paid $10 million as equity contributions for the CBK project; $6.4 million as part of the purchase price and $3 million as equity contributions for the Italian Wind projects; $20 million as part of the purchase of the 50% interest in the CBK project; and $63.4 million for the purchase of additional shares in Contact Energy.
In 2001, cash provided by investing activities from discontinued operations was primarily due to £643 million proceeds received from the sale of the Ferrybridge and Fiddler's Ferry power plants on December 21, 2001.
In 2000, net cash provided by investing activities from continuing operations included 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, $30.9 million was paid toward the purchase price and $13.3 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 EcoEléctrica project (June 2000), the Tri Energy project (July 2000) and the ISAB project (September 2000), respectively.
In 1999, cash used in investing activities from continuing operations was primarily due to the purchase of the Homer City facilities, the Illinois Plants and the 40% interest in Contact Energy. We invested $242.2 million, $330.6 million and $200 million in 2001, 2000 and 1999, respectively, in new plant and equipment principally related to the Valley Power project in Australia, Homer City facilities and Illinois plants in 2001, Homer City facilities and Illinois plants in 2000 and the Homer City facilities in 1999.
In 1999, cash used in investing activities from discontinued operations was primarily due to the purchase of the Ferrybridge and Fiddler's Ferry power plants.
Corporate Financial Ratios
In assessing the leverage of Edison Mission Energy, as a holding company, and its ability to meet debt service obligations, we and our principal bank lenders use two primary ratios: a recourse debt to recourse capital ratio and an interest coverage ratio. These ratios are determined in accordance with financial covenants that have been included in our corporate credit facilities and are not determined in accordance with generally accepted accounting principles as reflected in our Consolidated Statements of Cash Flows. Accordingly, these ratios should not be considered in isolation or as a substitute for cash flows from operating activities or cash flow statement data set forth in our Consolidated Statement of Cash Flows. While the ratios included in our corporate credit facilities measure the leverage and ability of Edison Mission Energy to meet its debt service obligations, they do not measure the liquidity or ability of our subsidiaries to meet their debt service obligations. Furthermore, these ratios are not necessarily comparable to other similarly titled captions of other companies due to differences in methods of calculations.
Our corporate credit facilities include covenants tied to these financial ratios(1):
Financial Ratio
Covenant
Actual at
December 31,
Description
Recourse Debt to recourse Capital Ratio
Less than or
equal to
67.5%
64.1%
Ratio of (a) senior recourse debt to (b) sum of (i) shareholder's equity per our balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse debt
Interest Coverage Ratio
Greater than
or equal to
1.50 to 1.00
1.64 to 1.00
For prior 12-month period, ratio of (a) funds flow from operations to (b) interest expense on senior recourse debt
(1)Our corporate credit facilities and corporate debt securities also include a Tangible Net Worth Covenant, which is determined based on our shareholder's equity adjusted for changes in other comprehensive income after December 31, 1999. At December 31, 2001, our tangible net worth as determined in accordance with the covenant was $944.9 million, which exceeds the covenant requirement of $613.8 million. As indicated in the above table, at December 31, 2001, we met the above financial covenants. The actual interest coverage ratio during 2001 was adversely affected by the operating results of the Ferrybridge and Fiddler's Ferry projects in the United Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was 1.98 to 1.0. Compliance with these covenants is subject to future financial performance, including items that are beyond our control. See "-Market Risk Exposures" and "-Risk Factors."
Discussion of Recourse Debt to Recourse Capital Ratio
The recourse debt to recourse capital ratio of Edison Mission Energy at December 31, 2001 and 2000 was calculated as follows:
(1)Recourse debt means direct obligations of Edison Mission Energy or obligations of one of its subsidiaries for which Edison Mission Energy has provided a guaranty. During 2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in our shareholder's equity from $1.1 billion of after-tax losses, attributable to the loss on sale of our Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. We sold the Ferrybridge and Fiddler's Ferry power plants in December 2001 due, in part, to the adverse impact of the negative cash flow pertaining to these plants. Our recourse debt at December 31, 2001 was slightly less than our recourse debt at December 31, 2000 with the proceeds from new notes issued during the course of the year having been used to repay short-term indebtedness.
Discussion of Interest Coverage Ratio
The following table sets forth the major component of our interest coverage ratio for 2001 and 2000:
(1)Operating cash flow is defined as revenues less operating expenses, foreign taxes paid and project debt service. Operating cash flow does not include capital expenditures or the difference between cash payments under our long-term leases and lease expenses recorded in our income statement. We expect our cash payments under our long-term power plant leases to be higher than our lease expense through 2014. (2)Consolidated operating projects are entities which we own more than a fifty-percent interest and, thus, include the operating results and cash flows in our consolidated financial statements. Non-consolidated operating projects are entities which we own 50% or less and account for on the equity method. (3)The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore project and Watson project. See description under "Business-Americas-Major Investments in California Cogeneration Projects."
The major factors affecting funds from operations in 2001 compared to 2000 were:
•Changes in market prices for energy and capacity from the Homer City, Ferrybridge and Fiddler's Ferry and First Hydro projects. As a result of the sale of the Ferrybridge and Fiddler's Ferry plants, we do not expect to incur negative cash flow from this project in future periods. See "-Market Risk Exposures." •Change in the fair value of the natural gas swap entered into in 2000 as a hedge against the changes in natural gas prices from our investment in Four Star Oil & Gas. See "Results of Operations-Americas." •Lower 2000 operating expenses as a result of the reduction in the liability for previously accrued incentive compensation during 2000 of approximately $60 million.
Interest expense increased $98 million in 2001 from 2000 as a result of:
•higher average debt balance in 2001 attributable in large part to the California power crisis; •an increase in borrowing costs from refinancing short-term debt with 2001 issuances of $1 billion long-term fixed rate debt as well as higher interest margins on our corporate credit facilities; and •additional 2001 financing fees from three maturity extensions of our corporate lines of credit.
Credit Ratings
To isolate ourselves from the impact of the California power crisis on Edison International and Southern California Edison, and to facilitate our ability and the ability of our subsidiaries to maintain our 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. 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 either of the following are true: 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; •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.
In January 2001, Standard & Poor's and Moody's downgraded our senior unsecured credit ratings to "BBB-" from "A-" and to "Baa3" from "Baa1", respectively. Our credit ratings remain investment
grade. Maintaining our investment grade credit ratings is part of our current operational focus and our long-term strategy. However, we cannot assure you that Standard & Poor's and Moody's will not downgrade our credit rating below investment grade. If our credit ratings are downgraded below investment grade, we could be required to, among other things:
•provide additional collateral in the form of letters of credit or cash for the benefit of counterparties in our domestic trading and price risk management activities related to accounts receivable and unrealized losses ($7.4 million at December 31, 2001); and •post a letter of credit or cash collateral to support our $45.3 million equity contribution obligation in connection with our acquisition in February 2001 of a 50% interest in the CBK Power Co. Ltd. project in the Philippines, which equity contribution would otherwise be payable commencing after full draw down of the debt facility currently scheduled for late 2002.
A downgrade of our credit ratings could result in a downgrade of the credit rating of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, would limit the ability of Midwest Generation to use excess cash flow to make distributions.
A downgrade of 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 have an adverse impact on us and our subsidiaries. In addition, in order to continue to market the power from our Homer City facilities and First Hydro plants in the United Kingdom as well as purchase natural gas or fuel oil at our Illinois Plants, we may be required to provide substantial additional credit support in the form of letters of credit or cash. In addition, changes in forward market prices and margining requirements could further increase the need for credit support for our trading and risk management activities.
Recently, Standard & Poor's and Moody's have indicated that they are reviewing the criteria for assessing credit risk for merchant energy companies (companies that generate and/or trade wholesale power without long-term contracts). The criteria used by Standard & Poor's and Moody's in assessing credit risk in turn is used to assign credit ratings, including whether or not a company is investment grade. We cannot predict whether Standard & Poor's or Moody's will change their criteria for assessing credit risk or, if changes were made, whether or not such changes would adversely affect our credit ratings.
Corporate Financing Plans
We have a $750 million corporate credit facility which includes a one-year $538.3 million component, Tranche A, that expires on September 17, 2002 and a three-year $211.7 million component, Tranche B, that expires on September 17, 2004. At December 31, 2001, we had borrowing capacity under this facility of $554.3 million and corporate cash and cash equivalents of $25 million. We plan to utilize the corporate credit facilities to fund corporate expenses, including interest, during 2002, depending on the timing and amount of distributions from our subsidiaries. Our 2002 cash flow will include distributions from our investments in partnerships made subsequent to receipt of payments of past due accounts receivable from Southern California Edison on March 1, 2002. Total amounts paid to these partnerships by Southern California Edison was $415 million, of which our share was $206.2 million. In addition, we expect to receive in 2002 tax sharing payments of our outstanding receivable of $224.4 million at December 31, 2001 from our ultimate parent company. In addition, we plan to extend Tranche A under our corporate facility or enter into a similar facility with other financial institutions by September 2002. The timing and amount of distributions from our subsidiaries may be affected by many factors beyond our control, some of which are described below under "-Risk Factors."
Subsidiary Financing Plans
The estimated capital and construction expenditures of our subsidiaries for 2002 are $95.2 million, excluding environmental improvements disclosed under "-Contractual Obligations, Commitments and Contingencies-Other Commercial Commitments." These expenditures are planned to be financed by existing subsidiary credit agreements and cash generated from their operations. Other than as described under "-Contractual Obligations, Commitments and Contingencies," we do not plan to make additional capital contributions to our subsidiaries.
Coal and Capex Facility
In connection with the original acquisition and financing of the Ferrybridge and Fiddler's Ferry coal-fired electric generating plants, one of our subsidiaries, EME Finance UK Limited, entered into a Coal and Capex Facility Agreement dated July 16, 1999. At December 31, 2001, £68 million was outstanding for coal purchases and £105 million was outstanding to fund capital expenditures under this facility. 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. Following the completion of the sale of the power plants, we can no longer make any new borrowings under this facility. Our liability under the guarantee will extend only to the amounts currently outstanding under the facility agreement, which totaled £173 million at December 31, 2001. Obligations under this facility are due in 2004. We plan to repay the Coal and Capex Facility prior to its maturity in 2004 from settlement of the remaining assets and liabilities of our discontinued operations (estimated at £55 million at December 31, 2001) and cash flows generated from our foreign subsidiaries. Subsequent to December 31, 2001, we made total payments of £35 million from a partial settlement of assets and liabilities of discontinued operations reducing our obligation from £173 million to £138 million at March 25, 2002. Interest expense associated with the Coal and Capex Facility will be included as part of corporate interest expense in income (loss) from continuing operations, effective the date of the sale of the power plants, December 21, 2001. Through December 21, 2001, interest expense associated with the facility agreement was classified in income (loss) from discontinued operations.
Intercompany Tax Sharing Payments
We participate in a tax sharing agreement with The Mission Group, which in turn participates in a tax sharing agreement with Edison International. We have historically received tax payments under the tax sharing agreement related to domestic net operating losses incurred by us. However, we were required to pay Edison International $55 million during October 2001 primarily as a result of changes in estimated taxable income for 2000. At December 31, 2001, we have recorded $224.4 million as an income tax receivable under the tax sharing agreement. However, we are not eligible to receive tax sharing payments for such losses until such time as Edison International and its subsidiaries generate sufficient taxable income in order to be able to monetize our tax losses in the consolidated income tax returns for Edison International and its subsidiaries. We anticipate this will occur in 2002, and, accordingly, we expect to receive payments in 2002 of our outstanding receivable from Edison International.
Restricted Assets of Subsidiaries
Each of our direct and 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 subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or to an affiliate of ours.
Contractual Obligations, Commitments and Contingencies
Contractual Obligations
The following table summarizes our consolidated contractual obligations as of December 31, 2001.
Sale-Leaseback Commitments
At December 31, 2001, we had minimum lease payments related to purchased power generation assets from Commonwealth Edison that were leased back to us in three separate transactions and the Homer City facilities. 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 from Commonwealth Edison 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. During the fourth quarter of 2001, we entered into a sale-leaseback transaction for the Homer City coal-fired plant located in Pennsylvania, to third-party lessors. Total minimum lease payments (included in the table above under "operating lease obligations") during the next five years are $343.6 million in 2002, $342.6 million in 2003, $310.8 million in 2004, $353.9 million in 2005, and $426.8 million in 2006. At December 31, 2001, the minimum lease payments due after 2006 were $5.4 billion. For further discussion, see "-Off-Balance Sheet Transactions-Sale-Leaseback Transactions."
Edison Mission Energy Master Turbine Lease
In December 2000, we entered into a master lease and related agreements which together initially provided for the construction of several new projects using in total nine turbines on order from Siemens Westinghouse. Under the terms of the master lease, an independent party is owner of the projects and is responsible for their development and construction using these turbines. In turn, as agent for the owner, we have agreed to supervise the development and construction of the new projects, which duties include arranging for funding to enable the owner to make payments for construction costs, including progress payments on the turbines. We are required to deposit U.S. treasury notes equal to 103% of the construction costs incurred by the owner from time to time as collateral security for our obligation to assist the owner to complete the projects. This can only be called upon in limited circumstances. We have agreed to lease from the owner each project upon its completion and to provide a guarantee of each project's residual value at the end of the lease term. Use of this structure during the development and construction phase of a project allows us to retain the flexibility to finance the project on a long-term basis through a lease structure. Lease payments are scheduled to begin in November 2003. Minimum lease payments (included in the table above under "operating lease obligations") under this agreement are $3.1 million in 2003, $27.7 million in 2004, $50.2 million in 2005 and $71.5 million in 2006. At December 31, 2001, the remaining minimum lease payments due after 2006 were $300.4 million. The term of the master lease ends in 2010.
Due to unfavorable market conditions, we decided to terminate our obligation to cause the completion of three of the four projects, for which we planned to use six of the turbines. In order to
terminate the master lease for these projects, we exercised an option to acquire the assets of these projects, principally the purchase rights for the related turbines, for a purchase price of approximately $25 million. As a result of our decision to terminate these projects, we recorded a loss of $25.4 million during the year ended December 31, 2001. In connection with the termination, we obtained a release of the treasury notes held as collateral for our performance obligations with respect to these projects. Also, as part of the termination, we acquired the purchase orders for the six turbines and, thus, can continue to make progress payments and take delivery of them should market conditions improve. No progress payments are due until 2003, however, and we have the right to terminate these orders prior to the end of 2002 with no additional payment obligations.
We exercised our right to purchase the remaining three turbines under the master lease in March 2002 for $61.1 million, effectively terminating any remaining obligations under this arrangement. We plan to use these turbines for a new gas-fired project and, accordingly, we plan to capitalize the amount paid to purchase the turbines from the master lease. Our remaining purchase obligations under these turbines purchase orders are $53 million.
Fuel Supply Contracts
At December 31, 2001, we had contractual commitments to purchase and/or transport coal and fuel oil. The minimum commitments are based on the contract provisions, which consist of fixed prices, subject to adjustment clauses in some cases.
Gas Transportation Agreement
In June 2000, we entered into a long-term transportation contract with Kern River Gas Transmission Company related to the expansion of the Midway-Sunset project, a 225 MW power plant in California in which our wholly-owned subsidiary owns a 50% interest. Under the terms of the contract we have contractual commitments to transport natural gas beginning the later of May 1, 2003 or the first day that expansion capacity is available for transportation services. We are committed to pay minimum fees under this agreement which has a term of 15 years.
Other Commercial Commitments
The following table summarizes our consolidated commercial commitments as of December 31, 2001. Details regarding these commercial commitments are discussed in the sections following the table.
Credit Support for Trading and Price Risk Management Activities
Our domestic trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc. 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 Edison Mission Marketing & Trading. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. Currently we provide a parent company guaranty by Edison Mission Energy to support Edison Mission Marketing & Trading's contracts. If we do not maintain an investment grade rating or if other events adversely affect our financial position, a third party could request us to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, 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 us for any losses.
Beginning in 2000, the California power crisis adversely affected the liquidity of West Coast trading markets and, to a lesser extent, markets in other regions in the United States. Our trading and price risk management activity was reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. In addition, there have been a number of other factors since 2000, including the bankruptcy filing of Enron, increased concern regarding the liquidity of independent power companies, decrease in market prices in U.S. wholesale energy markets, and risk factors related to our business, that continue to limit our trading and price risk management activities. It is not certain that market conditions or risks related to our business will change to allow us to be able to conduct trading and price risk management activities in a manner favorable to us.
Firm Commitment for Asset Purchase
(i)The Italian Wind projects are a series of power projects that are in operation or under development in Italy. Our wholly-owned subsidiary 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
(i)CBK is a 728 MW hydroelectric power project under construction in the Philippines. At December 31, 2001, 168 megawatts have been commissioned and are operational. Our wholly-owned subsidiary owns a 50% interest. Equity is to be contributed through December 2003 commencing after full draw down of the project's debt facility, which is currently scheduled for late 2002. This equity commitment could be accelerated if our credit rating were to fall below investment grade. We were notified that the contractor responsible for engineering, procurement, and construction of the project required an adjustment in the construction payment schedule in order to meet its obligations to major suppliers and subcontractors. The project lenders and sponsors agreed on an adjustment to the loan drawdown schedule, including a one-time special
draw to cover amounts owing to suppliers and subcontractors for work already completed. The agreement with the project's lenders required that 50% of the special draw amount be funded by the project sponsors. Therefore, we contributed $10 million of our equity commitment in December 2001.
(ii)The Sunrise project consists of two phases, with Phase I, a simple-cycle gas-fired facility (320 MW) that commenced commercial operation in June 2001, and Phase II, conversion to a combined-cycle gas-fired facility (560 MW) currently scheduled to be completed in July 2003. Our wholly-owned subsidiary owns a 50% interest. Equity will be contributed to fund the construction of Phase II. The amount set forth in the above table assumes the partners will contribute equity for the entire construction costs. The project intends to obtain project financing for a portion of the capital costs, which if such financing occurs, our equity contribution obligation would be reduced. Project financing is subject to a number of uncertainties, including the matters related to the power purchase agreement with the California Department of Water Resources. See "-The California Power Crisis-Regulatory Developments Affecting Sunrise Power Company." Firm commitments to contribute project equity could be accelerated due to events of default as defined in the non-recourse project financing facilities.
Contingencies
Paiton
Our wholly-owned subsidiary owns a 40% interest in PT Paiton Energy, which owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia, which is referred to as the Paiton project. Our investment in the Paiton project was $492.1 million at December 31, 2001. Under the terms of a long-term power purchase agreement between Paiton Energy and PT PLN, the state-owned electric utility company, PT PLN is required to pay for capacity and fixed operating costs once each unit and the plant achieve commercial operation.
PT PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN and the settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the terms of the power purchase agreement from 2029 to 2039. Paiton Energy and PT PLN are continuing negotiations on an amendment to the power purchase agreement that will include the agreed commercial terms in the Binding Term Sheet, with the aim of concluding those negotiations by June 30, 2002. The Binding Term Sheet serves as the basis under which PT PLN will pay Paiton Energy beginning January 1, 2002. The Binding Term Sheet will expire on June 30, 2002 unless extended by mutual agreement. Previously, PT PLN and Paiton Energy entered into a Phase I Agreement (covering January 1 to June 30, 2001), a Phase II Agreement (covering July 1 to September 30, 2001) and a Phase III Agreement (covering October 1 to December 31, 2001). PT PLN has made all payments to Paiton Energy as required under these agreements, which are superseded by the Binding Term Sheet. Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes that PT PLN will continue to make payments for electricity under the Binding Term Sheet while negotiations on the amendment to the power purchase agreement continue. Although completion of negotiations may be delayed beyond June 30, 2002, Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful.
Under the Binding Term Sheet, past due accounts receivable due under the original power purchase agreement will be compensated through a restructure settlement payment in the amount of US$4 million per month for a period of 30 years. If the power purchase agreement amendment is not completed within reasonable time frames acceptable to Paiton Energy, the parties would be entitled to revert back to the terms and conditions of the original power purchase agreement in order to pursue arbitration in the international courts.
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. 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 addition to the 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. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations. We are currently offering our interest in the Brooklyn Navy Yard project for sale.
ISAB
In connection with the financing of the ISAB project, we have guaranteed for the benefit of the banks financing the construction of the ISAB project our subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $40 million. The amount of payment under the obligation is contingent upon settlement of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. No overall settlement of the dispute has yet been achieved.
Indemnities
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, 2001, if payment were required, would be $234.4 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 Indemnities-In support of the business of our subsidiaries, we have, from time to time, entered into guarantees and indemnity agreements with respect to our subsidiaries' obligations such as debt service, fuel supply or the delivery of power, and have also entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We have also, from time to time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have indemnified the previous owners of the Illinois Plants and the Homer City facilities for specified liabilities, including environmental liabilities, incurred as a result of their prior ownership of the plants. We do not believe these indemnification obligations will have a material impact on us.
Tax Indemnity Agreements
In connection with the sale-leaseback transactions that we have entered into related to the Collins Station, Powerton and Joliet plants in Illinois and the Homer City facilities in Pennsylvania, we have entered into tax indemnity agreements. Under these tax indemnity agreements, we have agreed to indemnify the equity investors in the sale-leaseback transactions for specified adverse tax consequences. The potential indemnity obligations under these tax indemnity agreements could be significant. However, we believe it is not likely that an event requiring material tax indemnification will occur under any of these agreements.
Additional Gas-Fired Generation
Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago. The acquisition documents require that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected Network (generally referred to as MAIN) region and the improved reliability of power generation in the Chicago area, we have undertaken preliminary discussions with Exelon Generation regarding alternatives to construction of 500 MW of capacity which we do not believe are needed at this time. If we were to install this additional capacity, we estimate that the cost could be as much as $320 million.
Contingent Obligations to Contribute Project Equity
(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 $136 million has been contributed as of December 31, 2001.
For more information on the Paiton project, see "-Paiton" above.
(ii)ISAB is a 512 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. Our wholly-owned subsidiary 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.
For more information on the ISAB project, see "-ISAB" above.
We are not aware of any other significant contingent obligations or obligations to contribute project equity.
The California Power Crisis
We have partnership interests in eight partnerships that own power plants in California and 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 2001, our share of earnings before taxes from these partnerships was $244 million, which represented 35% of our operating income. Our investment in these partnerships at December 31, 2001 was $527.9 million.
Utility Payment Defaults
As a result of the liquidity crisis affecting Southern California Edison and Pacific Gas and Electric during 2001, each of these utilities failed to make payments during the first quarter of 2001 to qualifying facilities supplying them power. These qualifying facilities included the eight power plants that are owned by partnerships in which we have a partnership interest. The California utilities' failure to pay adversely affected the cash flow from our eight California qualifying facilities.
Pacific Gas and Electric
On April 6, 2001, Pacific Gas and Electric filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code in San Francisco bankruptcy court. Pacific Gas and Electric has paid for power delivered after the bankruptcy filing, but it paid only a small portion of the amounts due to the partnerships for power delivered in December 2000 and January 2001, and made no payment at all for power delivered in February and March 2001. At the petition date, accounts receivable to these partnerships from Pacific Gas and Electric were $47 million. Our share of these receivables was $23 million.
Effective as of July 31, 2001, Pacific Gas and Electric and four of the partnerships in which we have a partnership interest entered into agreements that amended the power purchase agreements to provide for a fixed energy price for the lesser of the remaining term of the power purchase agreement or five years. The contract amendments were approved by both the bankruptcy court and the California Public Utilities Commission. Pacific Gas and Electric assumed the power purchase agreements, as amended, and, in addition to payments for current deliveries of power, is making payments of the past-due receivables on an agreed schedule which, absent further defaults by Pacific Gas and Electric, should bring the past-due amounts current by the end of the first quarter of 2003.
Southern California Edison
Southern California Edison did not pay qualifying facilities, including four partnerships in which we have an interest, for power delivered between November 1, 2000 and March 26, 2001. Southern California Edison had paid the partnerships for power delivered after March 27, 2001. As a result, at December 31, 2001, accounts receivable by these partnerships from Southern California Edison were $436 million. Our share of these receivables was $216.5 million. As discussed below, Southern California Edison paid its past due receivables on March 1, 2002.
Provisions in the relevant partnership agreements stipulate that partnership actions concerning contracts with affiliates are to be taken through the non-affiliated partner in the partnership. Therefore, any partnership actions concerning the enforcement of rights under a partnership's power purchase
agreement with Southern California Edison are to be taken through the non-Edison Mission Energy affiliated partner in each partnership.
All four of the partnerships in which we have an interest filed complaints against Southern California Edison with respect to the payment defaults. All of those partnerships subsequently entered into agreements with Southern California Edison, under which the partnerships and Southern California Edison are to suspend the current litigation for a specified "standstill period" and provisionally stipulate as to the amount of past due receivables, and Southern California Edison is to make partial payments with respect to past due receivables. Pursuant to the standstill agreements, Southern California Edison paid the first 10% of the past due receivables and made monthly interest payments on the remaining past due amounts. On March 1, 2002, Southern California Edison reported that it had closed on $1.8 billion of financing and repaid all of its material, undisputed past due obligations. The remaining past due receivables to the four partnerships in which we have an interest were paid in full, except for certain disputed amounts totaling less than $1 million for all four partnerships.
Regulatory and Legislative Developments
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. As a result of this decision, Southern California Edison paid in full for power delivered after March 27, 2001, and Pacific Gas and Electric paid for power delivered after April 6, 2001 (the date it filed its bankruptcy petition). This decision did not address payment to the qualifying facilities for amounts due prior to March 27, 2001. In addition, the decision modified the pricing formula for determining short-run avoided costs for qualifying facilities subject to these provisions, including four partnerships in which we have a partnership interest. Those four partnerships, all of which sell power to Pacific Gas and Electric, have subsequently entered into agreements that amend the power purchase agreements to provide for a fixed energy price for the lesser of the remaining term or five years, thereby reducing their exposure to variations in the short-run avoided costs formula.
On April 3, 2001, the California Public Utilities Commission adopted an order instituting investigation. The order reopened past Commission decisions authorizing the California investor-owned utilities to form holding companies and initiated an investigation into: whether the holding companies violated requirements to give priority to the capital needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E Corporation and their respective non-utility affiliates (including us) also violated 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. On January 9, 2002, the Commission issued two decisions, the first asserting that it has adequate jurisdiction to adjudicate these issues and enforce decisions concerning them, and the second construing the nature and scope of the requirements to give priority to the capital needs of the utility subsidiaries, referred to above, to apply broadly to all forms of financial support, including working capital and cash for operating expenses such as wholesale power purchases, and not narrowly, to equity investment, as all three utilities had argued. The Commission also stated that it has not yet determined whether any holding company violated such requirements, and that such determination would be made in subsequent proceedings. We are not a party to this investigatory proceeding. We cannot predict what direct or indirect effects any subsequent action taken by the Commission in this proceeding or in any other action or proceeding, in reliance on the principles articulated in this order and in other applicable authority, may have on Edison International, on us, or on our subsidiaries.
On October 2, 2001, the California Public Utilities Commission announced an agreement with Southern California Edison to settle a federal district court lawsuit filed in late 2000 in which Southern California Edison sought a ruling that it is entitled to full recovery of its costs for wholesale purchases of electricity. The settlement agreement provides for Southern California Edison to recover its procurement-related liabilities, less cash on hand and certain other amounts, through a regulatory balancing account with a starting balance of approximately $3.3 billion. The recovery will take place out of the positive difference of Southern California Edison's revenues from retail electric rates (including surcharges) over authorized costs. The parties agreed that Southern California Edison will recover its procurement-related obligations by December 31, 2005. The settlement agreement also provides that, subject to certain qualifications, Southern California Edison will cooperate with the California Public Utilities Commission and the California Attorney General to pursue and resolve claims and rights against sellers of energy and related services.
On October 5, 2001, the federal district court signed and entered a stipulated judgment approving the terms of the settlement agreement. One of the intervenors in the lawsuit, a consumer advocacy group known as The Utility Reform Network, has appealed the stipulated judgment to the Ninth Circuit Court of Appeals. A separate set of appeals was filed by two electricity wholesalers and by a group purporting to represent a class of ratepayers. The appeals were consolidated and were heard on March 4, 2002, and a decision could be issued within the next several months. The settlement agreement and existing retail rates remain in effect.
A number of other 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. For example, on April 26, 2001, the Federal Energy Regulatory Commission ordered price mitigation measures, or price caps, for power sales in the California spot market during emergency periods only. On June 19, 2001, the price mitigation measures were expanded to apply during all periods and to cover the entire eleven-state Western region. These price mitigation measures are scheduled to end on September 30, 2002. In a related matter, on July 25, 2001, the Federal Energy Regulatory Commission ordered that refunds may be due from sellers who engaged in transactions in the Western markets from October 2, 2000 through June 20, 2001 at levels in excess of the price caps included in the April 26 and July 19 orders (with some modifications), and ordered an evidentiary hearing to determine the refunds due from the market participants. These proceedings have been delayed due to difficulties in obtaining and analyzing the underlying data necessary to calculate refunds. Currently no decision is expected until the third quarter of 2002 at the earliest. A separate proceeding addressed the potential for refunds in the Pacific Northwest. The administrative law judge in that proceeding recommended that refunds not be ordered, finding that the Pacific Northwest market was workably competitive. The Federal Energy Regulatory Commission has not yet acted on the administrative law judge's recommended disposition of the matter. The federal and state legislative and regulatory initiatives may result in a restructuring of the California power market. A California voter initiative or referendum has been threatened against any measures that would raise consumer rates or aid California's investor-owned utilities. At this time, it is not possible to estimate the likely ultimate outcome of these activities.
Regulatory Developments Affecting Sunrise Power Company
Sunrise Power Company, in which we own a 50% interest, sells all of its output to the California Department of Water Resources under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the Federal Energy Regulatory Commission against all sellers of long-term contracts to the California Department of Water Resources, including Sunrise Power Company. The California Public Utilities Commission complaint alleges that the contracts are "unjust and
unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity Oversight Board complaint makes a similar allegation and requests that the contracts be deemed voidable at the request of the California Department of Water Resources or, in the alternative, abrogated as of a future date, to allow for the possibility of renegotiation. In response, on March 19, 2002, Sunrise filed a motion to dismiss with the Federal Energy Regulatory Commission requesting, among other things, a dismissal of both complaints and expedited treatment of its motion; however, we cannot predict what actions the Federal Energy Regulatory Commission may take at this proceeding.
Market Risk Exposures
Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates 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.
Commodity Price Risk
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 the use of stress testing and worst-case scenario analysis, as well as stop loss limits and counterparty credit exposure limits.
Electric power generated at our merchant 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 facilities, to the Pennsylvania-New Jersey-Maryland Power Pool (PJM) or the New York Independent System Operator (NYISO). Our risk management policies and procedures include an assessment of credit risk. When making sales under negotiated bilateral contracts, it is our general policy to deal with investment grade counterparties or counterparties that have equivalent credit quality. Our risk management committees grant exceptions to the policy only after review and scrutiny. Most entities that have received exceptions are typically 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 provide more predictable earnings and cash flow. 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 revenues and results of operations during the estimated useful lives of our merchant power plants will depend upon prevailing market prices for capacity, energy, ancillary services, fuel oil, coal and natural gas and associated transportation costs in the market areas where our merchant plants are located. Among the factors that influence the price of power in these markets are:
•prevailing market prices for fuel oil, coal and natural gas and associated transportation costs;
•the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market entrants, including the development of new generation facilities;
•transmission congestion in and to each market area;
•the market structure rules to be established for each market area;
•the availability, reliability and operation of nuclear generating plants, where applicable;
•weather conditions prevailing in surrounding areas from time to time; and
•the rate of growth in electricity usage as a result of factors such as regional economic conditions and the implementation of conservation programs.
A discussion of each market area is set forth below by region.
Americas
Homer City Facilities
Electric power generated at the Homer City facilities 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 facilities 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 facilities can also transmit power to the Midwestern United States.
The following table depicts the average markets prices per megawatt hour in PJM during the past three years:
*Prices are calculated using historical hourly prices provided on the PJM-ISO web-site. As shown on the above table, the average market prices during the last three months of 2001 are below the average market prices during the last three months of 2000. In addition, the forecasted calendar year market prices for 2002 in PJM beginning January 2, 2002 through March 12, 2002 range from approximately $23 to $28. The forward market prices in PJM fluctuate as a result of a number of factors, including gas prices, electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity.
The ability of our subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the sale-leaseback transaction discussed under "-Off-Balance Sheet Transactions-Sale-Leaseback Transactions" is dependent on revenues generated by the Homer City facilities, which depend on market conditions for the sale of capacity and energy. These market conditions are beyond our control.
Illinois Plants
Electric power generated at the Illinois plants is sold under three power purchase agreements with Exelon Generation Company, in which Exelon Generation 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 capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the Illinois plants revenue for fixed charges, and the energy payments compensate the Illinois plants for variable costs of production.
Virtually all of the energy and capacity sales in 2001 from the Illinois plants were made to Exelon Generation under the power purchase agreements, and a significant portion is likely to be sold to Exelon Generation during 2002. In October 2001, Exelon Generation exercised the option under one of the power purchase agreements to terminate all of the oil peaker plants (300 megawatts), effective January 2002, but continued it with respect to all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.
The energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers or into the so-called spot market. Thus, to the extent that Exelon Generation does not purchase our power for 2003 or 2004, we will be subject to the market risks related to the price of energy and capacity described above. Due to the volatility of market prices for energy and capacity during the past several years, we cannot predict whether or not Exelon Generation will elect to terminate any of the units currently subject to the power purchase agreements for which termination is permitted and, if they do, whether sales of energy and capacity to other customers and the market will be at prices sufficient to generate cash flow necessary to meet the obligations of our subsidiary. As of December 31, 2001, we had not entered into forward energy sales contracts for the Illinois plants other than those with Exelon Generation.
Europe and Middle East
United Kingdom
Since 1989, our plants in the U.K. have sold their electrical energy and capacity through a centralized electricity pool, which established a half-hourly clearing price, also referred to as the pool price, for electrical energy. On March 27, 2001, this system was replaced by the U.K. government with a bilateral physical trading system referred to as the new electricity trading arrangements. In connection with the new electricity trading arrangements, the First Hydro plant entered into forward contracts with varying terms that expire on various dates through October 2003. In addition, two long-term contracts with a three-year termination provision entered into in March 1999 from the First Hydro plant to buy and sell electricity were amended as forward contracts.
The new electricity trading arrangements provide for, among other things, the establishment of a range of voluntary short-term power exchanges and brokered markets operating from a year or more in advance to 31/2-hours before a trading period of 1/2 hour; 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. The grid operator retained the right under the new market mechanisms to purchase system reserve and response services to maintain the quality of the electrical supply directly
from generators (generally referred to as "ancillary services"). Ancillary services contracts typically run for a year and can consist of both fixed contracted amounts and prices for services that are only paid for when called upon by the grid operator. Physical bilateral contracts have replaced the prior financial contracts for differences, but have a similar commercial function. However, it remains difficult to evaluate the future impact of the new electricity trading arrangements. A key feature of the new arrangements is to require firm physical delivery, which means that a generator must deliver, and a consumer must take delivery of their net contracted positions or pay for any energy imbalance at highly volatile imbalance prices calculated by the market 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. Furthermore, another consequence of the market change is that counterparties may require additional credit support, including parent company guarantees or letters of credit.
The legislation introducing the new trading arrangements set a principal objective for the Gas and Electric Market Authority to "protect the interests of consumers...where appropriate by promoting competition...." This represents a shift in emphasis toward the consumer interest. However, this is qualified by a recognition that license holders should be able to finance their activities. The Utilities Act of 2000 also contains new powers for the Secretary of State to issue guidance to the Gas and Electric Market Authority on social and environmental matters, changes to the procedures for modifying licenses and a new power for the Gas and Electric Market Authority to impose financial penalties on companies for breach of license conditions. We are monitoring the operation of these new provisions.
During 2001, our operating income from the First Hydro plant decreased $105.9 million from the prior year primarily due to the removal of a formal capacity mechanism in the new trading arrangements and the oversupply of generation in the market resulting in a sharp fall in the market value for capacity. In addition, First Hydro's operating results have been adversely impacted in the second half of the year by a fall in the differential of the peak daytime energy price compared to the cost of purchasing power at nighttime to pump water back to the top reservoir. Generation capacity on the UK system has been in excess of demand due to generators holding plant on the system at part load to protect themselves against the adverse affects of being out of balance in the new market and the mild weather experienced during 2001.
For the foregoing reasons, First Hydro's interest coverage ratio, when measured for the twelve-month period ended June 30, 2002, may be below the threshold set forth in its bond financing documents, although it is anticipated that current project revenues will enable the July 31, 2002 interest payment to be made without recourse to the project's debt service reserve. We believe that should market and trading conditions experienced thus far in 2002 be sustained for the balance of the year, First Hydro's interest coverage ratio will be above the required threshold when measured for the twelve-month period ended December 31, 2002. Compliance by First Hydro with these and other requirements of its bond financing documents are subject, however, to market conditions for the sale of energy and ancillary services. These market conditions are beyond our control. There is no assurance that these requirements will be met and, if not met, will be waived by the holders of First Hydro's bonds. The bond financing documents stipulate that a breach of a financial covenant constitutes an immediate event of default and, if the event of default is not waived or cured, the holders of the First Hydro bonds are entitled to enforce their security over First Hydro's assets, including its power plants.
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. 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 derivative contracts to further mitigate against price volatility inherent in the electricity pool. These contracts consist of fixed forward electricity contracts that expire on various dates through December 31, 2004, and a five-year electricity cap contract expiring December 31, 2006.
New Zealand. A substantial portion of Contact Energy's generation output is hedged by sales to retail electricity customers and forward contracts with other wholesale electricity counterparties. Contact Energy has entered into forward contracts and option contracts of varying terms that expire on various dates through September 30, 2002 and January 31, 2004, respectively. The New Zealand Government commissioned an inquiry into the electricity industry in February 2000. Following the inquiry report the New Zealand Government released a Government Policy Statement, at the center of which was a call for the industry to rationalize the three existing industry codes, form a single governance structure and address transmission pricing methodology. The Government Policy Statement also requested a model use of system agreement be agreed, that is a framework by which the retailers contract for services from each of the distribution networks, and a consumer complaints ombudsman be established. An essential theme throughout the Government Policy Statement was the desire that the industry retain a private multilateral self-governing structure. During 2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry does not heed the Government's call. Progress on the single governance code is well underway and the Chairs of the three existing codes report to the Minister of Energy every two months on progress. The new code is likely to be introduced in July 2002.
Commodity Price Sensitivity Analysis
A 10% increase in pool prices would result in a $91.1 million decrease in the fair market value of electricity rate swap agreements related to our Loy Yang B project in Australia. Likewise, the fair market value of these electricity rate swap agreements would increase by $91.1 million from a 10% decrease in pool prices. 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, 2001 would result in a $0.5 million increase in the fair market value of forward contracts. A 10% decrease in electricity prices at December 31, 2001 would result in a $0.5 million decrease in the fair market value of forward contracts. A 10% increase in electricity prices at December 31, 2001 would result in a $0.5 million decrease in the fair market value of option contracts. A 10% decrease in electricity prices at December 31, 2001 would result in a $0.3 million increase in the fair market value of option contracts.
A 10% increase in natural gas and electricity forward prices at December 31, 2001 would result in a $11.4 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 natural gas and electricity forward prices at December 31, 2001 would result in a $11.4 million increase in the fair market value of energy contracts utilized by our domestic trading operations in energy trading and price risk management activities.
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, interest rate options or other hedging mechanisms for a number of our project financings. Interest expense included $17.2 million, $14.6 million and $25.2 million for the years 2001, 2000 and 1999, 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, 2001 would result in an $11 million increase in the fair value of our interest rate hedge agreements. A 10% decrease in market interest rates at December 31, 2001 would result in an $11.3 million decline in the fair value of our interest rate hedge agreements.
We had short-term obligations of $168.2 million consisting of bank borrowings at December 31, 2001. The fair values of these obligations approximated their carrying values at December 31, 2001, and would not have been materially affected by changes in market interest rates. The fair market values 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 $5,961.2 million at December 31, 2001. A 10% increase in market interest rates at December 31, 2001 would result in a decrease in the fair value of total long-term obligations by approximately $150 million. A 10% decrease in market interest rates at December 31, 2001 would result in an increase in the fair value of total long-term obligations by approximately $155.8 million.
Foreign Exchange Rate Risk
Fluctuations in foreign 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 current exposure to fluctuations in foreign exchange rates through financial derivatives, offsetting obligations denominated in foreign currencies, and indexing underlying project agreements to U.S. 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.
The First Hydro plant in the U.K. and the Loy Yang B plant in Australia have been financed in their local currencies, 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.
During 2001, foreign currencies in Australia, New Zealand and the U.K. decreased in value compared to the U.S. dollar by 8%, 6% and 3%, respectively (determined by the change in the exchange rates from December 31, 2000 to December 31, 2001). The decrease in value of these currencies was the primary reason for the foreign currency translation loss of $50.7 million during 2001. A 10% increase or decrease in the exchange rate at December 31, 2001 would result in foreign currency translation gains or losses of $74.4 million.
Contact Energy enters into foreign currency forward exchange contracts to hedge identifiable foreign currency commitments associated with transactions in the ordinary course of business. The contracts are primarily in Australian and U.S. dollars with varying maturities through September 2002. At December 31, 2001, the outstanding notional amount of the contracts totaled $16.9 million and the
fair value of the contracts totaled ($158,000). During the period from consolidation of Contact Energy results of operations (June 1, 2001) to December 31, 2001, Contact Energy recognized a foreign exchange gain of $1.1 million related to the contracts that matured during the same period. A 10% increase in the exchange rates at December 31, 2001 would result in a $1.5 million decline in the fair value of the contracts. A 10% decrease in the exchange rates at December 31, 2001 would result in a $1.9 million increase in the fair value of the contracts.
In addition, Contact Energy enters into cross currency interest rate swap contracts in the ordinary course of business. These cross currency swap contracts involve swapping fixed-rate U.S. and Australian dollar loans into floating-rate New Zealand dollar loans with varying maturities through April 2018. At December 31, 2001, Contact Energy had cross currency swap contracts in place with an approximate net-hedged value of $27.6 million.
We entered into a foreign currency forward exchange contract for a portion of the purchase price related to the potential acquisition of the remaining 49% of Contact Energy for NZ$479 million. At December 31, 2001, the fair value of the contract totaled ($0.4 million). Following the unsuccessful bid for the remaining shares of Contact Energy, we closed the contracts and recognized a foreign exchange gain of $0.7 million in February 2002.
We will continue to monitor our foreign exchange exposure and analyze the effectiveness and efficiency of hedging strategies in the future.
Non-Trading Derivative Financial Instruments
The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and instrument type:
In assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions that are based on market conditions and risk existing at each balance sheet date. The fair value of the commodity price contracts considers quoted marked prices, time value, volatility of the underlying commodities and other factors.
The fair value of the electricity rate swaps agreements (included under commodity price-swaps) entered into by the Loy Yang B plant in 2001 and 2000 and the First Hydro plant in 2000 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.
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 operations beyond the traditional marketing of our electric power to include trading of electricity and fuels. In conducting our trading activities we seek to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchases contracts and manage our exposure through a value at risk analysis as described further below. We also conduct price risk management activities with third parties not related to our power plants or investments in energy projects, including the restructuring of power sales and power supply agreements.
The fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of December 31, 2001 and 2000, which include energy commodities, are set forth below (in millions):
Quoted market prices are used to determine the fair value of the financial instruments related to trading activities.
Risk Factors
We have a substantial amount of indebtedness, including short-term indebtedness, and long-term lease obligations.
As of December 31, 2001, we had $2.1 billion of debt which is recourse to Edison Mission Energy and $4 billion of debt which is non-recourse to Edison Mission Energy but is recourse to our subsidiaries appearing on our consolidated balance sheet. In addition, we have $7.8 billion of long-term lease obligations that are due over periods ranging up to 33 years.
A failure to repay, extend or refinance our existing credit facilities as required by their terms could result in an event of default under the credit facilities. An event of default under the credit facilities would trigger cross-defaults under agreements to which our subsidiaries are party. In addition, the failure of a subsidiary to satisfy its obligations under its agreements, including satisfying financial covenants and servicing its debt, could trigger defaults under its agreements. Both cross-defaults and defaults would have the effect of not permitting distributions from our subsidiaries, which would have a negative impact on our liquidity and on our ability to make debt service payments.
The ability of our subsidiary to make payments of interest on the bond financing of First Hydro is dependent on revenues generated by the First Hydro plants, which depend on market conditions for the sale of energy and ancillary services. These market conditions are beyond our control. The financial covenants included in the First Hydro bonds require our subsidiary to maintain a minimum interest coverage ratio for each trailing twelve-month period as of June 30 and December 31 of each year. Our subsidiary was in compliance with this ratio for the twelve months ended December 31, 2001. Compliance with this ratio depends on market conditions for the sale of energy and ancillary services. There is no assurance that these requirements will be met and, if not met, will be waived by the
holders of First Hydro's bonds. The bond financing documents stipulate that a breach of a financial covenant constitutes an immediate event of default and, if the event of default is not waived or cured, the holders of the First Hydro bonds are entitled to enforce their security over First Hydro's assets, including its power plants.
Our substantial amount of debt and financial obligations presents the risk that we might not have sufficient cash to service our indebtedness or long-term lease obligations and that our existing corporate, project debt and lease obligations could limit our ability to grow our business, to compete effectively or to operate successfully under adverse economic conditions.
Our credit ratings are subject to change, and a downgrade of our credit rating below investment grade could have an adverse impact on us.
In January 2001, Standard & Poor's and Moody's downgraded our senior unsecured credit ratings to "BBB-" from "A-" and to "Baa3" from "Baa1", respectively. Our credit ratings remain investment grade. Maintaining our investment grade credit ratings is part of our current operational focus and our long-term strategy. However, we cannot assure you that Standard & Poor's and Moody's will not downgrade our credit rating below investment grade. If our credit ratings are downgraded below investment grade, we could be required to, among other things:
•provide additional collateral in the form of letters of credit or cash for the benefit of counterparties in our domestic trading and price risk management activities related to accounts receivable and unrealized losses ($7.4 million at December 31, 2001); and
•post a letter of credit or cash collateral to support our $45.3 million equity contribution obligation in connection with our acquisition in February 2001 of a 50% interest in the CBK Power Co. Ltd. project in the Philippines, which equity contribution would otherwise be payable commencing after full draw down of the debt facility currently scheduled for late 2002.
A downgrade of our credit ratings could result in a downgrade of the credit rating of Edison Mission Midwest Holdings Co., our indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below investment grade, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, would limit the ability of Midwest Generation to use excess cash flow to make distributions.
A downgrade of 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 have an adverse impact on us and our subsidiaries. In addition, in order to continue market the power from our Homer City facilities and First Hydro plants in the United Kingdom as well as purchase natural gas or fuel oil at our Illinois Plants, we may be required to provide substantial additional credit support in the form of letters of credit or cash. In addition, changes in forward market prices and margining requirements could further increase the need for credit support for our trading and risk management activities.
Some of our projects operate without long-term power purchase agreements and are or will be subject to market forces that affect the price of power.
Some of our projects do not have long-term power purchase agreements. Also, projects that 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. See "-Market Risk Exposures-Commodity Price Risks."
A substantial amount of our revenues are derived under power purchase agreements with a single customer, and we may be adversely affected if that customer elects not to purchase power from us or fails to fulfill its obligations under those power purchase agreements.
During 2001 and 2000, 36% and 42%, respectively, of our electric revenues were derived under three power purchase agreements with Exelon Generation Company, a subsidiary of Exelon Corporation. These agreements were 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 Generation are earned from capacity and energy provided by the Illinois plants under three five-year power purchase agreements expiring in 2004. If Exelon Generation were to fail or become unable to fulfill or choose to terminate some of 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.
Under each of the power purchase agreements, Exelon Generation, upon notice by a given date, has the option in effect to terminate each agreement with respect to all or a portion of the units subject to it. In October 2001, Exelon Generation exercised the option under one of the power purchase agreements to terminate all of the oil peaker plants (300 megawatts), effective January 2002, but continued it with respect to all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.
The energy and capacity from any units which do not remain subject to one of the power purchase agreements with Exelon Generation will be sold under terms, including price and quantity, to be negotiated with customers or into the so-called spot market. Thus, to the extent that Exelon Generation does not purchase our power for 2003 or 2004, we will be subject to the market risks related to the price of energy and capacity described above. Due to the volatility of market prices for energy and capacity during the past several years, we cannot predict whether or not Exelon Generation will elect to terminate any of the units currently subject to the power purchase agreements for which termination is permitted and, if they do, whether sales of energy and capacity to other customers and the market will be at prices sufficient to generate cash flow necessary to meet the obligations of our subsidiary. As of December 31, 2001, we had not entered into forward energy sales contracts for the Illinois plants other than those with Exelon Generation.
Our parent, Mission Energy Holding, depends upon cash flows from us to service its debt.
Mission Energy Holding's principal asset is our common stock. In July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security interest in our common stock. Any foreclosure on the pledge of our common stock by the holders of the senior secured notes or the lenders under the term loan could result in a change of control of us. A change in control of us or our subsidiaries could require us to prepay indebtedness in our or their debt agreements. For a discussion of the provisions in our formation documents that constrain our ability to pay dividends or distributions to Mission Energy Holding, see "Management's Discussion and Analysis of Results of Operations and Financial Condition-Credit Ratings."
Restrictions in our articles of incorporation, our credit facilities and the Mission Energy Holding financing documents limit or prohibit us from entering into specified transactions that we otherwise may enter into.
The financing documents entered into by Mission Energy Holding Company contain financial and investment covenants restricting us and our subsidiaries. Our articles of incorporation bind us to the
provisions in Mission Energy Holding's financing documents by restricting our ability to enter into specified transactions and engage in specified business activities, as contemplated by Mission Energy Holding's financing documents, without shareholder approval. The instruments governing our indebtedness also contain financial and investment covenants. Restrictions contained in the documents described in the preceding sentences could affect, and in some cases significantly limit or prohibit, our and our subsidiaries' ability to, among other things, incur and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and engage in mergers and consolidations.
Our international projects are subject to risks of doing business in foreign countries.
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. See "-Market Risk Exposures-Foreign Exchange Rate Risk."
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 electric 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 "-Contractual Obligations, Commitments and Contingencies-Paiton."
Competition could adversely affect our business.
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.
We are subject to extensive government regulation.
Our operations are subject to extensive regulation by governmental agencies in each of the countries in which we conduct operations. See "-Business-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. Currently, environmental advocacy groups and regulatory agencies in the United States and other countries have been focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their potential role in
the "global warming" issue. The adoption of laws and regulations to implement the carbon dioxide controls could adversely affect our coal-fired plants. Also, coal plant emissions of nitrogen and sulphur oxides, mercury and particulates are potentially subject to increased controls. See "-Environmental Matters and Regulations." 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 "Business-Regulatory Matters-U.S. Federal Energy Regulation."
General operating risks and catastrophic events may adversely affect our projects.
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 and, as a result, our ability to meet our obligations as they become due. 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 entity could cause us to lose our interest in the project.
Our future acquisitions and development projects may not be successful.
Our long-term 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 and Southern California Edison, 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.
Off-Balance Sheet Transactions
We have off-balance sheet transactions in two principal areas: investments in projects accounted for under the equity method and operating leases resulting from sale-leaseback transactions.
Investments Accounted for Under the Equity Method
Investments in which we have a 50% or less ownership interest are accounted for under the equity method in accordance with and as required by current accounting standards. Under the equity method, the project assets and related liabilities are not consolidated in our consolidated balance sheet. Rather, our financial statements reflect our investment in each entity and we record only our proportionate ownership share of net income or loss. These investments are of three principal categories.
•Historically, we have invested in so-called qualifying facilities, that is, those which produce electrical energy and steam, or other forms of useful energy, and which otherwise meet the
requirements set forth in 18 C.F.R. 292.101 et seq., otherwise known as PURPA. See "-Business-Regulatory Matters-U.S. Federal Energy Regulation." These regulations limit our ownership interest in qualifying facilities to no more than 50% due to our affiliation with Southern California Edison, a public utility. For this reason, we own a number of domestic energy projects through partnerships in which we have a 50% or less ownership interest.
•On an international basis, for purposes of risk mitigation, we have often invested in energy projects with strategic partners where our ownership interest is 50% or less. •We own a minority interest in an oil and gas company which provides a natural hedge of a portion of the fuel price risk associated with our merchant power plants.
Entities formed to own these projects are generally structured with a management committee or board of directors in which we exercise significant influence but cannot exercise unilateral control over the operating, funding or construction activities of the project entity. Our energy projects have generally secured long-term debt to finance the assets constructed and/or acquired by them. These financings generally are secured by a pledge of the assets of the project entity, but do not provide for any recourse to us. Accordingly, a default on a long-term financing of a project could result in foreclosure on the assets of the project entity resulting in a loss of some or all of our project investment, but would generally not require us to contribute additional capital. At December 31, 2001, entities which we have accounted for under the equity method had indebtedness of $6.1 billion, of which $2.6 billion is proportionate to our ownership interest in these projects.
Sale-Leaseback Transactions
We have entered into sale-leaseback transactions related to the Collins, Powerton and Joliet plants in Illinois and the Homer City Station in Pennsylvania. See "-Contractual Obligations, Commitments and Contingencies-Sale-Leaseback Commitments." Each of these transactions was completed and accounted for in accordance with Statement of Financial Accounting Standard No. 98, "Sale-Leaseback Transactions Involving Real Estate" which requires, among other things, that all the risk and rewards of ownership of assets be transferred to a new owner without continuing involvement in the assets by the former owner other than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original acquisition of the assets or to repay indebtedness previously incurred for the acquisition. In each of these transactions, the assets (or, in the case of the Collins Station, the rights to purchase them) were sold to and then leased from owner/lessors owned by independent equity investors. In addition to the equity invested in them, these owner/lessors incurred or assumed long-term debt, referred to as lessor debt, to finance the purchase of the assets. In the case of Powerton and Joliet and Homer City, the lessor debt takes the form generally referred to as secured lease obligation bonds. In the case of Collins, the lessor debt takes the form of lessor notes as described in the footnote to the table below.
The lessor equity and lessor debt associated with the sale leaseback transactions for the Collins, Powerton, Joliet and Homer City assets are summarized in the following table:
PSEG-PSEG Resources, Inc.
ACI-Associates Capital Investments LLC
GECC-General Electric Capital Corporation
(i)The owner/lessor under the Collins lease issued notes in the amount of the lessor debt to Midwest Funding LLC, a funding vehicle created and controlled by the owner/lessor. These notes mature in January 2014 and are referred to as the lessor notes. Midwest Funding, in turn, entered into a commercial paper and loan facility with a group of banks pursuant to which it borrowed the funds required for its purchase of the lessor notes. These borrowings are currently scheduled to mature in December 2004 and are referred to as the lessor borrowings.
The rent under the Collins lease includes both a fixed component and a variable component, which is affected by movements in defined interest rate indices. If the lessor borrowings are not repaid at maturity, by a refinancing or otherwise, the interest rate on them would increase at specified increments every three months, which would be reflected in adjustments to the Collins lease rent payments. Our subsidiary lessee under the Collins lease may request the owner/lessor to cause Midwest Funding to refinance the lessor borrowings in accordance with guidelines set forth in the lease, but such refinancing is subject to the owner/lessor's approval. If the lessor borrowings are not refinanced by December 2004 because the owner/lessor's approval is not obtained or a refinancing is not commercially available, rent under the Collins lease would increase by approximately $8 million each three-month period.
The operating lease payments to be made by each of our subsidiary lessees are structured to service the lessor debt and provide a return to the owner/lessor's equity investors. Neither the value of the leased assets nor the lessor debt is reflected in our consolidated balance sheet. In accordance with generally accepted accounting principles, we record rent expense on a levelized basis over the terms of the respective leases. To the extent that our cash rent payments exceed the amount levelized over the term of each lease, we record prepaid rent. At December 31, 2001, prepaid rent on these leases was $21 million. To the extent that our cash rent payments are less than the amount levelized, we reduce the amount of prepaid rent.
In the event of a default under the leases, each lessor can exercise all its rights under the applicable lease, including repossessing the power plant and seeking monetary damages. In the event of a default, distributions to us from our subsidiary may also be prohibited. Each lease sets forth a termination value payable upon termination for default and in certain other circumstances, which generally declines over time and in the case of default may be reduced by the proceeds arising from the sale of the repossessed power plant. A default under the terms of the Collins, Powerton and Joliet or Homer City leases could result in a loss of our ability to use such power plant and could have a material adverse effect on our results of operations and financial position.
In connection with the above, our subsidiaries, Midwest Generation LLC and EME Homer City LLC, account for these leases as lease financings in their separate, publicly filed financial statements because of specific guarantees provided by us or one of our subsidiary holding companies. Under SFAS No. 98, guarantees provided by us or our subsidiary holding companies (generally referred to as parent company guarantees) constitute "continuing involvement" which precludes Midwest Generation and EME Homer City from accounting for these leases as operating leases in their separate consolidated financial statements. Instead, in preparing their financial statements, each such subsidiary records the power plants as assets and the lease obligations as liabilities. In addition, these subsidiaries record depreciation and interest expense in their statements of income in lieu of operating lease expense which we record on a consolidated basis. The accounting treatment by our subsidiaries does not affect our treatment of these transactions as operating leases because the relevant guarantees are not provided by any company outside of Edison Mission Energy and its subsidiaries and, as such, do not constitute "continuing involvement" under SFAS No. 98 for purposes of our consolidated financial statements. The treatment of these leases by us as operating leases in our consolidated financial statements, rather than as lease financings as is done by our subsidiaries, results in an increase in our consolidated net income by $54.6 million in 2001 and $40.4 million in 2000.
We have also entered into a sale-leaseback of equipment, consisting primarily of Illinois peaker power units for $300 million, with an independent entity formed by Citibank. Under the terms of this
5-year lease, our subsidiary lessee operates and sells the output of these units, and has the option to repurchase the units from their current owner/lessor at the end of the lease term for the fixed price of $300 million. Should this option not be exercised, the current owner/lessor can require us, as their agent, to sell the units and, if sold, they would no longer be available to us. The lease payments are structured to pay interest and fees of the lease debt plus a return to the owner/lessor on the equity invested in it. We have guaranteed the monthly payments by our subsidiary lessee under the lease and agreed to pay the owner/lessor a deficiency payment if we do not exercise our purchase option and the proceeds from the sale of the equipment on their behalf is less than $300 million. However, in no event can the deficiency payment exceed $255 million. In order to finance its purchase of the equipment from us, the current owner/lessor obtained an equity investment of $9 million (or 3% of the acquisition price), and an additional $291 million through its issuance of senior notes in the amount of $255 million and subordinated notes in the amount of $36 million. The lease has been structured to have the equity investor maintain its $9 million investment at risk for the entire term of the lease. As part of the transaction, we purchased the senior notes from the owner/lessor and Citibank purchased the subordinated notes. Thus, if we were to exercise our option to repurchase the equipment at the end of the lease term, we would effectively need $45 million to fund this purchase as a result of our holding the senior notes. By entering into the sale-leaseback of this equipment, we obtained $45 million of additional capital. As a result of the transaction, our annual depreciation expense is reduced by approximately $15 million ($9 million after tax) during the term of the lease.
Our minimum lease obligations under our power related leases are set forth under "-Contractual Obligations, Commitments and Contingencies-Sale-Leaseback Commitments."
Parent Company Obligations to Midwest Generation
The proceeds, in the aggregate amount of approximately $1.4 billion and $300 million, received by Midwest Generation LLC from the sale of the Powerton and Joliet plants and Illinois peaker power units, respectively, described above under Sale-Leaseback Transactions were loaned to Edison Mission Energy. We used the proceeds from these loans to repay corporate indebtedness. Although interest and principal payments made by us to Midwest Generation under these intercompany loans assist in the payment of the lease rental payments owing by Midwest Generation, the intercompany obligations do not appear on our consolidated balance sheet. These obligations have been disclosed to the credit rating agencies at the time of the transactions and have been included by them in assessing Edison Mission Energy's credit ratings. The following table summarizes payments due under these intercompany loans:
We fund the interest and principal payments due under these intercompany loans from distributions from our subsidiaries, including Midwest Generation, cash on hand, and amounts available under corporate lines of credit. A default by us in the payment of these intercompany loans could result in a shortfall of cash available by Midwest Generation in meeting its lease and debt obligations. A default by Midwest Generation in meeting its obligations could in turn have a material adverse effect on us.
Master Turbine Lease
In December 2000, we entered into a master lease and related agreements which together initially provided for the construction of several new projects using in total nine turbines on order from Siemens Westinghouse. See "-Contractual Obligations, Commitments and Contingencies-Edison Mission Energy Master Turbine Lease." The master turbine were structured to be off-balance sheet in accordance with EITF 90-15 "Impact of Nonsubstantive Lessors, Residual Value Guarantees, and Other Provision in Leasing Transaction", including meeting the minimum 3% equity requirement at risk by an independent third party. During the first quarter of 2002, we exercised a purchase option, which effectively terminated the lease. Total assets that will be capitalized as a result of exercising the purchase option will be $61.1 million and will be recorded on our consolidated balance sheet.
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 that may be initiated 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. There is no assurance 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.
State-Illinois
Air Quality. In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation of incentives to promote renewable energy and the establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental Protection Agency to propose regulations based on its findings no sooner than ninety days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed, we cannot evaluate the potential impact of this legislation on the operations of our facilities.
Water Quality. The Illinois EPA is reviewing the water quality standards for the DesPlaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. One of the limitations for discharges to the river that could be made more stringent if the existing secondary contact classification is changed would be the allowable temperature of the discharges from Joliet and Will County. At this time no new standards have been proposed, so we cannot estimate the financial impact of this review.
State-Pennsylvania
Water Quality. Our coal-cleaning plant National Pollutant Discharge Elimination System, commonly referred to as NPDES, permit was recently renewed by the Pennsylvania Department of Environmental Protection, or PADEP, Bureau of Water Management. It now includes water quality-based limits for certain contaminants. We are not required to meet these limits until February 2005 but must conduct toxics reduction evaluation studies in the meantime. These limits may require upgrade of our facilities' wastewater treatment systems with such approaches as reverse osmosis, ozonation, dechlorination and/or recycling of water. We have contested these requirements in an administrative appeal, but hope to reach an amicable resolution with PADEP.
The discharge from the treatment plant receiving the wastewater stream from the Unit 3 flue gas desulfurization system has exceeded the limits for selenium in the station's NPDES permit. The selenium limits are water-quality-based and require removal to very low levels. We are investigating technical alternatives to maximize the level of selenium removal in the discharge. We are also meeting with PADEP to discuss potential modifications to the station's NPDES permit.
We conduct ground water monitoring in a number of areas throughout the site, including active and former ash disposal sites, wastewater and runoff settling and drainage ponds and a coal refuse disposal site. On September 27, 2001, the Pennsylvania Department of Environmental Protection responded to an Assessment Report by stating that no further groundwater assessment or abatement is required for the industrial waste treatment ponds.
To date, PADEP has not requested that any additional remediation actions be performed at the site. Our facilities has a drinking water treatment system designed to meet applicable potable water standards. Recent tests indicate that our facilities' drinking water supply meets these standards.
Helvetia Discharges. Our generating units were originally constructed as a mine-mouth generating station, where coal produced from two adjacent deep mines was delivered directly to the units by coal conveyors. The two adjacent deep mines were owned by Helen Mining Company, a subsidiary of the Quaker State Corporation, and Helvetia, a subsidiary of the Rochester and Pittsburgh Coal Company. Both Helen Mining and Helvetia developed mine refuse sites, water treatment facilities and other mine related facilities on the site. The Helen Mining mine was closed in the early 1990s, and the mine surface operations and maintenance shop areas were restored before Helen Mining left the site. Helen Mining has continuing mine water and refuse site leachate treatment obligations and remains obligated to perform any cleanup required with respect to its refuse site. Helvetia's on-site mine was closed in 1995. As a result of the cessation of its on-site mining activities, Helvetia has continuing mine discharge and refuse site leachate discharge treatment obligations that it performs using water treatment facilities owned by Helvetia and located on the site. Bonds posted by Helvetia may not be sufficient to fund Helvetia's obligations in the event of Helvetia's failure to comply with its mine-related permits at the site. Current annual operating costs for Helvetia's treatment systems are estimated to be approximately $1 million. If Helvetia defaults on its treatment obligations, the government may look to us to fund these commitments.
Penn Hill No. 2 and Dixon Run No. 3 Discharges. In connection with our purchase of the Homer City facilities, we acquired the Two Lick Creek Dam and Reservoir. Acid mine drainage discharges from the Penn Hill No. 2 and Dixon Run No. 3 inactive deep mines were collected and partially
treated on the reservoir property by Stanford Mining Company before being pumped off the property for additional treatment at the nearby Chestnut Ridge Treatment Plant. The mining company filed for bankruptcy, however, it operated the collection and treatment system until May 1999 when its assets were allegedly depleted.
PADEP initially advised us that we were potentially liable for treating the two discharges solely because of our ownership of the property from which the discharges emanated. Without any admission of our liability, we voluntarily entered into a letter agreement to fund the operation of the collection and treatment system for an interim period until the agency completed its investigation of potentially liable parties and alternatives for permanent treatment of the discharges were evaluated. After examining property records, PADEP concluded that we are only responsible for treating the Dixon Run No. 3 discharge. The agency completed its investigation of other potentially responsible parties, particularly mining companies that previously operated the two mines, and has notified us that they plan no further action against other parties.
A draft consent decree agreement that addresses remedial responsibilities for the two discharges has been prepared by PADEP. Under its terms, we are responsible for designing and implementing a permanent system to collect and treat the Dixon Run No. 3 discharge. We will continue our funding of the existing collection and treatment system until the Dixon Run No. 3 treatment system becomes operational. The state has provided funding to the Blacklick Creek Watershed Association to develop and operate a collection and treatment system for the Penn Hill No. 2 discharge. The Watershed Association has completed construction of the Penn Hill No. 2 system, and it will be fully operational in the next several months.
The current cost of operating the collection and treatment system is approximately $17,000 per month. We expect that the costs of operation will be reduced by 30% to 40% as a result of the completion of the Penn Hill No. 2 system. We have evaluated options for permanent treatment of the Dixon Run No. 3 discharge and concluded that conventional chemical treatment is the most appropriate option. The capital cost of the system is estimated to be $1 million. Its operational costs cannot be determined until design and permitting are complete.
Federal-United States of America
Clean Air Act. 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 $17.8 million for 2002 to install upgrades to the environmental controls at the Homer City facilities to reduce sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental controls at the Illinois plants to reduce nitrogen oxide emissions to result in expenditures of approximately $367.9 million for the 2002-2005 period.
Mercury MACT Determination. 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.
National Ambient Air Quality Standards. 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 Environmental Protection Agency 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. On March 26, 2002, the D.C. Circuit, on remand, held that the revised ozone and fine particulate matter ambient air quality standards were neither arbitrary nor capricious. Further action by the EPA with respect to the implementation of the revised ozone standard and the promulgation of a new coarse particulate matter standard is required pursuant to the first D.C. Circuit opinion and the Supreme Court's decision in Whitman v. American Trucking Associations, Inc. Because of the delays resulting from the litigation over the standards and the additional actions to be undertaken by the EPA, the impact of these standards on our facilities is uncertain at this time.
We believe that our facilities are in material compliance with applicable state and federal air quality requirements. Further reductions in emissions may be required for the achievement and maintenance of National Ambient Air Quality Standards for ozone and fine particulate matter.
Clean Water Act-§ 316(b) Rulemakings. The Environmental Protection Agency proposed rules establishing standards for the location, design, construction and capacity of cooling water intake structures at new facilities, including steam electric power plants. Under the terms of a consent decree entered into by the U.S. District Court for the Southern District of New York in Riverkeeper, Inc. v. Whitman, regulations for new facilities were adopted by November 9, 2001. Pursuant to the consent decree, the agency proposed similar regulations for existing facilities on February 28, 2002, and is required to finalize those regulations by August 28, 2003. Until the final standards are promulgated, we cannot determine their impact on our facilities or estimate the potential cost of compliance.
Comprehensive Environmental Response, Compensation, and Liability Act. Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several. The cost of investigation, remediation or removal of these substances may be substantial. In connection with the ownership and operation of our facilities, we may be liable for these costs.
In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs of removal or remediation of a release or threatened release of hazardous or toxic substances at that disposal or treatment facility, whether or not that facility is owned or operated by that person. Some environmental laws and regulations create a lien on a contaminated site in favor of the government for damages and costs it incurs in connection
with the contamination. The owner of a contaminated site and persons who arrange for the disposal of hazardous substances at that site also may be subject to common law claims by third parties based on damages and costs resulting from environmental contamination emanating from that site. In connection with the ownership and operation of our facilities, we may be liable for these costs.
With respect to our liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, we accrue a liability to the extent the costs are probable and can be reasonably estimated. Generally, we do not believe the costs for environmental remediation can be reasonably estimated before a remedial investigation has been completed for a particular site. In connection with due diligence conducted for the acquisition of our Illinois Plants, we engaged a third party consultant to conduct an assessment of the potential costs for environmental remediation of the plants. This assessment, which was based on information provided to us by the former owner of these plants, was less rigorous than a remedial investigation conducted in the course of a voluntary or required site cleanup. Accordingly, we have not recorded a liability for environmental remediation at these sites. We plan to perform or update individual site assessments as we believe is appropriate. As these assessments are completed, we will determine whether remedial investigation is needed.
Enforcement Issues. We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation ("NOV") and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoEléctrica 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, or NSR, 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, including the prior owners of the Homer City facilities, 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, several utilities have reached formal agreements with the United States (or reached agreements-in-principle) to resolve alleged NSR violations. All of the settlements have included the installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. Some of the settlements have also included the retirement or repowering of coal-fired generating units. The agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The total cost of some of these settlements exceeds $1 billion; the civil penalties agreed to by these utilities range between $1 million and $10 million. Because of the uncertainty created by the Bush Administration's review of the NSR regulations and NSR enforcement proceedings, some of the settlements referred to above have not been finalized.
In May 2001, President Bush issued a directive for a 90-day review of NSR "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy. The results of the review have been postponed with release likely sometime during the first half of 2002. President Bush also directed the Attorney General to review
ongoing NSR legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." The DOJ review was released in January 2002 and concluded "EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act."
Prior to our purchase of the Homer City facilities, 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 facilities, 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. We cannot estimate the outcome of these discussions or the potential costs of investing in additional pollution control requirements, fines or penalties at this time.
International
United Nations Framework Convention on Climate Change. Since the adoption of the United Nations Framework Convention 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.
The Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush administration announced that the United States would not ratify the Kyoto Protocol, but would instead offer an alternative. On February 14, 2002, President Bush announced objectives to slow the growth of greenhouse gas emissions by reducing the amount of greenhouse gas emissions per unit of economic output by 18% by 2012 and to provide funding for climate-change related programs. The President's proposed program does not include mandatory reductions of greenhouse gas emissions. However, various bills have been, or are expected to be, introduced in Congress to require greenhouse gas emissions reductions and to address other issues related to climate change. Apart from the Kyoto Protocol, we may be impacted by future federal or state legislation relating to controlling greenhouse gas emissions.
Notwithstanding the Bush administration position, environment ministers from around the world have reached a compromise agreement on the mechanics and rules of the Kyoto Protocol. The compromise agreement is believed to clear the way for countries to begin the treaty ratification process.
We either have an equity interest in or own and operate generating plants in the following countries:
• Australia
• Indonesia
• Italy
• New Zealand
• Philippines
• Spain
• Thailand
• Turkey
• The United Kingdom
• The United States
With the exception of Turkey, all of the countries identified have ratified the UN Framework Convention on Climate Change, as well as signed the Kyoto Protocol. None of the countries have ratified the Kyoto Protocol, but, with the exception of the United States, all are expected to do so by the end of 2002. For the treaty to come into effect, approximately 55 countries that also represent at least 55% of the greenhouse gas emissions of the developed world must ratify it.
All of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas emission reduction targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with meeting the individual national emission targets as set out within the Kyoto Protocol.
If we do become subject to limitations on emissions of carbon dioxide from our fossil fuel-fired electric generating plants, these requirements could have a significant economic impact on their operations.
Critical Accounting Policies
The accounting policies described below are viewed by management as "critical" because their correct application requires the use of material estimates and have a material impact on our financial results and position.
Derivative Instruments and Hedging Activities
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 from changes in electricity and fuel prices, interest rates, and fluctuations in foreign currency exchange rates. We segregate all of our trading and non-trading activities upon entering into each transaction.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). This Statement establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. SFAS No. 133 also 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.
Management's judgment is required to determine if transactions meet the definition of a derivative and if they do, whether the normal sales and purchases exception applies or whether individual transactions qualify for hedge accounting treatment. The majority of our power sales and fuel supply agreements related to our generation activities qualify as normal purchases and sales under SFAS No. 133 or do not meet the definition of a derivative as they are not readily convertible to cash and are, therefore, recorded on an accrual basis.
Revenue Recognition
We derive the substantial portion of our revenues from sales of physical power in the wholesale electricity market as well as from energy marketing and risk management activities. With respect to physical power sales, we consider revenue earned upon output, delivery or satisfaction of specific targets, all as specified by contractual terms, unless we are subject to SFAS No. 133 and do not qualify for the normal sales and purchases exception. Revenues under long-term power sales arrangements are generally recognized on an accrual basis. 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.
Energy Trading
Derivative financial instruments that are utilized for trading purposes are accounted for using the fair value method under SFAS No. 133 and as provided for 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 market prices, 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.
Impairment
We follow Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS No. 121) but retains the requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations.
Factors we consider important, which could trigger an impairment, include operating losses from a project, projected future operating losses, or significant negative industry or economic trends. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows from the assets, as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the fair value was less than the book value. We also record an impairment if we make a decision (which generally occurs if we reach an agreement to sell an asset) to dispose of an asset and the fair value is less than our book value. During the third quarter of 2001, we recorded $1.9 billion impairment of our Ferrybridge and Fiddler's Ferry power plants. See "-Discontinued Operations," for further discussion. We also recorded $33.7 million impairment of investment in partnerships in which we had reached an agreement to sell our investments during 2001.
Off Balance Sheet Financing
We have entered into sale-leaseback transactions related to the Collins, Powerton and Joliet plants in Illinois and the Homer City Station in Pennsylvania. See "-Contractual Obligations, Commitments and Contingencies-Sale-Leaseback Commitments." Each of these transactions was completed and accounted for by us as an operating lease in our consolidated financial statements in accordance with Statement of Financial Accounting Standard No. 98 "Sale-Leaseback Transactions Involving Real Estate" (SFAS No. 98), which requires, among other things, that all of the risk and rewards of ownership of assets be transferred to a new owner without continuing involvement in the assets by the former owner other than as normal for a lessee. These transactions were entered into to provide a source of capital either to fund the original acquisition of the assets or to repay indebtedness previously incurred for the acquisition. We have also entered into a sale-leaseback of equipment, consisting primarily of Illinois peaker power units. Each of these leases uses special purpose entities.
Based on existing accounting guidance, we believe that it is appropriate to keep our obligations under these leases off of our consolidated balance sheet. However, the Financial Accounting Standards Board and others have initiated discussions to re-evaluate the accounting for transactions involving special purpose entities. Key issues that are being addressed include equity at risk requirements (increasing the current 3% requirement to 10%) as well as the identification of the sponsor or beneficiary of the special purpose entities activities. It is likely that changes to the existing accounting guidance would result in requiring our equipment lease with respect to the Illinois peaker units to be recorded on our balance sheet. This would result in our recording additional depreciation expense.
Income Taxes
SFAS No. 109, "Accounting for Income Taxes," requires the asset and liability approach for financial accounting and reporting for deferred income taxes. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant income tax temporary differences. See, "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements-Note 12. Income Taxes" for additional details.
As part of the process of preparing our consolidated financial statements we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves us estimating our actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheet. In accordance with SFAS No. 109, we have not recorded deferred taxes on undistributed earnings of foreign subsidiaries if those earnings are to be repatriated to the United States.
For additional information regarding our accounting policies, see, "Edison Mission Energy and Subsidiaries Notes to Consolidated Financial Statements-Note 2. Summary of Significant Accounting Policies".
New Accounting Standards
Currently, we are using the normal sales and purchases exception for some of our fuel supply agreements. However, in October 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 issued guidance that precludes contracts that have variable quantities from qualifying under the normal sales and purchases exception unless such quantities are contractually limited to use by the purchaser. Accordingly, we are evaluating the impact of this implementation guidance, which will be effective on April 1, 2002.
In October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains SFAS No. 121 requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations. In addition, SFAS No. 144 broadens the reporting of discontinued operations to include a component of an entity (rather than a segment of a business) that has been disposed of or is classified as held for sale. The standard, effective on January 1, 2002, was adopted by us in the fourth quarter of 2001, which required the sale of the Ferrybridge and Fiddler's Ferry power plants to be accounted for as discontinued operations. See "-Discontinued Operations," for further discussion.
In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," which will be effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. We are studying the effects of the new standard.
Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. A benchmark assessment for goodwill is required no later than June 30, 2002. The Statement requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the goodwill over the implied fair value. Goodwill on our consolidated balance sheet at December 31, 2001 totaling $631.7 million is comprised of $359.5 million related to the Contact Energy acquisitions, $247.4 million related to the First Hydro acquisition and $24.8 million related to the Citizens Power LLC acquisition. We have not completed our assessment of the effects of adopting SFAS No. 142.
Recent Developments
On February 10, 2002, the ductwork and bypass associated with the selective catalytic reduction system of one of the units at the Homer City facilities, known as Unit 3, collapsed. No fire occurred and no injuries were reported as a result of the event.
We have now completed a preliminary investigation of the event and currently project that Unit 3 will return to service in mid-April 2002. We also believe that the costs to repair the damage to Unit 3 will be covered by insurance and by contractual obligations of the contractor who installed the selective catalytic reduction system. Further, for events of this kind we maintain business interruption insurance that provides for lost revenues, net of costs, for outage periods beyond 60 days. A more in-depth analysis of the root causes of the event is required to determine the extent to which insurers and/or the contractor will cover the resulting costs of property damage and repair. This investigation continues.
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 Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income (loss), comprehensive income (loss), shareholder's equity and cash flows for each of the three years in the period ended December 31, 2001. 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 financial statements referred to above present fairly, in all material respects, the financial position of Edison Mission Energy and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.
As explained in Note 2 to the financial statements, effective January 1, 2001, the Company has changed its method of accounting for derivative instruments and hedging activities in accordance with SFAS No. 133, "Accounting for Derivatives Instruments and Hedging Activities," and its method of accounting for the impairment or disposal of long-lived assets in accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets."
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 25, 2002
EDISON MISSION ENERGY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(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 COMPREHENSIVE INCOME (LOSS)
(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 Mission Energy Holding Company, 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.
Mission Energy Holding Company
On June 8, 2001, our ultimate parent company, Edison International, created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset is our common stock. In July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a new term loan. The senior secured notes and the term loan are secured by a first priority security interest in our common stock. Any foreclosure on the pledge of our common stock by the holders of the senior secured notes or the lenders under the term loan could result in a change of control of us. A change in control of us could require us to prepay indebtedness in our debt agreements or debt agreements of our subsidiaries. The respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with respect to our stock are governed by intercreditor arrangements. Both the senior secured notes and the term loan also have security interests in interest reserve accounts, covering the interest payable on those obligations for the first two years. We have not guaranteed either the senior secured notes or the term loan, both of which are non-recourse to us. The net proceeds of the offering and the term loan not deposited into the respective interest escrow accounts were used to pay a dividend to Mission Energy Holding's parent, The Mission Group, which in turn loaned the net proceeds to its parent, Edison International. Edison International used the funds to repay a portion of its indebtedness that matured in 2001. The Mission Energy Holding financing documents contain restrictions on our ability and the ability of our subsidiaries to enter into specified transactions or engage in specified business activities and require, in some instances, that we obtain the approval of the Mission Energy Holding's board of directors. Our articles of incorporation bind us to the restrictions in Mission Energy Holding's financing documents by restricting our ability to enter into specified transactions or engage in specified business activities, other than as permitted in Mission Energy Holding's financing documents, without shareholder approval.
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. Except as indicated, amounts reflected in the notes to the consolidated financial statements relate to continuing operations of Edison Mission Energy.
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 $230.7 million and $226.4 million at December 31, 2001 and 2000, respectively, 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, 2001 and 2000. 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 facilities, 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 $65.7 million and $38.8 million at December 31, 2001 and 2000, respectively. On January 1, 2002, the amortization of goodwill ceased upon adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." See "New Accounting Standards" for further discussion.
Impairment of Investments and Long-Lived Assets
We periodically evaluate the potential impairment of our investments in projects and other long-lived assets 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. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," 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 12-Income Taxes.
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). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we recorded a $21.8 million, after tax, increase to income from continuing operations, as the cumulative effect of 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 $44.0 million in 2001 and $24.4 million in 2000.
Derivative Instruments and Hedging Activities
Our primary market risk exposures arise from changes in electricity and fuel prices, interest rates 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. Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that derivative instruments be recorded in the balance sheet as either assets or liabilities measured at their fair value unless they meet an exception. 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.
Effective January 1, 2001, we recorded all derivatives at fair value unless the derivatives qualified for the normal sales and purchases exception. This exception applies to physical sales and purchases of power or fuel where it is probable that physical delivery will occur, the pricing provisions are clearly and closely related to the contracted prices and the documentation requirements of SFAS No. 133 are met.
Accounting for derivatives under SFAS No. 133 is complex. Each transaction requires an assessment of whether it is a derivative according to the definition under SFAS No. 133, including amendments and interpretations. Transactions that do not meet the definition of a derivative are accounted by us on the accrual basis, unless they relate to our trading operations, in which case they are accounted for using the fair value method under EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities". The majority of our physical long-term power and fuel contracts, and the similar business activities of our affiliates, either do not meet the definition of a derivative or qualify for the normal purchases and sales exception.
As a result of the adoption of SFAS No. 133, we expect our quarterly earnings will be more volatile than earnings reported under the prior accounting policy.
Discussion of Initial Adoption of SFAS No. 133
On January 1, 2001, we recorded a $0.2 million, after tax, increase to income from continuing operations and a $230.2 million, after tax, decrease to other comprehensive income as the cumulative effect of the adoption of SFAS No. 133. The following material items were recorded at fair value:
•The forward sales contracts from our Homer City facilities qualified as cash flow hedges. We did not use the normal sales and purchases exception for these forward sales contracts due to our net settlement procedures with counterparties as discussed below under "Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133." As a result of higher market prices for forward sales from our Homer City facilities, we recorded a liability of $115.9 million at January 1, 2001, deferred tax benefits of $54.1 million and a decrease in other comprehensive income of $61.8 million.
•The hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia qualified as a cash flow hedge. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. As a result of higher market prices for forward sales from our Loy Yang B plant, we recorded a liability of $227 million at January 1, 2001, deferred tax benefits of $68.1 million and a decrease in other comprehensive income of $158.9 million.
•The majority of our activities related to the fuel contracts for our Collins Station in Illinois did not qualify for either the normal purchases and sales exception or as cash flow hedges. We could not conclude, based on information available at January 1, 2001, that the timing of generation from the Collins Station met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, these contracts were recorded at fair value, with subsequent changes in fair value reflected in net gains (losses) from energy trading and price risk
management in our consolidated income statement. We have continued to record fuel contracts for our Collins Station at fair value.
Discussion of July 1, 2001 Adoption of Interpretations of SFAS No. 133
Effective July 1, 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C15 modified the normal sales and purchases exception to include electricity contracts which include terms that require physical delivery by the seller in quantities that are expected to be sold in the normal course of business. This modification had two significant impacts:
•As a result of the new interpretation, our Homer City forward sales contracts qualified for the normal sales and purchases exception commencing July 1, 2001. Based on this accounting guidance, on July 1, 2001, we eliminated the value of the Homer City forward sales contracts from our consolidated balance sheet. The cumulative effect of this change in accounting is reflected as a $15.5 million, after tax, decrease to other comprehensive income in 2001.
•For the period between January 1, 2001 through June 30, 2001, we applied the normal sales and purchases exception for long-term commodity contracts that included both selling and purchasing electricity by our First Hydro plant. However, the criteria applicable to the buyer of power outlined under Statement No. 133 Implementation Issue Number C15 precluded the contracts from qualifying under the normal sales and purchases exception as of July 1, 2001 because First Hydro is not contractually obligated to maintain sufficient capacity to meet electricity needs of a customer. Accordingly, we recorded a $14.9 million, after tax, increase to income from continuing operations as the cumulative effect of change in accounting for derivatives in the consolidated income statement as of July 1, 2001. All subsequent changes in the fair value of these contracts were reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.
Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, of a derivative's change in fair value is immediately recognized in earnings. We recorded a net loss of $1.4 million in 2001, representing the amount of cash flow hedges' ineffectiveness, reflected in net gains (losses) from energy trading and price risk management in our consolidated income statement.
Revenue Recognition
We record revenue and related costs as electricity is generated or services are provided unless we are subject to SFAS No. 133 and do not qualify for the normal sales and purchases exception. 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.
Note 2. Summary of Significant Accounting Policies (Continued)
Energy Trading
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 market prices, 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 $7.1 million, $12.8 million and ($1.7) million for 2001, 2000 and 1999, respectively.
Stock-based Compensation
We measure compensation expense relative to stock-based compensation by the intrinsic-value method.
New Accounting Standards
Currently, we are using the normal sales and purchases exception for some of our fuel supply agreements. However, in October 2001, the Derivative Implementation Group of the Financial Accounting Standards Board under Statement No. 133 Implementation Issue Number C16 issued guidance that precludes contracts that have variable quantities from qualifying under the normal sales and purchases exception unless such quantities are contractually limited to use by the purchaser. Accordingly, we are evaluating the impact of this implementation guidance, which will be effective on April 1, 2002.
In October 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The Statement establishes accounting and reporting standards for the impairment or disposal of long-lived assets. The Statement supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains SFAS No. 121 requirements to recognize an impairment loss only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and to measure an impairment loss as the difference between the carrying amount and fair value of the asset less cost to sell, whether reported in continuing operations or in discontinued operations. In addition, SFAS No. 144 broadens the reporting of discontinued operations to include a component of an entity (rather than a segment of a business) that has been disposed of or is classified as held for sale. The standard, effective on January 1, 2002, was adopted by us in the fourth quarter of 2001, which required the sale of the Ferrybridge and Fiddler's Ferry power plants to be accounted for as discontinued operations. See Note 6-Discontinued Operations, for further discussion.
In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," which will be effective on January 1, 2003. The Statement requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. We are studying the effects of the new standard.
Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets." The Statement establishes accounting and reporting standards requiring goodwill not to be amortized but rather tested for impairment at least annually at the reporting unit level. A benchmark assessment for goodwill is required no later than June 30, 2002. The Statement requires that goodwill should be tested for impairment using a two-step approach. The first step used to identify a potential impairment compares the fair value of a reporting unit to its carrying amount, including goodwill. If the fair value of the reporting unit is less than its carrying amount, the second step of the impairment test is performed to measure the amount of the impairment loss. The second step of the impairment test is a comparison of the implied fair value of goodwill to its carrying amount. The impairment loss is equal to the excess carrying amount of the goodwill over the implied fair value. Goodwill on our consolidated balance sheet at December 31, 2001 totaling $631.7 million is comprised of $359.5 million related to the Contact Energy acquisitions, $247.4 million related to the First Hydro acquisition and $24.8 million related to the Citizens Power LLC acquisition. We have not completed our assessment of the effects of adopting SFAS No. 142.
Note 3. Inventory
Inventory is stated at the lower of weighted average cost or market. Inventory at December 31, 2001 and December 31, 2000 consisted of the following:
Note 4. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss), including the discontinued operations of the Ferrybridge and Fiddler's Ferry power plants, consisted of the following:
Unrealized gains (losses) on cash flow hedges at December 31, 2001 included interest rate swaps of our affiliates and the Loy Yang B project and the hedge agreement we have with the State Electricity Commission of Victoria for electricity prices from our Loy Yang B project in Australia. This contract could not qualify under the normal sales and purchases exception because financial settlement of the contract occurs without physical delivery. Approximately 57% of our accumulated other comprehensive loss at December 31, 2001 related to unrealized losses on the cash flow hedge resulting from this contract. These losses arise from current forecasts of future electricity prices in these markets greater than our contract prices. Although the contract prices are below the current market prices, we believe that prices included in our contracts mitigate price risk associated with future changes in market prices and are at prices that meet our profit objectives. Assuming the long-term contract with the State Electricity Commission of Victoria continues to qualify as a cash flow hedge, future changes in the forecast of market prices for contract volumes included in this agreement will increase or decrease our other comprehensive income without significantly affecting our net income.
As our hedged positions are realized, approximately $13 million, after tax, of the net unrealized gains on cash flow hedges will be reclassified into earnings during 2002. Management expects that these net unrealized gains will be offset when the hedged items are recognized in earnings. The maximum period over which a cash flow hedge is designated, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is 15 years.
Note 5. Acquisitions and Dispositions
Acquisitions
Acquisition of Interest in CBK Power Co. Ltd.
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 728 MW Caliraya-Botocan-Kalayaan (CBK) hydroelectric project located in the Philippines. Financing for this $460 million project comprises equity commitments of $110.6 million, of which our 50% share is $55.3 million, and debt financing which is in place for the remainder of the cost for this project. As of December 31, 2001, we have made equity contributions of $10 million. For a more detailed discussion of the commitment to contribute project equity, refer to "-Commitments and Contingencies-Firm Commitments to Contribute Project Equity."
Acquisition of Sunrise Project
On November 17, 2000, we completed a transaction with Texaco Power & Gasification Holdings 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 had an option to repurchase, at cost, a 50% interest in the project prior to its commercial operation, which commenced on June 27, 2001. On June 25, 2001, Texaco exercised its option and repurchased a 50% interest for $84 million. As part of our acquisition of the Sunrise project, we also: (i) acquired from Texaco two gas turbines for the project and (ii) granted Texaco an option to acquire a 50% interest in 1,000 MW of future power plant projects we designate. The Sunrise project consists of two phases, with Phase I, a simple-cycle gas-fired facility (320 MW), completed on June 27, 2001, and Phase II, conversion to a combined-cycle gas-fired facility (560 MW), currently scheduled to be completed in July 2003. We entered into a long-term power purchase agreement with the California Department of Water Resources on June 25, 2001.
The total purchase price of the Sunrise project from Texaco was $27 million. We funded the purchase with cash. The total estimated construction cost of this project through 2003 is approximately $459 million. The project intends to obtain project financing for a portion of the capital costs.
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 operations beyond the traditional marketing of our electric power to include trading of electricity and fuels, although this represents a small portion of our consolidated operations. 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 Project
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. At December 31, 2001, 230 MW have been commissioned and are operational. Assuming all the projects under construction at December 31, 2001 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, with equity contribution obligations of up to 33 billion Italian Lira, depending on the number of projects that are ultimately developed. As of December 31, 2001, our payments in respect of these projects included 77 billion Italian Lira ($37.4 million) toward the purchase price and 33 billion Italian Lira ($16.3 million), which funded our entire equity contribution obligation.
Acquisition of Illinois Plants
On December 15, 1999, we completed a transaction with Commonwealth Edison, now 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 are located in the Mid-America Interconnected Network which has transmission connections to the East Central Area Reliability Council and other regional markets. In connection with this transaction, we entered into three power purchase agreements with Commonwealth Edison with terms of up to five years expiring in 2004, 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. Exelon Generation provided us notice to continue the agreement related to the coal units and the Collins Station for 2002. In October 2001, Exelon Generation terminated the power purchase agreement for the peaker units with respect to 300 megawatts of oil peakers, effective January 2002, but continued the agreement for all other peaker plants for 2002. In each of 2003 and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the option to terminate all or any of the remaining coal units and all of the natural gas and oil-fired units with prior notice as specified under each agreement.
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 MW 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 our debt and $1.2 billion in equity contributions to us from Edison International.
Acquisition of Interest in Contact Energy
On May 14, 1999, we completed a transaction with the New Zealand government to acquire 40% of the shares of Contact Energy Limited. The remaining 60% of Contact Energy's shares were sold in a New Zealand and 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. 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 2,302 MW.
Consideration for our interest in Contact Energy consisted of a cash payment of approximately $635 million (NZ$1.2 billion), which was financed by $120 million of preferred securities, a $214 million (NZ$400 million 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.
During 2000, we increased our share of ownership in Contact Energy to 42.6%. Subsequently, during the second quarter of 2001, we completed the purchase of additional shares of Contact Energy for NZ$152 million, thereby increasing our ownership interest from 42.6% to 51.2%. Due to acquisition of a controlling interest, we began accounting for Contact Energy on a consolidated basis effective June 1, 2001. Prior to June 1, 2001, we used the equity method of accounting for Contact Energy. In order to finance the purchase of the additional shares, we obtained a NZ$135 million, 364-day bridge loan from an investment bank under a credit facility which was syndicated by the bank. In addition to other security arrangements, a security interest over all Contact Energy shares held by us has been provided as collateral. On July 2, 2001, we redeemed NZ$400 million preferred securities issued by one of our subsidiaries EME Taupo. Funding for the redemption of the existing preferred securities was provided by a NZ$400 million credit facility scheduled to mature in July 2005. The financing documents provide that the credit facility may be funded under either, or a combination of, a letter of credit facility or a revolving credit facility. The NZ$400 million was originally funded as a revolving credit facility. From June 2001 to October 2001, we issued NZ$250 million of new preferred securities through one of our subsidiaries. The proceeds were used to repay borrowings outstanding under the NZ$400 million credit facility and to repay the bridge loan.
On October 12, 2001, we announced our intention to acquire the remaining 48.8% of Contact Energy that we do not own, thereby increasing our ownership interest to 100%. We proposed an offer of NZ$4.25 per share, including an interim dividend of NZ$0.11 per share, to the minority shareholders payable in cash. The offer commenced on November 6, 2001 and was extended until February 3, 2002. The offer was conditioned on our acquiring a 90% interest in Contact Energy, which would have enabled us to acquire the remaining minority interests through a merger. On February 4, 2002, we announced that we did not receive the necessary level of acceptances required to complete the transaction, and, therefore, we currently plan to continue with our current 51.2% ownership interest.
Acquisition of Homer City Facilities
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 facilities 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.
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 Sunrise beginning July 1, 2001, Citizens beginning September 1, 2000, Italian Wind beginning April 1, 2000, the Homer City facilities beginning March 18, 1999, Contact Energy beginning May 1, 1999, and the Illinois Plants beginning December 15, 1999. We began accounting for Contact Energy on a consolidated basis effective June 1, 2001, upon acquisition of a controlling interest.
Pro Forma Data
Pro forma data has not been provided for the acquisitions of the Homer City facilities 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 Edison Mission Energy's results of operations or financial position.
The table below summarizes additional acquisitions by Edison Mission Energy or its wholly-owned subsidiaries from 1999 through 2001.
Dispositions
On December 21, 2001, we completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. In accordance with SFAS No. 144, the results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated financial statements. See "-Discontinued Operations." The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.148 billion after tax) related to the loss on disposal. Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants.
During 2001, we also sold our 50% interest in the Nevada Sun-Peak project, 50% interest in the Saguaro project and 25% interest in the Hopewell project for a total gain on sale of $45 million ($24.4 million after tax). In addition, we entered into agreements, subject to obtaining consents from third parties and other conditions precedent to closing, for the sale of our interests in the Commonwealth Atlantic, Gordonsville, EcoEléctrica, Harbor and James River projects. During 2001, we recorded asset impairment charges of $33.7 million related to the Commonwealth Atlantic, Gordonsville, Harbor and James River projects based on the expected sales proceeds. Subsequent to December 31, 2001, we completed the sales of our 50% interests in the Commonwealth Atlantic and James River projects and our 30% interest in the Harbor project for $47.7 million. The sales of our interests in the EcoEléctrica and Gordonsville projects have not closed, and in each case the sale agreement has terminated and we have recommenced marketing efforts. On March 8, 2002, we filed a complaint against Mirant Corporation and two of its affiliates, alleging that Mirant wrongfully terminated the sales agreement for the purchase of the EcoEléctrica project. We are currently offering for sale our interests in the Brooklyn Navy Yard, EcoEléctrica and Gordonsville projects.
On June 25, 2001, we completed the sale of a 50% interest in the Sunrise project to Texaco Power & Gasification Holdings Inc. Proceeds from the sale were $84 million.
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).
Note 6. Discontinued Operations
On December 21, 2001, Edison First Power Limited completed the sale of the Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom to two wholly-owned subsidiaries of American Electric Power. In addition, as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated with the plants. The sale is the result of a competitive bidding process. We acquired the plants in 1999 from PowerGen UK plc for £1.3 billion. The results of Ferrybridge and Fiddler's Ferry have been reflected as discontinued operations in the consolidated
financial statements in accordance with SFAS No. 144. The consolidated financial statements have been restated to conform to discontinued operations treatment for all historical periods presented.
Net proceeds from the sales of £643 million were used to repay borrowings outstanding under the existing debt facility related to the acquisition of the power plants. The early repayment of the projects' existing debt facility of £682.2 million at December 21, 2001 resulted in an extraordinary loss of $28 million, after tax, attributable to the write-off of unamortized debt issue costs.
Effective January 1, 2001, we recorded a $5.8 million, after tax, increase to income (loss) from discontinued operations, as the cumulative effect of change in accounting for derivatives. The majority of our activities related to the Ferrybridge and Fiddler's Ferry power plants did not qualify for either the normal purchases and sales exception or as cash flow hedges under SFAS No. 133. We could not conclude, based on information available at December 31, 2000, that the timing of generation from these power plants met the probable requirement for a specific forecasted transaction under SFAS No. 133. Accordingly, the majority of these contracts were recorded at fair value with subsequent changes in fair value recorded through the income statement.
Effective January 1, 2000, we recorded a $4.1 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting for major maintenance costs. Through December 31, 1999, we accrued for major maintenance costs incurred during the period at the Ferrybridge and Fiddler's Ferry power plants between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred.
Summarized results of discontinued operations are as follows:
The loss from operations of Ferrybridge and Fiddler's Ferry in 2001 includes $1.9 billion ($1.148 billion after tax) related to the loss on disposal. Included in the loss on disposal is the asset impairment charge of $1.9 billion ($1.154 billion after tax) we recorded in the third quarter of 2001 to reduce the carrying amount of the power plants to reflect the estimated fair value less the cost to sell and related currency adjustments.
Note 6. Discontinued Operations (Continued)
The following summarizes the balance sheet information of the discontinued operations:
Net operating and capital loss carryforwards totaled approximately $1.4 billion at December 31, 2001. Although there are no expiration dates related to the use of these loss carryforwards, our ability to offset taxable income with these carryforwards is subject to substantial restrictions and limitations under U.K. tax regulations. Accordingly, no income tax benefits have been recognized for these tax loss carryforwards.
Note 7. 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 $257.1 million at December 31,
2001. 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, 2001 consist of the following: a $110.9 million, 10% interest loan, due on demand; a $26.3 million, 5% interest promissory note, interest payable semiannually, due April 2008; and a $35.6 million, 12% interest loan, due on demand.
The undistributed earnings of investments accounted for by the equity method were $330.7 million in 2001 and $270.7 million in 2000.
The following table presents summarized financial information of the investments primarily 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, 2001, 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.
Investments in Oil and Gas
At December 31, 2001, we had one 37.2%-owned (with 36.05% 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 $9.2 million at December 31, 2001. 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 December 2001, we purchased additional shares in Four Star for $7.4 million, increasing our interest from 35.84% to 37.20%. 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 continued 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 the profits and losses of 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 8. 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 9. Financial Instruments
Short-Term Obligations
At December 31, 2001, we had available $554.3 million of borrowing capacity and approximately $115.7 million in letters of credit issued under a $750 million revolving credit facility that expires in September 2002 (Tranche A, consisting of the $80 million outstanding borrowing) and September 2004 (Tranche B). At December 31, 2001, other short-term borrowings consisted of a 55 million Australian dollar construction facility for the Valley Power project due November 2002 of which US$23.7 million was outstanding and a floating rate note due March 2002, which relates to the Contact Energy project.
Our corporate facilities include the following financial covenants:
Financial Ratio
Covenant
Actual at December 31,
Description
Recourse Debt to Recourse Capital Ratio
#67.5%
64.1%
Ratio of (a) senior recourse debt to (b) sum of (i) shareholders equity per our balance sheet adjusted by comprehensive income after December 31, 1999, plus (ii) senior recourse debt
Interest Coverage Ratio
a1.50 to 1.00
1.64 to 1.00
For prior 12-month period, ratio of (a) funds flow from operations to (b) interest expense on recourse debt
At December 31, 2001, we met the above financial covenants. The actual interest coverage ratio during 2001 was adversely affected by the operating results of the Ferrybridge and Fiddler's Ferry projects in the United Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects, was 1.98 to 1.0. Compliance with these covenants is subject to future financial performance, including items that are beyond our control.
At December 31, 2000, commercial paper consisted of a $700 million senior credit facility due May 2001 of which $444.2 million was outstanding. Other short-term obligations consisted of a borrowing under the $700 million senior credit facility and the $300 million senior credit facility due
May 2001 of which $128.5 million and $283.5 million were outstanding, respectively, at December 31, 2000.
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, 2001, recourse debt totaled $2 billion and non-recourse project debt totaled $3.9 billion. Long-term obligations consist of the following:
Bond Financing of First Hydro
The ability of our subsidiary to make payments of interest on the bond financing of First Hydro bonds is dependent on revenues generated by the First Hydro plant, which depend on market conditions for the sale of energy and ancillary services. These market conditions are beyond our control. The financial covenants included in the bond financing of First Hydro require our subsidiary to maintain a minimum interest coverage ratio for each trailing twelve-month period as of June 30 and December 31 of each year. Our subsidiary was in compliance with this ratio for the twelve months ended December 31, 2001. Compliance with this ratio depends on market conditions for the sale of energy and ancillary services. There is no assurance that these requirements will be met and, if not met, will be waived by the holders of First Hydro's bonds. The bond financing documents stipulate that a breach of a financial covenant constitutes an immediate event of default and, if the event of default is not waived or cured, the holders of the First Hydro bonds are entitled to enforce their security over First Hydro's assets, including its power plants.
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% (2.62% at December 31, 2001). The note was subsequently exchanged for two notes with the same terms and conditions and assigned to other subsidiaries of Edison International.
Financing of the Homer City Facilities
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 facilities. 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 a result of the bond financing described below. The $250 million facility has since been repaid and retired as a result of the sale-leaseback of our Homer City facilities assets on December 7, 2001. These loans were structured on a limited-recourse basis in which the lenders look primarily to the cash generated by the Homer City facilities to repay the debt and took a security interest in the Homer City facilities assets. We used amounts available under the $250 million five-year term loan facility to fund environmental capital improvements at the Homer City facilities and never drew down on the $50 million five-year revolving credit facility. The $50 million facility was also retired as a result of the sale-leaseback transaction.
In May 1999, Edison Mission Holdings Co. completed an $830 million bond financing. The financing consisted of (1) $300 million, 8.137% Senior Secured Bonds due 2019 and (2) $530 million, 8.734% Senior Secured Bonds due 2026. These bonds were non-recourse to us apart from the Credit Support Guarantee and Debt Service Reserve Guarantee entered into by us. These bonds, and related guarantees by us, have since been assumed by the buyer as a result of the sale-leaseback of our Homer City facilities assets. In connection with the extinguishment of the bonds, we recorded an extraordinary gain of $5.7 million, net of income tax expense of $4.4 million. See Note 16-Lease Commitments-Sale-Leaseback Transactions, for further discussion about the sale-leaseback.
Financing of the Ferrybridge and Fiddler's Ferry Plants
As part of the financing of the Ferrybridge and Fiddler's Ferry plants, we had entered into a 359 million pounds sterling Coal and Capex Facility due January 2004 and July 2004, respectively. Following the completion of the sale of the power plants, this facility was cancelled. We plan to repay the borrowings outstanding under the Coal and Capex Facility from settlement of the remaining assets and liabilities of our discontinued operations and cash flows generated from our foreign subsidiaries prior to its maturity in 2004.
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, 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. On January 6, 2001, Tranche B was decreased from $816 million to $808.3 million. During December 2001, the $911 million revolving credit facility, Tranche B, due date was extended to 2003. Under the working capital revolving facility, Tranche C, $150 million and $6.6 million of borrowing capacity was available at December 31, 2001 and 2000, respectively.
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. During 2001, the amount outstanding was repaid.
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, 2001, for the next five years, excluding capital leases (see Note 16) are summarized as follows: 2002-$190.3 million; 2003-$1,057.0 million; 2004-$1,209.4 million; 2005-$219.2 million, and 2006-$75.3. 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 included in our consolidated balance sheet under the
caption "Restricted cash and other assets" was $281.8 million at December 31, 2001 and $121.0 million at December 31, 2000. Debt service reserves classified in Restricted cash and other assets (including reserves for interest on annual lease payments) were $49.2 million at December 31, 2001 and $75.1 million at December 31, 2000.
Collateral reserves classified in Restricted cash and other assets were $74.3 million at December 31, 2001 as required by the Edison Mission Energy Turbine Trust agreement entered into on December 4, 2000. This agreement is discussed further in Note 16-Lease Commitments-Sale-Leaseback Transactions.
Each of our direct and 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 subsidiaries, be advanced, loaned, paid as dividends or otherwise distributed or contributed to us or our affiliates.
Fair Values of Non-Derivative Financial Instruments
The following table summarizes the fair values for outstanding non-derivative financial instruments:
In assessing the fair value of our financial instruments, 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 derivatives, long-term obligations and preferred securities. Foreign currency forward exchange agreements and cross currency interest rate swaps 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.
Note 10. Risk Management and Derivative Financial Instruments
Our risk management policy allows for the use of derivative financial instruments to limit financial exposure on our investments and to manage exposure from changes in electricity and fuel prices, interest rates and fluctuations in foreign currency exchange rates 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. 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 the use of stress testing and worst-case scenario analysis, as well as stop loss 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, interest rate options 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 our fixed to variable swap agreements, the fixed interest rate payments are at a weighted average rate of 5.972% and 5.65% at December 31, 2001 and 2000, respectively. Variable rate payments under our corporate agreements are based on six-month LIBOR capped at 9%. Variable rate payments pertaining to our foreign subsidiary agreements are based on an equivalent interest rate benchmark to LIBOR. The weighted average rate applicable to these agreements was 2.803% and 5.605% at December 31, 2001 and 2000, respectively. Under the variable to fixed swap agreements, we will pay counterparties interest at a weighted average fixed rate of 7.118% and 7.59% at December 31, 2001 and 2000, respectively. Counterparties will pay us interest at a weighted average variable rate of 4.762% and 6.43% at December 31, 2001 and 2000, respectively. The weighted average variable interest rates are based on LIBOR or equivalent interest rate benchmarks for foreign denominated interest rate swap agreements. Under our interest rate options, the weighted average strike interest rate is 6.76%.
Note 10. Risk Management and Derivative Financial Instruments (Continued)
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 36% and 42% of our consolidated operating revenues in 2001 and 2000, respectively. Any failure by Exelon Generation 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 15-Commitments and Contingencies. 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 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 facilities 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. 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, 2001, we had outstanding foreign currency forward exchange contracts and cross currency interest rate swap contracts entered into in the ordinary course of business to offset certain operational and balance sheet exposures from adverse currency rate fluctuations with varying maturities through April 2018. The periods of the contracts correspond to the periods of the hedged transactions.
Non-Trading Derivative Financial Instruments
The following table summarizes the fair values for outstanding derivative financial instruments used for purposes other than trading by risk category and instrument type:
In assessing the fair value of our non-trading derivative financial instruments, we use a variety of methods and assumptions that are based on market conditions and risk existing at each balance sheet date. The fair value of the commodity price contracts considers quoted marked prices, time value, volatility of the underlying commodities and other factors.
The fair value of the electricity rate swaps agreements (included under commodity price-swaps) entered into by the Loy Yang B plant in 2001 and 2000 and the First Hydro plant in 2000 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.
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 operations beyond the traditional marketing of our electric power to include trading of electricity and fuels. In conducting our trading activities, we seek to generate profit from price volatility of electricity and fuels by buying and selling these commodities in wholesale markets. We generally balance forward sales and purchases contracts and manage our exposure through a value at risk analysis as described further below. We also conduct price risk management activities with third parties not related to our power plants or investments in energy projects, including the restructuring of power sales and power supply agreements.
The fair value of the financial instruments, including forwards, futures, options and swaps, related to trading activities as of December 31, 2001 and 2000, which include energy commodities, are set forth below:
Quoted market prices are used to determine the fair value of the financial instruments related to trading activities.
The net realized and change in unrealized gains or losses arising from trading activities for the year ended December 31, 2001 and the period from inception (September 1, 2000) to December 31, 2000 are as follows:
The change in unrealized gain (loss) from trading and price risk management activities included in the above amounts was ($12.2) million and $11.7 million for the year ended December 31, 2001 and the period ended December 31, 2000, respectively.
Note 11. Preferred Securities
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 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. No securities have been redeemed as of December 31, 2001. 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, with mandatory redemption in 2025 at a redemption price of $25 per security, plus accrued and unpaid distributions. No securities have been redeemed as
of December 31, 2001. 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 our common stock if at such time (i) we shall be in default with respect to our 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 our selection of an extended interest payment period as provided in the indenture and such period, or any extension thereof, shall be continuing.
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 ranged from 6.19% to 6.86%. The shares were redeemable in June 2003 at 10,000 New Zealand dollars per share. 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 ranged from 5.00% to 6.37%. The shares were redeemable at one New Zealand dollar per share in June 2001 (64 million), June 2002 (43 million), and June 2003 (133 million).
On July 2, 2001, the Class A Redeemable Preferred Shares were redeemed at 10,000 New Zealand dollars per share and the retail redeemable preferred shares were redeemed at one New Zealand dollar per share from the existing holders. Funding for the redemption of the shares was provided by a NZ$400 million credit facility scheduled to mature in July 2005.
From June through October 2001, Mission Contact Finance Limited issued $104 million of Redeemable Preferred Shares (250 million shares at a price of one New Zealand dollar per share). The dividend rate is 6.03%. The shares are redeemable in July 2006 at one New Zealand dollar per share. Mission Contact Finance Limited is a special purpose company established by Mission Energy Universal Holdings (Universal) to raise funds from the public and other institutional subscribers, to be used by it to subscribe for redeemable preferred shares in Mission Energy Pacific Holdings (Pacific). Universal and Pacific are wholly-owned subsidiaries of Edison Mission Energy. Mission Contact Finance will call on Pacific to redeem Pacific's Redeemable Preferred Shares held by Mission Contact Finance as and when necessary to provide it with the funds required to redeem the Mission Contact Finance Redeemable Preferred Shares. The redemption of the shares can be accelerated if Mission Contact Finance exercises its option under the terms of the issue of the shares to redeem all or part of the shares, at its discretion, by giving 45 days' irrevocable notice to the holders. Events of default will result in automatic redemption. Optional early redemption may occur if the holders pass an extraordinary resolution to redeem the shares if Mission Contact Finance or Pacific ceases to be a subsidiary of Edison Mission Energy, or in the case of failure by Pacific to comply with the terms of the security trust deed. The Mission Contact Finance Redeemable Preferred Shares rank ahead of the ordinary shares in Mission Contact Finance for payment of amounts due on the shares. The holders of the shares have a shared indirect security interest, through a security trustee, in all of the ordinary shares of Contact Energy held by Pacific. The Security Trust Deed secures a limited recourse guarantee
by Pacific of Mission Contact Finance's payment obligations to holders of the redeemable preferred shares. Mission Contact Finance may not, without the security trustee's prior written consent, make any distribution after an enforcement event (primarily a payment default) has occurred which remains unremedied.
Note 12. 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 for continuing operations were:
Foreign loss carryforwards, primarily Australian, total $196.5 million and $281 million at December 31, 2001 and 2000, respectively, with $11 million expiring in 2005. State loss carryforwards total $87 million for California, $18 million for Pennsylvania and $184 million for Illinois at December 31, 2001 with various expiration dates. State capital loss carryforwards total $186 million and $309 million at December 31, 2001 and 2000, respectively, with $186 million expiring in 2005.
The components of income (loss) before income taxes and minority interest applicable to continuing operations are as follows:
United States income taxes have not been provided on unrepatriated foreign earnings in the amounts of $483 million and $440 million at December 31, 2001 and 2000, respectively. In addition, foreign income taxes have not been provided on unrepatriated foreign earnings from a different foreign jurisdiction in the amount of $75 million and $151 million at December 31, 2001 and 2000, respectively.
The provision (benefit) for income taxes applicable to continuing operations is comprised of the following:
The components of the deferred tax provision from continuing operations, which arise from tax credits and timing differences between financial and tax reporting, are presented below:
Variations from the 35% federal statutory rate for income from continuing operations 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 13. 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, 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 for Ferrybridge and Fiddler's Ferry totaled $1 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. Amounts for the year 2000 are included in the table below. Pension expense for Ferrybridge and Fiddler's Ferry totaled $1.5 million for the year 2000 and is included in the table below.
On December 21, 2001, the Ferrybridge and Fiddler's Ferry plants were sold to two wholly-owned subsidiaries of American Electric Power. American Electric Power hired our employees upon completion of the purchase and is required, pursuant to the asset purchase agreement, to set up a pension plan similar to ours by March 31, 2002. We anticipate that all of our former employees will transfer to the new plan, although they are under no obligation to do so. Pursuant to Statement of Financial Accounting Standards No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," we recorded a curtailment gain of $10.3 million related to the cessation of future benefits for our former employees. The curtailment gain reduced actuarial losses incurred during the year and, therefore, did not impact our pension expense.
Note 13. Employee Benefit Plans (Continued)
Information on plan assets and benefit obligations is shown below:
Components of pension expense were:
Postretirement Benefits Other Than Pensions
Most United States non-union 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. Eligibility depends on a number of factors, including the employee's hire date.
Employees at our Illinois and Homer City facilities in union-represented positions are covered by collective bargaining agreements that are due to expire in 2002. Under the agreements, a portion of these employees that retire prior to their expiration are covered under the postretirement benefit plans of their employer prior to our acquisitions in 1999. We have accounted for postretirement benefit obligations on the basis of a substantive plan under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pension." A substantive plan means that we are assuming for accounting purposes that we will provide postretirement benefits to union-represented employees following the conclusion of negotiations to replace the current benefits agreement, even though we have no legal obligation to do so. If we adopt a postretirement benefit plan for union-represented employees substantially the same as provided under the prior plans, we would record an adjustment to our prior service costs, if applicable, and amortize the impact over the estimated remaining service of covered employees. If no post retirement benefits are provided, we would treat this as a plan termination under SFAS No. 106 and record a gain during 2002. At the present time, we cannot predict the outcome of the negotiations related to these benefit plans.
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 10.5% for 2002, gradually decreasing to 5.0% for 2008 and beyond. Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 2001, by $29.1 million and annual aggregate service and interest costs by $3.1 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2001, by $22.6 million and annual aggregate service and interest costs by $2.4 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 $5.6 million in 2001, $5.3 million in 2000 and $2.9 million in 1999.
Doga employees are included in a separate government scheme, Pension Plan of Social Security Institution. The plan is administered by the officers of the Turkish Government. Contributions to the plan are based on a percentage of compensation for the covered employees and are assessed by the Ministry of Labor and Social Security. The plan is substantially funded at the end of each month.
Pension expense recorded by Doga was $97 thousand in 2001, $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 $0.7 million, $0.5 million and $0.4 million in 2001, 2000 and 1999, respectively.
Note 14. Stock Compensation Plans
Stock Options
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 which the special options discussed below were awarded. Under these programs, there are currently outstanding at December 31, 2001 to employees and former employees of Edison Mission Energy, options on 1,747,011 shares of Edison International Common Stock.
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. Options expire 10 years after the date of grant, and vest over a period of up to five years.
Edison International stock options awarded prior to 2000 include a dividend equivalent feature. Dividend equivalents on options issued after 1993 and prior to 2000 are accrued to the extent dividends are declared on Edison International Common Stock, and are subject to reduction unless certain performance criteria are met. Only a portion of the 1999 Edison International stock option awards included 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's consolidated balance sheet.
Options issued after 1997 generally have a four-year vesting period. The special options granted in 2000 vest over five years, but vesting does not begin until May 2002. Earlier options had a three-year vesting period with one-third of the total award vesting annually. If an option holder retires, dies, is terminated by the company, or is terminated while permanently and totally disabled (qualifying event) during the vesting period, the unvested options will vest on a pro rata basis.
The fair value for each option granted during 2001, 2000 and 1999, 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 application of fair-value accounting to calculate the pro forma disclosures is not an indication of future income statement effects. The recognition of dividend equivalents results in no dividends assumed for purposes of fair-value determination. The pro forma disclosures do not reflect the effect of fair-value accounting on stock-based compensation awards granted prior to 1995.
Other Equity-Based Awards
For years after 1999, a portion of the executive long-term incentives was awarded in the form of performance shares. The 2000 performance shares were restructured as retention incentives in December 2000, which pay as a combination of Edison International common stock and cash if the executive remains employed at the end of the performance period. The performance period ended December 31, 2001, for half of the award, and ends on December 31, 2002, for the remainder. Additional performance shares were awarded in January 2001 and January 2002. The 2001 performance shares vest December 31, 2003, half in shares of Edison International common stock and half in cash. The 2002 performance shares vest December 31, 2004; also half in shares of common stock and half in cash. The number of shares that will be paid out from the 2002 performance share awards will depend on the performance of Edison International common stock relative to the stock performance of a specified group of peer companies.
The 2000 and 2001 performance shares and deferred stock unit values are accrued ratably over a three-year performance period. The 2002 performance shares will be valued based on Edison International's stock performance relative to the stock performance of other such entities.
In March 2001, deferred stock units were awarded as part of a retention program. These vest and will be paid no later than March 12, 2003, but may vest as early as March 12, 2002, depending on performance. The deferred stock units are payable on the vesting date in shares of Edison International common stock.
In October 2001, a stock option retention exchange offer was extended offering holders of Edison International stock options granted in 2000 the opportunity to exchange those options for a lesser number of deferred stock units. The exchange ratio was based on the Black-Scholes value of the options and the stock price at the time the offer was extended. The exchange took place in November 2001; the options that participants elected to exchange were cancelled, and deferred stock units were issued. Approximately three options were cancelled for each deferred stock unit issued. The deferred stock units will vest 25% per year over four years, with the first vesting date in November 2002. The following assumptions were used in determining fair value through the Black-Scholes option-pricing model: expected life: 8-9 years; risk-free interest rate: 5.10%; expected volatility: 52%.
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 and $0.4 million for 1999. No compensation expense was recorded in 2001.
The weighted-average fair value of options granted during 2001, 2000 and 1999 was $3.88 per share option, $5.63 per share option and $6.45 per share option, respectively. The weighted-average remaining life of options outstanding was 6 years as of December 31, 2001, 8 years as of December 31, 2000 and 7 years as of December 31, 1999.
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 (loss) of ($1,121.8) million, $123.8 million and $131.4 million in 2001, 2000 and 1999, 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 from 1994 through 1999. 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 our 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. In August 2000, all outstanding phantom stock options were cancelled and replaced with a combination of cash and stock equivalent units relating to Edison International common stock in accordance with the Edison Mission Energy Affiliate Option Exchange Offer.
Compensation expense recorded with respect to phantom stock options was $6 million, $4.1 million (before the $60 million adjustment referred to below) and $136.3 million in 2001, 2000 and 1999, respectively.
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 15. Commitments and Contingencies
Firm Commitment for Asset Purchase
(i)The Italian Wind projects are a series of power projects that are in operation or under development in Italy. Our wholly-owned subsidiary 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
(i)CBK is a 728 MW hydroelectric power project under construction in the Philippines. At December 31, 2001, 168 megawatts have been commissioned and are operational. Our wholly-owned subsidiary owns a 50% interest. Equity is to be contributed through December 2003 commencing after full draw down of the project's debt facility, which is currently scheduled for late 2002. This equity commitment could be accelerated if our credit rating were to fall below investment grade. We were notified that the contractor responsible for engineering, procurement, and construction of the project required an adjustment in the construction payment schedule in order to meet its obligations to major suppliers and subcontractors. The project lenders and sponsors agreed on an adjustment to the loan drawdown schedule, including a one-time special draw to cover amounts owing to suppliers and subcontractors for work already completed. The agreement with the project's lenders required that 50% of the special draw amount be funded by the project sponsors. Therefore, we contributed $10 million of our equity commitment in December 2001.
(ii)The Sunrise project consists of two phases, with Phase I, a simple-cycle gas-fired facility (320 MW) that commenced commercial operation in June 2001, and Phase II, conversion to a combined-cycle gas-fired facility (560 MW) currently scheduled to be completed in July 2003. Our wholly-owned subsidiary owns a 50% interest. Equity will be contributed to fund the construction of Phase II.
The amount set forth in the above table assumes the partners will contribute equity for the entire construction costs. The project intends to obtain project financing for a portion of the capital costs, which if such financing occurs, our equity contribution obligation would be reduced. Project financing is subject to a number of uncertainties, including the matters related to the power purchase agreement with the California Department of Water Resources.
Firm commitments to contribute project equity could be accelerated due to certain events of default as defined in the non-recourse project financing facilities.
Contingent Obligations to Contribute Project Equity
(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 $136 million has been contributed as of December 31, 2001.
(ii)ISAB is a 512 MW integrated gasification combined cycle power plant near Siracusa in Sicily, Italy. Our wholly-owned subsidiary 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.
Note 15. Commitments and Contingencies (Continued)
Other Commitments and Contingencies
The California Power Crisis
During the period between summer 2000 and spring 2001, various market conditions and other factors resulted in higher wholesale power prices to California utilities. At the same time, two of the three major California utilities, Southern California Edison and Pacific Gas and Electric, were operating under a retail rate freeze. As a result, there was a significant underrecovery of costs by Southern California Edison and Pacific Gas and Electric, and each of these companies failed to make payments due to power suppliers, including us, and others. Pacific Gas and Electric filed a voluntary bankruptcy petition on April 6, 2001. Southern California Edison and the California Public Utilities Commission, in October 2001, entered into a settlement of the federal district lawsuit, which would allow Southern California Edison to recover certain procurement-related liabilities, and Southern California Edison made payments to creditors, including the four partnerships in which we have an interest, on March 1, 2002. Edison International is also the corporate parent of Southern California Edison.
Credit Support for Trading and Price Risk Management Activities
Our domestic trading and price risk management activities are conducted through our subsidiary, Edison Mission Marketing & Trading, Inc. 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 Edison Mission Marketing & Trading. The majority of Edison Mission Marketing & Trading's contracts have various standards of creditworthiness, including the maintenance of specified credit ratings. Currently we provide a parent company guaranty by Edison Mission Energy to support Edison Mission Marketing & Trading's contracts. If we do not maintain an investment grade rating or if other events adversely affect our financial position, a third party could request us to provide adequate assurance. Adequate assurance could take the form of supplying additional financial information, 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 us for any losses.
Beginning in 2000, the California power crisis adversely affected the liquidity of West Coast trading markets and, to a lesser extent, markets in other regions in the United States. Our trading and price risk management activity was reduced as a result of these market conditions and uncertainty regarding the effect of the power crisis on our affiliate, Southern California Edison. In addition, there have been a number of other factors since 2000, including the bankruptcy filing of Enron, increased concern regarding the liquidity of independent power companies, decrease in market prices in U.S. wholesale energy markets, and risk factors related to our business, that continue to limit our trading and price risk management activities. It is not certain that market conditions or risks related to our business will change to allow us to conduct trading and price risk management activities in a manner favorable to us.
Paiton
Our wholly-owned subsidiary owns a 40% interest in PT Paiton Energy, which owns a 1,230 MW coal-fired power plant in operation in East Java, Indonesia, which is referred to as the Paiton project. Our investment in the Paiton project was $492.1 million at December 31, 2001. Under the terms of a long-term power purchase agreement between Paiton Energy and PT PLN, the state-owned electric utility company, PT PLN is required to pay for capacity and fixed operating costs once each unit and the plant achieve commercial operation.
PT PLN and Paiton Energy signed a Binding Term Sheet on December 14, 2001 setting forth the commercial terms under which Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement payment" covering arrears owed by PT PLN and the settlement of other claims. In addition, the Binding Term Sheet provides for an extension of the terms of the power purchase agreement from 2029 to 2039. Paiton Energy and PT PLN are continuing negotiations on an amendment to the power purchase agreement that will include the agreed commercial terms in the Binding Term Sheet, with the aim of concluding those negotiations by June 30, 2002. The Binding Term Sheet serves as the basis under which PT PLN will pay Paiton Energy beginning January 1, 2002. The Binding Term Sheet will expire on June 30, 2002 unless extended by mutual agreement. Previously, PT PLN and Paiton Energy entered into a Phase I Agreement (covering January 1 to June 30, 2001), a Phase II Agreement (covering July 1 to September 30, 2001) and a Phase III Agreement (covering October 1 to December 31, 2001). PT PLN has made all payments to Paiton Energy as required under these agreements, which are superseded by the Binding Term Sheet. Paiton Energy is continuing to generate electricity to meet the power demand in the region and believes that PT PLN will continue to make payments for electricity under the Binding Term Sheet while negotiations on the amendment to the power purchase agreement continue. Although completion of negotiations may be delayed beyond June 30, 2002, Paiton Energy continues to believe that negotiations on the long-term restructuring of the tariff will be successful.
Under the Binding Term Sheet, past due accounts receivable due under the original power purchase agreement will be compensated through a restructure settlement payment in the amount of US$4 million per month for a period of 30 years. If the power purchase agreement amendment is not completed within reasonable time frames acceptable to Paiton Energy, the parties would be entitled to revert back to the terms and conditions of the original power purchase agreement in order to pursue arbitration in the international courts.
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. 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 addition to the 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. We believe that the outcome of this litigation will not have a material adverse effect on our consolidated financial position or results of operations. We are currently offering our interest in the Booklyn Navy Yard project for sale.
ISAB
In connection with the financing of the ISAB project, we have guaranteed for the benefit of the banks financing the construction of the ISAB project our subsidiary's obligation to contribute project equity and subordinated debt totaling up to approximately $40 million. The amount of payment under the obligation is contingent upon settlement of an arbitration proceeding brought in 1999 by the contractor of the project against ISAB Energy. No overall settlement of the dispute has yet been achieved.
Additional Gas-Fired Generation
Pursuant to the acquisition documents for the purchase of generating assets from Commonwealth Edison, our subsidiary committed to install one or more gas-fired electric generating units having an additional gross dependable capacity of 500 MW at or adjacent to an existing power plant site in Chicago. The acquisition documents require that commercial operation of this project commence by December 15, 2003. Due to additional capacity for new gas-fired generation in the Mid-America Interconnected Network (generally referred to as MAIN) region and the improved reliability of power generation in the Chicago area, we have undertaken preliminary discussions with Exelon Generation regarding alternatives to construction of 500 MW of capacity which we do not believe are needed at this time. If we were to install this additional capacity, we estimate that the cost could be as much as $320 million.
Fuel Supply Contracts
At December 31, 2001, 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: 2002-$642.3 million; 2003-$466.5 million; 2004-$449.2 million; 2005-$430.4 million; 2006-$413.8 million.
Gas Transportation Agreement
In June 2000, we entered into a long-term transportation contract with Kern River Gas Transmission Company related to the expansion of the Midway-Sunset project, a 225 MW power plant
in California in which our wholly-owned subsidiary owns a 50% interest. Under the terms of the contract we have contractual commitments to transport natural gas beginning the later of May 1, 2003 or the first day that expansion capacity is available for transportation services. We are committed to pay minimum fees under this agreement which has a term of 15 years. These minimum commitments are currently estimated to aggregate $28.2 million in the next five years summarized as follows: 2003-$5.1 million; 2004-$7.7 million; 2005-$7.7 million; and 2006-$7.7 million.
Indemnities
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, 2001, if payment were required, would be $234.4 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 Indemnities
In support of the business of our subsidiaries, we have, from time to time, entered into guarantees and indemnity agreements with respect to our subsidiaries' obligations such as debt service, fuel supply, or the delivery of power, and have also entered into reimbursement agreements with respect to letters of credit issued to third parties to support our subsidiaries' obligations. We have also, from time to time, entered into guarantees and indemnification agreements with respect to acquisitions made by our subsidiaries. In this regard, we have indemnified the previous owners of the Illinois plants and the Homer City facilities for specified liabilities, including environmental liabilities, incurred as a result of their prior ownership of the plants. We do not believe these indemnification obligations will have a material impact on us.
Tax Indemnity Agreements
In connection with the sale-leaseback transactions that we have entered into related to the Collins Station, Powerton and Joliet plants in Illinois and the Homer City facilities in Pennsylvania, we have entered into tax indemnity agreements. Under these tax indemnity agreements, we have agreed to indemnify the equity investors in the sale-leaseback transactions for specified adverse tax consequences. The potential indemnity obligations under these tax indemnity agreements could be significant. However, we believe it is not likely that an event requiring material tax indemnification will occur under any of these agreements.
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 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 that may be initiated 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. There is no assurance 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.
State-Illinois
Air Quality. In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on fossil fuel-fired electric generating stations, including the potential need for additional controls on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003 and September 30, 2004, also requires an evaluation of incentives to promote renewable energy and the establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law allows the Illinois Environmental Protection Agency to propose regulations based on its findings no sooner than ninety days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and proposes regulations in accordance with the findings, if such regulations are proposed, we cannot evaluate the potential impact of this legislation on the operations of our facilities.
Water Quality. The Illinois EPA is reviewing the water quality standards for the DesPlaines River adjacent to the Joliet Station and immediately downstream of the Will County Station to determine if the use classification should be upgraded. One of the limitations for discharges to the river that could be made more stringent if the existing secondary contact classification is changed would be the allowable temperature of the discharges from Joliet and Will County. At this time no new standards have been proposed, so we cannot estimate the financial impact of this review.
State-Pennsylvania
Water Quality. Our coal-cleaning plant National Pollutant Discharge Elimination System, commonly referred to as NPDES, permit was recently renewed by the Pennsylvania Department of Environmental Protection, or PADEP, Bureau of Water Management. It now includes water-quality-based limits for certain contaminants. We are not required to meet these limits until February 2005 but
must conduct toxics reduction evaluation studies in the meantime. These limits may require upgrade of our facilities' wastewater treatment systems with such approaches as reverse osmosis, ozonation, dechlorination and/or recycling of water. We have contested these requirements in an administrative appeal, but hope to reach an amicable resolution with PADEP.
The discharge from the treatment plant receiving the wastewater stream from the Unit 3 flue gas desulfurization system has exceeded the limits for selenium in the station's NPDES permit. The selenium limits are water-quality-based and require removal to very low levels. We are investigating technical alternatives to maximize the level of selenium removal in the discharge. We are also meeting with PADEP to discuss potential modifications to the station's NPDES permit.
We conduct ground water monitoring in a number of areas throughout the site, including active and former ash disposal sites, wastewater and runoff settling and drainage ponds and a coal refuse disposal site. On September 27, 2001, the Pennsylvania Department of Environmental Protection responded to an Assessment Report by stating that no further groundwater assessment or abatement is required for the industrial waste treatment ponds.
To date, PADEP has not requested that any additional remediation actions be performed at the site. Our facilities has a drinking water treatment system designed to meet applicable potable water standards. Recent tests indicate that our facilities' drinking water supply meets these standards.
Helvetia Discharges. Our generating units were originally constructed as a mine-mouth generating station, where coal produced from two adjacent deep mines was delivered directly to the units by coal conveyors. The two adjacent deep mines were owned by Helen Mining Company, a subsidiary of the Quaker State Corporation, and Helvetia, a subsidiary of the Rochester and Pittsburgh Coal Company. Both Helen Mining and Helvetia developed mine refuse sites, water treatment facilities and other mine related facilities on the site. The Helen Mining mine was closed in the early 1990s, and the mine surface operations and maintenance shop areas were restored before Helen Mining left the site. Helen Mining has continuing mine water and refuse site leachate treatment obligations and remains obligated to perform any cleanup required with respect to its refuse site. Helvetia's on-site mine was closed in 1995. As a result of the cessation of its on-site mining activities, Helvetia has continuing mine discharge and refuse site leachate discharge treatment obligations that it performs using water treatment facilities owned by Helvetia and located on the site. Bonds posted by Helvetia may not be sufficient to fund Helvetia's obligations in the event of Helvetia's failure to comply with its mine-related permits at the site. Current annual operating costs for Helvetia's treatment systems are estimated to be approximately $1 million. If Helvetia defaults on its treatment obligations, the government may look to us to fund these commitments.
Penn Hill No. 2 and Dixon Run No. 3 Discharges. In connection with our purchase of the Homer City facilities, we acquired the Two Lick Creek Dam and Reservoir. Acid mine drainage discharges from the Penn Hill No. 2 and Dixon Run No. 3 inactive deep mines were collected and partially treated on the reservoir property by Stanford Mining Company before being pumped off the property for additional treatment at the nearby Chestnut Ridge Treatment Plant. The mining company filed for bankruptcy, however, it operated the collection and treatment system until May 1999 when its assets were allegedly depleted.
PADEP initially advised us that we were potentially liable for treating the two discharges solely because of our ownership of the property from which the discharges emanated. Without any admission of our liability, we voluntarily entered into a letter agreement to fund the operation of the collection and treatment system for an interim period until the agency completed its investigation of potentially liable parties and alternatives for permanent treatment of the discharges were evaluated. After examining property records, PADEP concluded that we are only responsible for treating the Dixon Run No. 3 discharge. The agency completed its investigation of other potentially responsible parties, particularly mining companies that previously operated the two mines, and has notified us that they plan no further action against other parties.
A draft consent decree agreement that addresses remedial responsibilities for the two discharges has been prepared by PADEP. Under its terms, we are responsible for designing and implementing a permanent system to collect and treat the Dixon Run No. 3 discharge. We will continue our funding of the existing collection and treatment system until the Dixon Run No. 3 treatment system becomes operational. The state has provided funding to the Blacklick Creek Watershed Association to develop and operate a collection and treatment system for the Penn Hill No. 2 discharge. The Watershed Association has completed construction of the Penn Hill No. 2 system, and it will be fully operational in the next several months.
The current cost of operating the collection and treatment system is approximately $17,000 per month. We expect that the costs of operation will be reduced by 30% to 40% as a result of the completion of the Penn Hill No. 2 system. We have evaluated options for permanent treatment of the Dixon Run No. 3 discharge and concluded that conventional chemical treatment is the most appropriate option. The capital cost of the system is estimated to be $1 million. Its operational costs cannot be determined until design and permitting are complete.
Federal-United States of America
Clean Air Act. 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 $17.8 million for 2002 to install upgrades to the environmental controls at the Homer City facilities to reduce sulfur dioxide and nitrogen oxide emissions. Similarly, we anticipate upgrades to the environmental controls at the Illinois plants to reduce nitrogen oxide emissions to result in expenditures of approximately $367.9 million for the 2002-2005 period.
Mercury MACT Determination. 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.
Note 15. Commitments and Contingencies (Continued)
National Ambient Air Quality Standards. 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 Environmental Protection Agency 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. On March 26, 2002, the D.C. Circuit, on remand, held that the revised ozone and fine particulate matter ambient air quality standards were neither arbitrary nor capricious. Further action by the EPA with respect to the implementation of the revised ozone standard and the promulgation of a new coarse particulate matter standard is required pursuant to the first D.C. Circuit opinion and the Supreme Court's decision in Whitman v. American Trucking Associations, Inc. Because of the delays resulting from the litigation over the standards and the additional actions to be undertaken by the EPA, the impact of these standards on our facilities is uncertain at this time.
We believe that our facilities are in material compliance with applicable state and federal air quality requirements. Further reductions in emissions may be required for the achievement and maintenance of National Ambient Air Quality Standards for ozone and fine particulate matter.
Clean Water Act-§ 316(b) Rulemakings. The Environmental Protection Agency proposed rules establishing standards for the location, design, construction and capacity of cooling water intake structures at new facilities, including steam electric power plants. Under the terms of a consent decree entered into by the U.S. District Court for the Southern District of New York in Riverkeeper, Inc. v. Whitman, regulations for new facilities were adopted by November 9, 2001. Pursuant to the consent decree, the agency proposed similar regulations for existing facilities on February 28, 2002, and is required to finalize those regulations by August 28, 2003. Until the final standards are promulgated, we cannot determine their impact on our facilities or estimate the potential cost of compliance.
Comprehensive Environmental Response, Compensation, and Liability Act. Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by these parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused
the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several. The cost of investigation, remediation or removal of these substances may be substantial. In connection with the ownership and operation of our facilities, we may be liable for these costs.
In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or treatment facility may be liable for the costs of removal or remediation of a release or threatened release of hazardous or toxic substances at that disposal or treatment facility, whether or not that facility is owned or operated by that person. Some environmental laws and regulations create a lien on a contaminated site in favor of the government for damages and costs it incurs in connection with the contamination. The owner of a contaminated site and persons who arrange for the disposal of hazardous substances at that site also may be subject to common law claims by third parties based on damages and costs resulting from environmental contamination emanating from that site. In connection with the ownership and operation of our facilities, we may be liable for these costs.
With respect to our liabilities arising under CERCLA or similar laws for the investigation and remediation of contaminated property, we accrue a liability to the extent the costs are probable and can be reasonably estimated. Generally, we do not believe the costs for environmental remediation can be reasonably estimated before a remedial investigation has been completed for a particular site. In connection with due diligence conducted for the acquisition of our Illinois plants, we engaged a third party consultant to conduct an assessment of the potential costs for environmental remediation of the plants. This assessment, which was based on information provided to us by the former owner of these plants, was less rigorous than a remedial investigation conducted in the course of a voluntary or required site cleanup. Accordingly, we have not recorded a liability for environmental remediation at these sites. We plan to perform or update individual site assessments as we believe is appropriate. As these assessments are completed, we will determine whether remedial investigation is needed.
Enforcement Issues. We own an indirect 50% interest in EcoEléctrica, L.P., a limited partnership which owns and operates a liquefied natural gas import terminal and cogeneration project at Peñuelas, Puerto Rico. In 2000, the U.S. Environmental Protection Agency issued to EcoEléctrica a notice of violation ("NOV") and a compliance order alleging violations of the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoEléctrica have met with the Environmental Protection Agency to discuss the notice of violations and compliance order. To date, EcoEléctrica 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, or NSR, 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, including the prior owners of the Homer City
facilities, 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, several utilities have reached formal agreements with the United States (or reached agreements-in-principle) to resolve alleged NSR violations. All of the settlements have included the installation of additional pollution controls, supplemental environment projects, and the payment of civil penalties. Some of the settlements have also included the retirement or repowering of coal-fired generating units. The agreements provide for a phased approach to achieving required emission reductions over the next 10 to 15 years. The total cost of some of these settlements exceeds $1 billion; the civil penalties agreed to by these utilities range between $1 million and $10 million. Because of the uncertainty created by the Administration's review of the NSR regulations and NSR enforcement proceedings, some of the settlements referred to above have not been finalized.
In May 2001, President Bush issued a directive for a 90-day review of NSR "interpretation and implementation" by the Administrator of the Environmental Protection Agency and the Secretary of the U.S. Department of Energy. The results of the review have been postponed with release likely sometime during the first half of 2002. President Bush also directed the Attorney General to review ongoing NSR legal actions to "ensure" they are "consistent with the Clean Air Act and its regulations." The DOJ review was released in January 2002 and concluded "EPA has a reasonable basis for arguing that the enforcement actions are consistent with both the Clean Air Act and the Administrative Procedure Act".
Prior to our purchase of the Homer City facilities, 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 facilities, 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. We cannot estimate the outcome of these discussions or the potential costs of investing in additional pollution control requirements, fines or penalties at this time.
International
United Nations Framework Convention on Climate Change. Since the adoption of the United Nations Framework Convention 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.
The Kyoto Protocol has yet to be submitted to the U.S. Senate for ratification. In March 2001, the Bush administration announced that the United States would not ratify the Kyoto Protocol, but would instead offer an alternative. On February 14, 2002, President Bush announced objectives to slow the growth
of greenhouse gas emissions by reducing the amount of greenhouse gas emissions per unit of economic output by 18% by 2012 and to provide funding for climate-change related programs. The President's proposed program does not include mandatory reductions of greenhouse gas emissions. However, various bills have been, or are expected to be, introduced in Congress to require greenhouse gas emissions reductions and to address other issues related to climate change. Apart from the Kyoto Protocol, we may be impacted by future federal or state legislation relating to controlling greenhouse gas emissions.
Notwithstanding the Bush administration position, environment ministers from around the world have reached a compromise agreement on the mechanics and rules of the Kyoto Protocol. The compromise agreement is believed to clear the way for countries to begin the treaty ratification process.
We either have an equity interest in or own and operate generating plants in the following countries:
• Australia
• Spain
• Indonesia
• Thailand
• Italy
• Turkey
• New Zealand
• The United Kingdom
• Philippines
• The United States
With the exception of Turkey, all of the countries identified have ratified the UN Framework Convention on Climate Change, as well as signed the Kyoto Protocol. None of the countries have ratified the Kyoto Protocol, but, with the exception of the United States, all are expected to do so by the end of 2002. For the treaty to come into effect, approximately 55 countries that also represent at least 55% of the greenhouse gas emissions of the developed world must ratify it.
All of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or "developed" countries and are subject to national greenhouse gas emission reduction targets during the period of 2008-2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with meeting the individual national emission targets as set out within the Kyoto Protocol.
If we do become subject to limitations on emissions of carbon dioxide from our fossil fuel-fired electric generating plants, these requirements could have a significant economic impact on their operations.
Note 16. 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 $166.9 million in a guarantee to the lessor and in loans to the project. As of December 31, 2001, the loan obligation stands at $62.1 million, which is secured by the plant assets of $14.2 million owned by the project and a debt service reserve of $2.9 million.
Note 16. Lease Commitments (Continued)
Future minimum payments for operating and capital leases at December 31, 2001, are:
Operating lease expense amounted to $162.5 million, $121.9 million and $10.3 million in 2001, 2000 and 1999, respectively.
Sale-Leaseback Transactions
On December 7, 2001, our subsidiary completed a sale-leaseback of our Homer City facilities to third-party lessors for an aggregate purchase price of $1.591 billion, consisting of $782 million in cash and assumption of debt (the fair value of which was $809.3 million). Under the terms of the 33.67-year leases, our subsidiary is obligated to make semi-annual lease payments on each April 1 and October 1. If a lessor intends to sell its interest in the Homer City facilities, we have a right of first refusal to acquire the interest at fair market value. Minimum lease payments (included in the table above) are $175.0 million in 2002, $174.0 million in 2003, $142.1 million in 2004, $151.9 million in 2005, and $151.6 million in 2006. At December 31, 2001, the total remaining minimum lease payments are $3.4 billion. Lease costs will be levelized over the terms of the leases. The gain on the sale of the facilities has been deferred and is being amortized over the term of the leases.
On August 24, 2000, our subsidiary completed a sale-leaseback of our 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, which began January 2, 2001. We guarantee our 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 (included in the table above) are $97.3 million in 2002, $97.3 million in 2003, $97.3 million in 2004, $141.1 million in 2005, and $184.9 million in 2006. At December 31, 2001, the total remaining minimum lease payments are $2.3 billion. Lease costs of these power facilities will be
levelized over the terms of the respective leases. The gain 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. Minimum lease payments (included in the table above) are $21.0 million in 2002, $21.0 million in 2003, $21.0 million in 2004 and $10.6 million in 2005. 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 (3.43% at December 31, 2001). The notes are due and payable in 2005. The gain on the sale of equipment has been deferred and is being amortized over the term of the lease.
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 $50.3 million in 2002, $50.3 million in 2003, $50.4 million in 2004, $50.3 million in 2005 and $90.3 million in 2006. At December 31, 2001, the total remaining minimum lease payments were $1.5 billion.
Edison Mission Energy Master Turbine Lease
In December 2000, we entered into a master lease and related agreements which together initially provided for the construction of several new projects using in total nine turbines on order from Siemens Westinghouse. Under the terms of the master lease, an independent party is owner of the projects and is responsible for their development and construction using these turbines. In turn, as agent for the owner, we have agreed to supervise the development and construction of the new projects, which duties include arranging for funding to enable the owner to make payments for construction costs, including progress payments on the turbines. We are required to deposit treasury notes equal to 103% of the construction costs incurred by the owner from time to time as collateral security for our obligation to assist the owner to complete the projects. This can only be called upon in certain limited circumstances. We have agreed to lease from the owner each project upon its completion and to provide a guarantee of each project's residual value at the end of the lease term. Use of this structure during the development and construction phase of a project allows us to retain the flexibility to finance the project on a long-term basis through a lease structure. 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, $50.2 million in 2005 and $71.5 million in 2006. At December 31, 2001, the total remaining minimum lease payments were $452.9 million. 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.
Due to unfavorable market conditions, we decided to terminate our obligation to cause the completion of three of the four projects (for which we planned to use six of the turbines). In order to terminate the master lease for these projects, we exercised an option to acquire the assets of these projects (principally the purchase rights for the related turbines) for a purchase price of approximately $25 million. As a result of our decision to terminate these projects, we recorded a loss of $25.4 million during the year ended December 31, 2001. In connection with the termination, we obtained a release of the treasury notes held as collateral for our performance obligations with respect to these projects. Also, as part of the termination, we acquired the purchase orders for the six turbines and, thus, can continue to make progress payments and take delivery of them should market conditions improve. No progress payments are due until 2003, however, and we have the right to terminate these orders prior to the end of 2002 with no additional payment obligations.
We exercised our right to purchase the remaining three turbines under the master lease in March 2002 for $61.1 million, effectively terminating any remaining obligations under this arrangement. We plan to use these turbines for a new gas-fired project and, accordingly, we plan to capitalize the amount paid to purchase the turbines from the master lease. Our remaining purchase obligations under these turbines purchase orders are $53 million.
Note 17. 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 $71.3 million, $65.3 million and $34.6 million in 2001, 2000 and 1999, respectively. Accounts payable-affiliates associated with these administrative services totaled $12 million and $25.5 million at December 31, 2001 and 2000, respectively.
We participate in the insurance program of Edison International, including property, general liability, workers compensation and various other specialty policies. Our insurance premiums are generally based on our share of risk related to each policy. In connection with the property insurance program, a portion of the risk is reinsured by a captive insurance subsidiary of Edison International. Under these reinsurance policies, we are entitled to receive a premium refund to the extent that our loss experience is less than estimated.
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 applicable to continuing operations of $11.9 million, $226.3 million and $75.5 million for 2001, 2000 and 1999, respectively. See Note 12-Income Taxes. Amounts included in Accounts receivable-affiliates associated with these tax benefits totaled $224.4 million and $149.9 million at December 31, 2001 and 2000, 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 is to perform all operation and maintenance activities necessary for the production of power by these partnerships' facilities. The agreements continue until terminated by either party. Edison Mission Operation & Maintenance is paid for all costs incurred with operating and maintaining such facilities and may also earn an incentive compensation as set forth in the agreements. We recorded revenues under the operation and maintenance agreements of $24.1 million, $27.9 million and $28.9 million in 2001, 2000 and 1999, respectively. Accounts receivable-affiliates for Edison Mission Operation & Maintenance totaled $5.7 million and $4.9 million at December 31, 2001 and 2000, 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 $982.8 million, $715.9 million and $512.6 million in 2001, 2000 and 1999, respectively.
Note 18. Supplemental Statements of Cash Flows Information
Note 19. 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 and Middle East. 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 three 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 these power purchase agreements terminating in December 2004. Our revenues from Commonwealth Edison were $1.1 billion for each of the years ended December 31, 2001 and 2000, respectively. This represents 36% and 42% of our consolidated revenues in 2001 and 2000, respectively. Our share of equity in earnings from partnerships that have long-term power purchase agreements with Southern California Edison were $225.8 million, $153.0 million and $132.4 million for the years ended December 31, 2001, 2000 and 1999, respectively. This represents 8% in 2001, 6% in 2000 and 10% in 1999 of our consolidated revenues. Both companies' revenues are included in the Americas region shown below.
A plant located in Australia sells its energy and capacity production through a centralized power pool by entering into short and/or long-term contracts to hedge against the volatility of price fluctuations in the pool. A plant located in the United Kingdom sells its energy and capacity production by entering into physical bilateral contracts with various counterparties. Other electric power generated overseas is sold under short and/or long-term contracts to either electricity companies, electricity buying groups or electric utilities located in the country where the power is generated. Intercompany transactions have been eliminated in the following segment information.
Geographic Information
Foreign operating revenues and assets by country included in the table above are shown below.
(1)Includes assets of discontinued operations.
Note 20. Quarterly Financial Data (unaudited)
(i)Reflects our seasonal pattern, in which the majority of earnings from domestic projects are recorded in the third quarter of each year and higher electric revenues from specified international projects are recorded during the winter months of each year. (ii)Reflects asset impairment charges of $1.154 billion, after tax, required to write down the carrying amount of the Ferrybridge and Fiddler's Ferry plants to their estimated fair value less cost to sell and related currency adjustments in connection with the sale of the plants. (iii)Reflects asset impairment charges of $9.7 million required to write down our investment to the estimated net proceeds from the planned sale of the Commonwealth Atlantic, Gordonsville and Harbor projects and a loss on the termination of a portion of the Edison Mission Energy Master Turbine Lease of $25.4 million.
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 28, 2002.
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. Since January 2002, Mr. Craver has been executive vice president of Edison International. Mr. Craver has been senior vice president until January 2002, and 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. Heller has been director, president and chief executive officer of Edison Mission Energy since January 2002. Mr. Heller was senior vice president and division president of Edison Mission Energy, Europe, Central Asia, Middle East and Africa from February 2000 until January 2002. Mr. Heller was elected director of Edison Mission Energy's board of directors, 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 and chief technical officer of Edison Mission Energy since January 2002. From June 1999 to January 2002, Mr. Litzinger was senior vice president of Edison Mission Energy's Worldwide Operations. 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.
Ms. Nelson has been senior vice president of Edison Mission Energy since January 1996. Ms. Nelson has been general manager, Americas Region since January 2002 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.
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 2001:
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 2001, 2000 and 1999 for services rendered by such persons in all capacities to Edison Mission Energy and its subsidiaries.
SUMMARY COMPENSATION TABLE
(1)Effective January 1, 2002, Mr. Fohrer resigned as president and chief executive officer of Edison Mission Energy and Mr. Heller was elected president and chief executive officer of Edison Mission Energy. Mr. Heller was senior vice president and division president of Edison Mission Energy, Europe, Central Asia, Middle East and Africa from February 2000 until January 2002.
(2)Includes perquisites if in total they exceed the lesser of $50,000 or 10% of annual salary and annual incentive, plus reimbursed taxes.
(3)No Stock Appreciation Rights have been awarded. No Edison International nonqualified stock options were granted to the named executive officers in 2001. Amounts shown are comprised of Edison International nonqualified stock options for 2000 and 1999 and Edison Mission Energy phantom stock options for 1999. In August 2000, all outstanding phantom stock options were cancelled and replaced with a combination of cash and stock equivalent units relating to Edison International Common Stock pursuant to the Edison Mission Energy Affiliate Option Exchange Offer. For 1999, the amount shown for Mr. Edgell, Ms. Nelson and Mr. Vickers includes 7,480, 4,310 and 7,190 Edison Mission Energy phantom stock options, respectively.
(4)Includes the following company contributions to a defined contribution plan, Stock Savings Plus Plan and a supplemental plan for eligible participants who are affected by Stock Savings Plus Plan participation limits imposed on higher-paid individuals by federal tax law for 2001: Mr. Fohrer, $32,524; Mr. Edgell, $30,087; Mr. Heller, $31,671; Ms. Nelson $22,100 and Mr. Vickers, $11,900.
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 2001: Mr. Fohrer, $55,768; Mr. Edgell, $2,280; Mr. Heller, $31,997; Ms. Nelson $1,751 and Mr. Vickers, $2,586.
(5)Includes the following amounts for an overseas service allowance for 2001: Mr. Edgell, $95,391 and Mr. Heller, $22,343.
(6)No annual incentives were paid under the Executive Incentive Compensation Plan to executive officers for 2000 performance. The following table presents information regarding the exercise of Edison International stock options during 2001 by the executive officers named in the Summary Compensation Table above and unexercised options held as of December 31, 2001 by any of the named officers. This table also reflects proceeds realized with respect to phantom stock options cancelled in 2000 pursuant to the Edison Mission Energy Affiliate Option Exchange Offer. No Stock Appreciation Rights were exercised during 2001 or held at year-end 2001 by any of the named officers.
AGGREGATED OPTION EXERCISES IN 2001
AND YEAR-END OPTION VALUES
(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. Options generally expire 10 years after the date of grant. Edison International stock options awarded prior to 2000 include a dividend equivalent feature. Dividend equivalents on stock options issued after 1993 and prior to 2000 are accrued to the extent dividends are declared on Edison International Common Stock, and are subject to reduction unless certain performance criteria are met. Only a portion of the 1999 Edison International stock option awards included a dividend equivalent feature. Stock options awarded after 1999 do not include dividend equivalents.
Options issued after 1997 generally vest in 25% annual installments over a four-year period. Stock options issued prior to 1998 had a three-year vesting period. If an option holder retires, dies or is permanently and totally disabled (qualifying event) during the vesting period, the unvested options vest on a pro rata basis. Unvested options of Mr. Fohrer will fully vest upon a qualifying event. If a qualifying event occurs, the vested options may continue to be exercised pursuant to their original terms by the recipient or beneficiary. If an option holder is terminated other than by a qualifying event, unvested options are forfeited. Options which had vested as of the prior anniversary date of the grant are also forfeited unless exercised within 180 days of the date of termination except that if the termination is covered by the Edison International Executive Severance Plan, the terminated executive will receive one additional year of vesting credit and must exercise vested options within 12 months.
(2)In October 2001, Edison International offered to exchange deferred stock units for Edison International stock options held by active employees that were issued during the year 2000. The named executive officers elected to accept the exchange offer with respect to the following number of Edison International stock options which have been cancelled:
The deferred stock units received by the named executive officers in exchange for their Edison International stock options are listed in the table below entitled "Long-Term Incentive Plan Awards in Last Fiscal Year," and the terms and conditions of the deferred stock units are described in footnote (3) to that table.
(3)Edison International stock options have been treated as in-the-money if the fair market value of the underlying stock at December 31, 2001 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 2001 and (ii) the exercise prices of those options. The aggregate value at year-end 2001 of all accrued dividend equivalents for the named officers was:
(4)The amount shown represents the proceeds from the exercise of dividend equivalents related to 5,000 options granted in 1991, 15,000 options granted in 1993, 20,300 options granted in 1994, 45,000 options granted in 1995, 36,200 options granted in 1996, and 38,000 options granted in 1997. The options granted in 1991 expired at the end of their ten-year term. The options granted in the other years have not been exercised. These options will accrue no further dividend equivalents. (5)The amount shown represents the proceeds from the exercise of dividend equivalents related to 3,500 options granted in 1991. The options expired at the end of their ten-year term. (6)The amount shown was paid out in 2001 and included interest accrued during 2001 and the values of stock equivalents on their date of payout in August 2001. Of the total value shown in the Annual Report on Form 10-K for the year ended December 31, 2000, $8,065,599 represented amounts deferred in 2000 into a separate deferred compensation plan account. (7)The entire value shown in the Annual Report on Form 10-K for the year ended December 31, 2000, represented amounts deferred in 2000 into a separate deferred compensation plan account. (8)The amount shown was paid out in 2001 and included interest accrued during 2001. Of the total value shown in the Annual Report on Form 10-K for the year ended December 31, 2000, $4,830,682 represented amounts deferred in 2000 into a separate deferred compensation plan account. The following table presents information regarding Edison International performance shares, retention incentives and deferred stock units granted during 2001 to the executive officers named in the Summary Compensation Table above.
LONG-TERM INCENTIVE PLAN
AWARDS IN LAST FISCAL YEAR(1)
(1)Twenty-five percent of each named executive officer's annual long-term incentive compensation for 2001 was awarded in the form of Edison International performance shares. The remaining portion of the named executive officer's long-term compensation for 2001 was awarded in the form of
Edison International stock options as part of a special grant in May 2000. No Edison International stock options were granted to the named executive officers in 2001.
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. The performance shares cannot be voted or sold. 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 payment will be based on the closing value of Edison International Common Stock on December 31, 2003, if the named executive officer remains employed by Edison Mission Energy on that date. In the event of retirement, death, disability, or involuntary severance without cause pro rata payments will be made on or after December 31, 2003. No payment will be made in the event of a voluntary separation or a separation for cause. Performance share payments will also be made in cash in the event of a change in control of Edison International. The performance shares are not transferable, but a beneficiary may be designated in the event of death. Edison International will substitute cash awards to the extent necessary to pay required tax withholding.
(2)Retention Incentives were also awarded to the named executive officers during 2001. The retention incentives are stock units with each unit worth one share of Edison International Common Stock. No dividend equivalents were included with these grants. The Retention Incentives cannot be voted or sold. They are payable on the earlier of (i) March 12, 2003, or (ii) the date the average closing price for a share of Edison International Common Stock for at least 20 consecutive trading days has equaled or exceeded $20, but no earlier than March 12, 2002.
The Retention Incentives will be paid to the named executive officers in Edison International Common Stock under the Equity Compensation Plan. Payments will be made upon retirement, 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. Retention Incentive payments will also be made in cash in the event of a change in control of Edison International. The Retention Incentives are not transferable, but a beneficiary may be designated in the event of death. Edison International will substitute cash awards to the extent necessary to pay required tax withholding.
(3)As stated in footnote (2) to the table above entitled "Aggregated Option Exercises in 2001 and Year-End Option Values," Deferred Stock Units were awarded to the named executive officers during 2001 to the extent they accepted the terms of an exchange offer made to all active employees holding Edison International stock options issued during 2000. The terms of the exchange offer provided that one Deferred Stock Unit would be awarded in exchange for from 2.6 to 3.4 stock options, depending on the Black-Scholes value of the surrendered options. Each Deferred Stock Unit is worth one share of Edison International Common Stock. No dividend equivalents were included with these grants. The Deferred Stock Units cannot be voted or sold. The Deferred Stock Units vest in 25% annual installments and will be paid on each of the following dates, November 29 of 2002, 2003, 2004 and 2005, if the individual remains employed by Edison Mission Energy on that date.
The Deferred Stock Units will be paid in Edison International Common Stock under the Equity Compensation Plan. Pro rata payments will be made on the scheduled payment date in the event of a participant's retirement, death, disability, or involuntary severance without cause during the related vesting period. No payment will be made in the event of a participant's voluntary separation or a separation for cause. Payments will also be made in cash in the event of a change in control of Edison International. The Deferred Stock Units are not transferable, but a beneficiary may be designated in the event of death. Edison International will substitute cash awards to the extent necessary to pay required tax withholding.
Retirement Benefits
The following table sets forth estimated gross annual benefits payable upon retirement at age 65 to the executive officers named in the Summary Compensation Table above in the remuneration and years of service classifications indicated.
PENSION PLAN TABLE(1)
(1)Estimates are based on the 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 incentive 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, 2001, the years of service completed for: Mr. Fohrer, 28; Mr. Edgell, 31; Mr. Heller, 6; Ms. Nelson, 31 and Mr. Vickers, 3. 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 salary and annual incentive prior to attaining age 65. Compensation used to calculate combined benefits under the plans is based on base salary and annual incentive (excluding special recognition awards) as reported in the Summary Compensation Table, except the Compensation and Executive Personnel Committee elected to adjust the amounts reported in that table to include foregone 2000 target annual incentives and foregone 2001 salary merit increases for purposes of the pension benefit determination under the executive retirement plan. The adjustment amounts for 2000 for this purpose are $339,500, $276,250, $237,250, $226,850 and $197,450 for Mr. Fohrer, Mr. Edgell, Mr. Heller, Ms. Nelson, and Mr. Vickers, respectively.
The service percentage is based on 13/4% per year for the first 30 years of service (521/2% upon completion of 30 years of 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 participant following his or her death. The benefit is approximately 22.5% of final compensation (salary at retirement and the average of the three highest annual incentives paid in the five years prior to retirement) payable for ten years certain. If a named executive officer's final annual compensation was $950,000 (the highest compensation level in the Pension Plan Table above), the beneficiary's estimated annual survivor benefit would be approximately $213,275. 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 named executive officer following his or her death. The benefit is 25% of final compensation (salary at retirement and the average of the three highest annual incentives paid in the five years prior to retirement) payable for ten years certain. At retirement, a named 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 annual incentives paid in the five years prior to retirement) payable to the participant for ten years certain immediately following retirement. If a named executive officer's final annual compensation was $950,000 (the highest compensation level in the Pension Plan Table above), the beneficiary's estimated annual survivor benefit would be approximately $237,500. If a named executive officer were to elect the retirement income benefit in lieu of survivor income and had final annual compensation of approximately $950,000 (the highest compensation level in the Pension Plan Table above), the named executive officer's estimated annual benefit would be approximately $95,000. Messrs. Fohrer and Edgell have elected coverage under this plan.
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.
Changes in Control
On June 8, 2001, Edison International created Mission Energy Holding Company as a wholly-owned indirect subsidiary. Mission Energy Holding's principal asset is our common stock. In July 2001, Mission Energy Holding issued $800 million of 13.50% senior secured notes due 2008. Concurrently with the consummation of the offering of its senior secured notes, Mission Energy Holding borrowed $385 million under a term loan. The senior secured notes and the term loan are secured by a first priority security interest in our common stock. Any foreclosure on the pledge of our common stock by the holders of the senior secured notes or the lenders under the term loan could result in a change of control of us. A change in control of us or our subsidiaries could require us to prepay indebtedness in our or their debt agreements.
Management
The following table shows the number of equity securities of Edison International beneficially owned as of December 31, 2001, except as otherwise noted, 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, 2001. The table includes shares that can be acquired through March 1, 2002, through the exercise of stock options and the payment of Retention Incentive deferred stock units. Unless otherwise indicated, each individual has sole voting and investment power.
(a)No named person or group owns more than 1% of the outstanding shares of the class.
(b)Includes 61,890 Retention Incentive deferred stock units, 17,255 shares credited under the Stock Savings Plus Plan and 830,051 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, 45,120 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 23,088 Retention Incentive deferred stock units and 107,051 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 23,010 Retention Incentive deferred stock units, 3,837 shares credited under the Stock Savings Plus Plan and 280,626 shares that can be acquired through the exercise of options. Includes 8,427 shares held with spouse as joint tenants with shared voting and investment power.
(e)Includes 26,541 Retention Incentive deferred stock units, 28,375 shares credited under the Stock Savings Plus Plan and 261,526 shares that can be acquired through the exercise of options.
(f)Includes 16,287 Retention Incentive deferred stock units, 43,946 shares credited under the Stock Savings Plus Plan and 49,476 shares that can be acquired through the exercise of options.
(g)Includes 15,457 Retention Incentive deferred stock units, 1,043 shares credited under the Stock Savings Plus Plan and 172,750 shares that can be acquired through the exercise of options.
(h)Includes 13,030 Retention Incentive deferred stock units, 5,742 shares credited under the Stock Savings Plus Plan and 19,042 shares that can be acquired through the exercise of options.
(i)Includes 14,333 Retention Incentive deferred stock units, 1,537 shares credited under the Stock Savings Plus Plan and 11,626 shares that can be acquired through the exercise of options.
(j)Includes 213,572 Retention Incentive deferred stock units, 107,533 shares credited under the Stock Savings Plus Plan and 1,742,649 shares that can be acquired through the exercise of options. The Retention Incentive deferred stock units are described in footnote (2) to the table above entitled "Long-Term Incentive Plan Awards in Last Fiscal Year." 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, 51,120 shares held as co-trustee and co-beneficiary of trust with shared voting and investment power, 200 shares held by spouse with shared voting and investment power and 8,427 shares held with spouse as joint tenants with shared voting and investment power. 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. Fohrer resigned as president and chief executive officer of Edison Mission Energy, effective January 1, 2002. ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In July 1999, Edison Mission Energy made an interest-free loan to Georgia R. Nelson, who at that time was Senior Vice President and President of Midwest Generation EME, LLC, in the amount of $179,800 in exchange for a note executed by Ms. Nelson and payable to us 365 days following the conclusion of her assignment in Chicago, Illinois.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) List of Financial Statements
See Index to Consolidated Financial Statements at Item 8 of this report.
(2)List of Financial Statement Schedules
The following 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, 2001, 2000 and 1999.
•Four Star Financial Statements as of December 31, 2001, 2000 and 1999.
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
The registrant filed the following reports on Form 8-K during the quarter ended December 31, 2001.
(c)Exhibits
Exhibit No.
Description
2.1
Agreement for the sale and purchase of shares in First Hydro Limited, dated December 21, 1995, between PSB Holding Limited and First Hydro Finance Plc, incorporated by reference to Exhibit 2.1 to Edison Mission Energy's Form 8-K dated December 21, 1995.
2.2
Transaction Implementation Agreement, dated March 29, 1997, between The State Electricity Commission of Victoria, Edison Mission Energy Australia Limited, Loy Yang B Power Station Pty Ltd, Loy Yang Power Limited, The Honorable Alan Robert Stockdale, Leanne Power Pty Ltd and Edison Mission Energy, incorporated by reference to Exhibit 2.2 to Edison Mission Energy's Form 8-K dated May 22, 1997.
2.3
Stock Purchase and Assignment Agreement, dated December 23, 1998, between KES Puerto Rico, L.P., KENETECH Energy Systems, Inc., KES Bermuda, Inc. and Edison Mission Energy del Caribe for the (i) sale and purchase of KES Puerto Rico, L.P.'s shares in EcoEléctrica Holdings Ltd.; (ii) assignment of KENETECH Energy Systems' rights and interests in that certain Project Note from the Partnership; and (iii) assignment of KES Bermuda, Inc.'s rights and interests in that certain Administrative Services Agreement dated October 31 1997, incorporated by reference to Exhibit 2.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.4
Asset Purchase Agreement, dated August 1, 1998, between Pennsylvania Electric Company, NGE Generation, Inc., New York State Electric & Gas Corporation and Mission Energy Westside, Inc., incorporated by reference to Exhibit 2.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.5
Asset Sale Agreement, dated March 22, 1999, between Commonwealth Edison Company and Edison Mission Energy as to the Fossil Generating Assets, incorporated by reference to Exhibit 2.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
2.6
Agreement for the Sale and Purchase of Shares in Contact Energy Limited, dated March 10, 1999, between Her Majesty the Queen in Right of New Zealand, Edison Mission Energy Taupo Limited and Edison Mission Energy, incorporated by reference to Exhibit 2.6 to the Edison Mission Energy's Form 10-Q for the quarter ended March 31, 1999.
2.7
Sale, Purchase and Leasing Agreement between PowerGen UK plc and Edison First Power Limited for the purchase of the Ferrybridge C Power Station, incorporated by reference to Exhibit 2.7 to Edison Mission Energy's Form 8-K/A dated July 19, 1999.
2.8
Sale, Purchase and Leasing Agreement between PowerGen UK plc and Edison First Power Limited for the purchase of the Fiddler's Ferry Power Station, incorporated by reference to Exhibit 2.8 to Edison Mission Energy's Form 8-K/A dated July 19, 1999.
2.9
Purchase and Sale Agreement, dated May 10, 2000, between Edison Mission Energy, P & L Coal Holdings Corporation and Gold Fields Mining Corporation, incorporated by reference to Exhibit 2.9 to Edison Mission Energy's 10-Q for the quarter ended September 30, 2000.
2.10
Asset Purchase Agreement dated 3 March 2000 between MEC International B.V. and UPC International Partnership CV II, incorporated by reference to Exhibit 10.80 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
2.11
Stock Purchase Agreement, dated November 17, 2000 between Mission Del Sol, LLC and Texaco Inc., incorporated by reference to Exhibit 2.11 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
2.12
Agreement relating to the sale and purchase of the business carried on at Fiddler's Ferry Power Station, Warrington, Cheshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.12 to Edison Mission Energy's Form 8-K dated December 21, 2001.
2.13
Agreement relating to the sale and purchase of the business carried on at Ferrybridge "C" Power Station, Knottingley, West Yorkshire, dated October 6, 2001, among Edison First Power Limited, AEP Energy Services UK Generation Limited, AEPR Global Holland Holding BV, and American Electric Power Company, Inc., incorporated by reference to Exhibit 2.13 to Edison Mission Energy's Form 8-K dated December 21, 2001.
3.1
First Amended and Restated Articles of Incorporation of Edison Mission Energy. Originally filed with Edison Mission Energy's Registration Statement on Form 10 to the Securities and Exchange Commission on September 30, 1994 and amended by Amendment No. 1 thereto dated November 19, 1994 and Amendment No. 2 thereto dated November 21, 1994 (as so amended, the "Form 10"), incorporated by reference to Exhibit 3.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
3.1.1
Certificate of Amendment of Articles of Incorporation of Edison Mission Energy dated October 18, 1988, originally filed with Edison Mission Energy's Form 10, incorporated by reference to Exhibit 3.1.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
3.1.2
Certificate of Amendment of Articles of Incorporation of Edison Mission Energy dated January 17, 2001, incorporated by reference to Exhibit 3.1.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
3.1.3
Certificate of Amendment of Articles of Incorporation of Edison Mission Energy dated July 2, 2001, incorporated by reference to Exhibit 3.1.3 to Edison Mission Energy's 10-Q for the quarter ended June 30, 2001.
3.2
By-Laws of Edison Mission Energy as amended to and including January 1, 2000, incorporated by reference to Exhibit 3.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
3.2.1
Amendment to By-Laws of Edison Mission Energy dated January 15, 2001, incorporated by reference to Exhibit 3.2.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.1
Indenture, dated as of August 10, 2001, among Edison Mission Energy and The Bank of New York as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.1.1
Form of 10% Senior Note due 2008 (included in Exhibit 4.1) to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001).
4.2
Registration Rights Agreement, dated as of August 7, 2001, among Edison Mission Energy, Credit Suisse First Boston Corporation, BMO Nesbitt Burns Corp., Salomon Smith Barney Inc., SG Cowen Securities Corporation, TD Securities (USA) Inc. and Westdeutsche Landesbank Girozentrale (Düsseldorf), incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.3
Indenture, dated as of April 5, 2001, among Edison Mission Energy and United States Trust Company of New York as Trustee, incorporated by reference to Exhibit 4.20 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.3.1
Form of 9.875% Senior Note due 2011 (included in Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001).
4.4
Registration Rights Agreement, dated as of April 2, 2001, among Edison Mission Energy and Credit Suisse First Boston Corporation and Westdeutsche Landesbank Girozentrale (Düsseldorf) as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 24, 2001.
4.5
Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Powerton Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.9 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.5.1
Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.5 hereto, incorporated by reference to Exhibit 4.9.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6
Guarantee, dated as of August 17, 2000, made by Edison Mission Energy, as Guarantor in favor of Joliet Trust I, as Owner Lessor, incorporated by reference to Exhibit 4.10 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.6.1
Schedule identifying substantially identical agreement to Guarantee constituting Exhibit 4.6 hereto, incorporated by reference to Exhibit 4.10.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.7
Registration Rights Agreement, dated as of August 17, 2000, among Edison Mission Energy, Midwest Generation, LLC and Credit Suisse First Boston Corporation and Lehman Brothers Inc., as representatives of the Initial Purchasers, incorporated by reference to Exhibit 4.11 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.8
Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Powerton Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Powerton Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee, and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.8.1
Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.8 hereto, incorporated by reference to Exhibit 4.12.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9
Participation Agreement (T1), dated as of August 17, 2000, by and among, Midwest Generation, LLC, Joliet Trust I, as the Owner Lessor, Wilmington Trust Company, as the Owner Trustee, Joliet Generation I, LLC, as the Owner Participant, Edison Mission Energy, United States Trust Company of New York, as the Lease Indenture Trustee and United States Trust Company of New York, as the Pass Through Trustees, incorporated by reference to Exhibit 4.13 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.9.1
Schedule identifying substantially identical agreement to Participation Agreement constituting Exhibit 4.9 hereto, incorporated by reference to Exhibit 4.13.1 to Edison Mission Energy's and Midwest Generation LLC's Registration Statement on Form S-4 to the Securities and Exchange Commission on April 20, 2001.
4.10
Copy of the Global Debenture representing Edison Mission Energy's 97/8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2024, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
4.11
Conformed copy of the Indenture, dated as of November 30, 1994, between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
4.11.1
First Supplemental Indenture, dated as of November 30, 1994, to Indenture dated as of November 30, 1994 between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.2.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
4.11.2
Second Supplemental Indenture, dated as of August 8, 1995, to Indenture dated as of November 30, 1994 between Edison Mission Energy and The First National Bank of Chicago, as Trustee, incorporated by reference to Exhibit 4.11.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on August 29, 2001.
4.12
Indenture, dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
4.12.1
First Supplemental Indenture, dated as of June 28, 1999, to Indenture dated as of June 28, 1999, between Edison Mission Energy and The Bank of New York, as Trustee, incorporated by reference to Exhibit 4.2 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
4.13
Copy of the Security representing Edison Mission Energy's 81/8% Senior Notes Due 2002, incorporated by reference to Exhibit 4.4 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.14
Promissory Note ($499,450,800), dated as of August 24, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.5 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.14.1
Schedule identifying substantially identical agreements to Promissory Note constituting Exhibit 4.4 hereto, incorporated by reference to Exhibit 4.5.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
4.15
Promissory Note, dated as of June 23, 2000, by Edison Mission Energy in favor of Midwest Generation, LLC, incorporated by reference to Exhibit 4.6 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.1
Registration Rights Agreement, dated as of June 23, 1999, between Edison Mission Energy and the Initial Purchasers specified therein, incorporated by reference to Exhibit 10.1 to Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on February 18, 2000.
10.8
Power Purchase Contract between Southern California Edison Company and Arco Petroleum Products Company (Watson Refinery), incorporated by reference to Exhibit 10.8 to Edison Mission Energy's Form 10.
10.9
Power Supply Agreement between State Electricity Commission of Victoria, Loy Yang B Power Station Pty. Ltd. and the Company Australia Pty. Ltd., as managing partner of the Latrobe Power Partnership, dated December 31, 1992, incorporated by reference to Exhibit 10.9 to Edison Mission Energy's Form 10.
10.10
Power Purchase Agreement between P.T. Paiton Energy Company as Seller and Perusahaan Umum Listrik Negara as Buyer, dated February 12, 1994, incorporated by reference to Exhibit 10.10 to Edison Mission Energy's Form 10.
10.11
Amended and Restated Power Purchase Contract between Southern California Energy Company and Midway-Sunset Cogeneration Company, dated May 5, 1988, incorporated by reference to Exhibit 10.11 to Edison Mission Energy's Form 10.
10.12
Parallel Generation Agreement between Kern River Cogeneration Company and Southern California Energy Company, dated January 6, 1984, incorporated by reference to Exhibit 10.12 to Edison Mission Energy's Form 10.
10.13
Parallel Generation Agreement between Kern River Cogeneration (Sycamore Project) Company and Southern California Energy Company, dated December 18, 1984, incorporated by reference to Exhibit 10.13 to Edison Mission Energy's Form 10.
10.15
Conformed copy of the Second Amended and Restated U.S. $500 million Bank of America National Trust and Savings Association Credit Agreement, dated as of October 11, 1996, incorporated by reference to Exhibit 10.15.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1996.
10.15.1
Amendment One to Second Amended and Restated U.S. $500 million Bank of America National Trust and Savings Association Credit Agreement, dated as of August 17, 2000, incorporated by reference to Exhibit 10.15.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.15.2
Amendment Two to Second Amended and Restated U.S. $425 million Bank of America, N.A. Credit Agreement, dated as of May 30, 2001, incorporated by reference to Exhibit 10.15.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.16
Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to Edison Mission Energy's Form 10.
10.16.1
Amendment No. 1 to Amended and Restated Ground Lease Agreement between Texaco Refining and Marketing Inc. and March Point Cogeneration Company, dated August 21, 1992, incorporated by reference to Exhibit 10.16 to Edison Mission Energy's Form 10.
10.17
Memorandum of Agreement between Atlantic Richfield Company and Products Cogeneration Company, dated September 17, 1987, incorporated by reference to Exhibit 10.17 to Edison Mission Energy's Form 10.
10.18
Memorandum of Ground Lease between Texaco Producing Inc. and Sycamore Cogeneration Company, dated January 19, 1987, incorporated by reference to Exhibit 10.18 to Edison Mission Energy's Form 10.
10.19
Amended and Restated Memorandum of Ground Lease between Getty Oil Company and Kern River Cogeneration Company, dated November 14, 1984, incorporated by reference to Exhibit 10.19 to Edison Mission Energy's Form 10.
10.20
Memorandum of Lease between Sun Operating Limited Partnership and Midway-Sunset Cogeneration Company, incorporated by reference to Exhibit 10.20 to Edison Mission Energy's Form 10.
10.21
Executive Supplemental Benefit Program, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.22
1981 Deferred Compensation Agreement, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.23
1985 Deferred Compensation Agreement for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.24
1987 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.25
1988 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.26
1989 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).
10.27
1990 Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).
10.28
Annual Deferred Compensation Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-9936).
10.29
Executive Retirement Plan for Executives, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No. 1-2313).
10.31
Estate and Financial Planning Program for Executive Officers, incorporated by reference to Exhibits to Forms 10-K filed by SCEcorp (File No 1-9936).
10.32
Letter Agreement with Edward R. Muller, incorporated by reference to Exhibit 10.32 to Edison Mission Energy's Form 10.
10.34
Conformed copy of the Guarantee Agreement dated as of November 30, 1994, incorporated by reference to Exhibit 10.34 to Edison Mission Energy's Form 10.
10.35
Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated as of December 18, 1989, incorporated by reference to Exhibit 10.35 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
10.35.1
First Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated November 1, 1991, incorporated by reference to Exhibit 10.35.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
10.35.2
Second Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated June 3, 1994, incorporated by reference to Exhibit 10.35.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
10.35.3
Third Amendment to Indenture of Lease between Brooklyn Navy Yard Development Corporation and Cogeneration Technologies, Inc., dated December 12, 1994, incorporated by reference to Exhibit 10.35.3 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
10.37
Amended and Restated Limited Partnership Agreement of Mission Capital, L.P., dated as of November 30, 1994, incorporated by reference to Exhibit 10.37 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
10.38
Action of General Partner of Mission Capital, L.P. creating the 97/8% Cumulative Monthly Income Preferred Securities, Series A, dated as of November 30, 1994, incorporated by reference to Exhibit 10.38 to Edison Mission Energy's Form 10-K for the year ended December 31, 1994.
10.39
Action of General Partner of Mission Capital, L.P., creating the 81/2% Cumulative Monthly Income Preferred Securities, Series B, dated as of August 8, 1995, incorporated by reference to Exhibit 10.39 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 1995.
10.40
Power Purchase Contract between ISAB Energy, S.r.l. as Seller and Enel, S.p.A. as Buyer, dated June 9, 1995, incorporated by reference to Exhibit 10.40 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 1995.
10.41
400 million sterling pounds Barclays Bank Plc Credit Agreement, dated December 18, 1995, incorporated by reference to Exhibit 10.41 to Edison Mission Energy's Form 8-K, dated December 21, 1995.
10.44
Guarantee by Edison Mission Energy, dated December 20, 1996, in favor of The Fuji Bank, Limited, Los Angeles Agency, to secure Camino Energy Company's payments pursuant to Camino Energy Company's Credit Agreement and Defeasance Agreement, incorporated by reference to Exhibit 10.44 to Edison Mission Energy's Form 10-K for the year ended December 31, 1996.
10.45
Power Purchase Agreement between National Power Corporation and San Pascual Cogeneration Company International B.V., dated September 10, 1997, incorporated by reference to Exhibit 10.45 to Edison Mission Energy's Form 10-K for the year ended December 31, 1997.
10.46
Power Purchase Agreement between Gulf Power Generation Co., LTD., and Electricity Generating Authority of Thailand, dated December 22, 1997, incorporated by reference to Exhibit 10.46 to Edison Mission Energy's Form 10-K for the year ended December 31, 1997.
10.49
Equity Support Guarantee by Edison Mission Energy, dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan Bank to guarantee certain equity funding obligations of EcoEléctrica Ltd. and EcoEléctrica Holdings Ltd. pursuant to EcoEléctrica Ltd.'s Credit Agreement dated as of October 31, 1997, incorporated by reference to Exhibit 10.49 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.50
Master Guarantee and Support Instrument by Edison Mission Energy, dated December 23, 1998, in favor of ABN AMRO Bank N.V., and the Chase Manhattan Bank to guarantee the availability of funds to purchase fuel for the EcoEléctrica project pursuant to EcoEléctrica Ltd.'s Credit Agreement dated as of October 31, 1997 and Intercreditor Agreement dated as of October 31, 1997, incorporated by reference to Exhibit 10.50 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.51
Guarantee Assumption Agreement from Edison Mission Energy, dated December 23, 1998, under which Edison Mission Energy assumed all of the obligations of KENETECH Energy Systems, Inc. to Union Carbide Caribe Inc., under the certain Guaranty dated November 25, 1997, incorporated by reference to Exhibit 10.51 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.52
Transition Power Purchase Agreement, dated August 1, 1998, between New York State Electric & Gas Corporation and Mission Energy Westside, Inc, incorporated by reference to Exhibit 10.52 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.54
Guarantee, dated August 1, 1998, between Edison Mission Energy, Pennsylvania Electric Company, NGE Generation, Inc. and New York State Electric & Gas Corporation, incorporated by reference to Exhibit 10.54 to Edison Mission Energy's Form 10-K for the year ended December 31, 1998.
10.55
Credit Agreement, dated March 18, 1999, among Edison Mission Holdings Co. and Certain Commercial Lending Institutions, and Citicorp USA, Inc., incorporated by reference to Exhibit 10.55 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.56
Guarantee and Collateral Agreement made by Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME City Generation L.P. and Edison Mission Energy in favor of United States Trust Company of New York, dated as of March 18, 1999, incorporated by reference to Exhibit 10.56 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.56.1
Amendment No. 1 to the Guarantee and Collateral Agreement, dated May 27, 1999, between Edison Mission Holdings, Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Company, Mission Energy Westside, Inc., EME Homer City Generation L.P. and Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.56.1 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.56.2
Open-End Mortgage, Security Agreement and Assignment of Leases and Rents, dated March 18, 1999 from EME Homer City Generation L.P. to United States Trust Company of New York, incorporated by reference to Exhibit 10.56.2 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.56.3
Amendment No. 1 to the Open-End Mortgage, Security Agreement and Assignment of Leases and Rents, dated May 27, 1999, from EME Homer City Generation L.P. to United States Trust Company of New York, incorporated by reference to Exhibit 10.56.3 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.57
Collateral Agency and Intercreditor Agreement among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P., The Secured Parties' Representatives, Citicorp USA, Inc. as Administrative Agent and United States Trust Company of New York as Collateral Agent, dated as of March 18, 1999, incorporated by reference to Exhibit 10.57 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.58
Security Deposit Agreement among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, as Collateral Agent, dated as of March 18, 1999, incorporated by reference to Exhibit 10.58 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.58.1
Amendment No. 1 to the Security Deposit Agreement, dated May 27, 1999, between Edison Mission Holdings, Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Company, Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, as Collateral Agent, incorporated by reference to Exhibit 10.58.1 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.59
Credit Support Guarantee, dated as of March 18, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.59 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.59.1
Amendment No. 1 to the Credit Support Guarantee, dated May 27, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.59.1 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.60
Debt Service Reserve Guarantee, dated as of March 18, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York on behalf of the various financial institutions (Lenders) as are or may become parities to the Credit Agreement, dated as of March 18, 1999, among Edison Mission Holdings Co., the Lenders and Citicorp USA, Inc., incorporated by reference to Exhibit 10.60 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.60.1
Amendment No. 1 to the Debt Service Reserve Guarantee, dated May 27, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.60.1 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.60.2
Amendment No. 2 to the Debt Service Reserve Guarantee, dated as of March 18, 2001, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.60.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.60.3
Bond Debt Service Reserve Guarantee, dated May 27, 1999, made by Edison Mission Energy in favor of United States Trust Company of New York, incorporated by reference to Exhibit 10.60.2 to Amendment No. 1 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 8, 2000.
10.60.4
Intercompany Loan Subordination Agreement, dated March 18, 1999, among Edison Mission Holdings Co., Edison Mission Finance Co., Homer City Property Holdings, Inc., Chestnut Ridge Energy Co., Mission Energy Westside, Inc., EME Homer City Generation L.P. and United States Trust Company of New York, incorporated by reference to Exhibit 10.60.3 to Amendment No. 2 of Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on February 29, 2000.
10.61
Credit Agreement, dated March 18, 1999, among Edison Mission Energy and Certain Commercial Lending Institutions, and Citicorp USA, Inc., incorporated by reference to Exhibit 10.61 to Edison Mission Energy's Form 8-K dated March 18, 1999.
10.61.1
Amendment One to Credit Agreement, dated as of August 17, 2000, by and among Edison Mission Energy, Certain Commercial Lending Institutions, and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.61.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.61.2
Amendment Two to Credit Agreement, dated as of March 15, 2001, by and among Edison Mission Energy, certain commercial lending institutions, and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.61.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.61.3
Amendment Three to the U.S. $595 million Credit Agreement, dated as of May 30, 2001, by and among Edison Mission Energy, certain commercial lending institutions, and Citicorp USA, Inc., as Administrative Agent, incorporated by reference to Exhibit 10.61.3 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.62
Edison Power Limited £1,150,000,000 Guaranteed Secured Variable Rate Bonds due 2019 Guaranteed by Maplekey UK Limited, incorporated by reference to Exhibit 10.62 to Edison Mission Energy's Form 8-K dated July 19, 1999.
10.64
Coal and Capex Facility Agreement, dated July 16, 1999 between EME Finance UK Limited, Barclay's Capital and Credit Suisse First Boston, The Financial Institutions named as Banks, and Barclays Bank PLC as Facility Agent, incorporated by reference to Exhibit 10.64 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 1999.
10.64.1
Amendment One to Coal and Capex Facility Agreement, dated as of May 29, 2001, by and among Edison Mission Energy Finance UK Limited and Barclays Bank PLC, as Facility Agent, incorporated by reference to Exhibit 10.64.1 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.65
Guarantee by Edison Mission Energy dated July 16, 1999 supporting the Coal and Capex Facility Agreement (Facility Agreement) issued by Barclays Bank PLC to secure EME Finance UK Limited obligations pursuant to the Facility Agreement, incorporated by reference to Exhibit 10.65 to Edison Mission Energy's Form 10-Q for the quarter ended September 30, 1999.
10.65.1
Amendment One to Guarantee by Edison Mission Energy supporting the Facility Agreement, dated as of August 17, 2000, incorporated by reference to Exhibit 10.65.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.65.2
Amendment Two to Guarantee by Edison Mission Energy Supporting the Facility Agreement, dated as of May 29, 2001, incorporated by reference to Exhibit 10.65.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.66
Debt Service Reserve Guarantee, dated as of July 16, 1999, made by Edison Mission Energy in favor of Bank of America National Trust and Savings Association, incorporated by reference to Exhibit 10.66 to Edison Mission Energy's Form 10-K for the year ended December 31, 1999.
10.71
Indenture, dated as of May 27, 1999, between Edison Mission Holdings Co. and United States Trust Company of New York, as Trustee, incorporated by reference to Exhibit 4.1 to Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999.
10.75
Exchange and Registration Rights Agreement, dated as of May 27, 1999, by and among the Initial Purchasers named therein, the Guarantors named therein and Edison Mission Holdings Co., incorporated by reference to Exhibit 10.1 to Edison Mission Holdings Co.'s Registration Statement on Form S-4 to the Securities and Exchange Commission on December 3, 1999.
10.76
Agreement among Edward R. Muller, Edison International and Edison Mission Energy concerning the terms of Mr. Muller's employment separation, incorporated by reference to Exhibit 10.76 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
10.77
Agreement By and Between S. Linn Williams and Edison Mission Energy dated February 5, 2000, incorporated by reference to Exhibit 10.77 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
10.78
Form of Agreement for 2000 Employee Awards under the Equity Compensation Plan, incorporated by reference to Exhibit 10.78 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
10.79
Resolution regarding the computation of disability and survivor benefits prior to age 55 for Alan J. Fohrer, incorporated by reference to Exhibit 10.79 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
10.81
Edison International 2000 Equity Plan, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended June 30, 2000. (File No. 1-9936).
10.82
Form of Agreement for 2000 Employee Awards under the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended June 30, 2000. (File No. 1-9936).
10.83
Amendment No. 1 to the Edison International Equity Compensation Plan (as restated January 1, 1998), incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended June 30, 2000. (File No. 1-9936).
10.84
Credit Agreement, dated May 30, 2000, among Edison Mission Energy, Certain Commercial Lending Institutions and Bank of America, N.A., incorporated by reference to Exhibit 10.84 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2000.
10.84.1
Amendment One to Credit Agreement, dated as of August 17, 2000, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Bank of America, N.A. as Administrative Agent, incorporated by reference to Exhibit 10.84.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.84.2
Amendment Two to the U.S. $255 million Credit Agreement, dated as of May 30, 2001, by and among Edison Mission Energy, Certain Commercial Lending Institutions and Bank of America, N.A. as Administrative Agent, incorporated by reference to Exhibit 10.84.2 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.85
Guarantee, dated as of June 23, 2000, in favor of EME/CDL Trust and Midwest Generation, LLC made by Edison Mission Energy, incorporated by reference to Exhibit 10.85 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.86
Power Purchase Agreement (Crawford, Fisk, Waukegan, Will County, Joliet and Powerton Generating Stations), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.86 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.87
Power Purchase Agreement (Collins Generating Station), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.87.1
Amendment No. 1 to the Power Purchase Agreement, dated July 12, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.87.2
Amended and Restated Power Purchase Agreement (Collins Generating Station), dated as of September 13, 2000, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.87.2 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.88
Power Purchase Agreement (Crawford, Fisk, Waukegan, Calumet, Joliet, Bloom, Electric Junction, Sabrooke and Lombard Peaking Units), dated as of December 15, 1999, between Commonwealth Edison Company and Midwest Generation, LLC, incorporated by reference to Exhibit 10.88 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.89
Participation Agreement, dated as of June 23, 2000, among Midwest Generation, LLC, Edison Mission Energy, EME/CDL Trust, the Investor party to the Trust Agreement, Wilmington Trust Company, the Persons listed as Noteholders on Schedule I thereto, Citicorp North America, Inc. and Citicorp North America, Inc., incorporated by reference to Exhibit 10.89 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000
10.89.1
Amendment One, dated as of August 17, 2000, by and among Midwest Generation, LLC, Edison Mission Energy, EME/CDL Trust, Citicorp Del-Lease, Inc., Wilmington Trust Company, Certain Noteholders Party Thereto, Citicorp North America, Inc. and Citicorp North America, Inc., incorporated by reference to Exhibit 10.89.1 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.90
Reimbursement Agreement, dated as of August 17, 2000, between Edison Mission Energy and Midwest Generation, LLC, incorporated by reference to Exhibit 10.90 to Edison Mission Energy's Form 10-K for the year ended December 31, 2000.
10.91
Supplemental Agreement, dated as of May 30, 2001, to Amendment Two to the Second Amended and Restated U.S. $425 million Bank of America, N.A. Credit Agreement dated as of May 30, 2001, Amendment Three to the U.S. $595 million Credit Agreement dated as of May 30, 2001 and Amendment Two to the U.S. $255 million Credit Agreement dated as of May 30, 2001, incorporated by reference to Exhibit 10.91 to Edison Mission Energy's Form 10-Q for the quarter ended June 30, 2001.
10.92
Credit Agreement, dated as of September 13, 2001, among Edison Mission Energy, Certain Commercial Lending Institutions, Citicorp USA, Inc., as Administrative Agent, and Citibank, N.A. as Issuing Agent, incorporated by reference to Exhibit 10.92 to Amendment No. 1 of Edison Mission Energy's Registration Statement on Form S-4 to the Securities and Exchange Commission on September 27, 2001.
10.93
Edison Mission Energy Exchange Offer Circular, dated as of July 3, 2000.*
10.94
Edison Mission Energy Option Exchange Offer Summary of Deferred Compensation Alternatives, dated as of July 3, 2000.*
10.95
Executive Retirement Plan Amendment 2001-1, incorporated by reference to Exhibit 10.1 to Edison International's Form 10-Q for the quarter ended March 31, 2001. (File No. 1-9936).
10.96
Restatement of Terms of 2000 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.2 to Edison International's Form 10-Q for the quarter ended March 31, 2001. (File No. 1-9936).
10.97
Terms of 2001 basic long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.3 to Edison International's Form 10-Q for the quarter ended March 31, 2001. (File No. 1-9936).
10.98
Terms of 2001 special long-term incentive awards under the Equity Compensation Plan or the 2000 Equity Plan, incorporated by reference to Exhibit 10.4 to Edison International's Form 10-Q for the quarter ended March 31, 2001. (File No. 1-9936).
10.99
Terms of 2001 retention incentives under the Equity Compensation Plan, incorporated by reference to Exhibit 10.5 to Edison International's Form 10-Q for the quarter ended March 31, 2001. (File No. 1-9936).
10.100
Executive Severance Plan as adopted effective January 1, 2001, incorporated by reference to Exhibit 10.34 to Edison International's Form 10-K for the year ended December 31, 2001. (File No. 1-9936).
18.1
Preferability Letter Regarding Change in Accounting Principle for Major Maintenance Costs, incorporated by reference to Exhibit 18.1 to Edison Mission Energy's Form 10-Q for the quarter ended March 31, 2000.
List of Subsidiaries of Edison Mission Energy.*
Letter from Edison Mission Energy Regarding Assurance Letter from Arthur Andersen LLP.*
*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, 2001, 2000 and 1999. 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 2001, 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 2001 and 2000. There were no oil and gas investments which were 50% or less owned by Edison Mission Energy that met the requirements of Rule 3-09 of Regulation S-X in 1999.
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, 2001 and 2000, and the related combined statements of income, partners' equity and members' equity and cash flows for each of the three years in the period ended December 31, 2001. 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 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 combined financial statements referred to above present fairly, in all material respects, the financial position of the Cogeneration Group as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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 25, 2002
THE COGENERATION GROUP
COMBINED STATEMENTS OF INCOME
(In Thousands)
The accompanying notes are an integral part of these consolidated 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 consolidated financial statements.
THE COGENERATION GROUP
COMBINED STATEMENTS OF CASH FLOWS
(In Thousands)
The accompanying notes are an integral part of these consolidated financial statements.
THE COGENERATION GROUP
NOTES TO COMBINED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
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 Cogeneration LLC (jointly referred to herein as the Cogeneration Group). Southern Sierra Energy Company, Western Sierra Energy Company, and Camino Energy Company are wholly owned by Edison Mission Energy but 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, an indirect wholly-owned subsidiary of ChevronTexaco Corporation (Chevron), 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 Chevron, 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. The Partnership shall terminate, unless terminated at an earlier date pursuant to the general partnership agreement, on the latter of December 31, 2006, or the date the Partnership elects to cease operations.
Sycamore Cogeneration Company, which is commonly referred to as Sycamore, is a general partnership between Texaco Cogeneration Company, an indirect wholly-owned subsidiary of Chevron, 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., a wholly owned subsidiary of Chevron, 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. The Partnership shall terminate, unless terminated at an earlier date pursuant to the general partnership agreement, on the latter of December 31, 2008, or the date the Partnership elects to cease operations.
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
As a result of SCE's liquidity crisis in late 2000 and early 2001, SCE failed to make payments to qualifying facilities supplying them power. These qualifying facilities include the Cogeneration Group.
As of December 31, 2001 SCE owed the Cogeneration Group $373.6 million for electric energy delivered from November 1, 2000 through March 26, 2001 (the past due period). SCE claimed the non-payment stemmed from the undercollection in their tariff rates based on the full cost of providing service to their customers. The Cogeneration Group notified SCE that they were in breach of the Power Purchase Agreement (PPA) as a result of the delinquent payments.
On July 31, 2001, the Cogeneration Group and SCE entered into written agreements to address the outstanding issues surrounding SCE's failure to pay past due amounts for energy deliveries from the past due period. SCE agreed to a payment schedule based on the occurrence of certain events, the first of which occurred with the execution of the agreement. SCE paid 10 percent of the past due amount $44.3 million in August, 2001 and agreed to pay an additional 10 percent upon a legislative solution being reached which would restore SCE to creditworthiness and allow them to pay their debts in a timely manner.
On October 2, 2001, SCE and the California Public Utilities Commission (CPUC) announced an agreement that would allow SCE to eventually restore its creditworthiness. The CPUC agreed to freeze consumer rates despite the decline in the price of wholesale electricity.
In March, 2002 SCE paid the Cogeneration Group all of the past due amounts including accrued interest amounting to approximately $362.5 million.
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.
Reclassifications
Certain previously reported amounts have been reclassified to conform to current year presentation.
Operating Plants and Equipment
Operating plants and equipment are stated at cost. Normal repairs for maintenance and minor replacements that do not improve or extend the lives of the respective assets are charged to expense as incurred.
All costs, including interest and field overhead expenses, incurred during construction and precommission phase of the plants were capitalized as part of the cost of the plants. Revenue earned during the precommission phase was offset against the costs of the Facility. The plants and related equipment are being depreciated on a straight-line basis over 30 years, the estimated life of the plants.
The Kern plant's estimated life exceeds the term of the Power Purchase Agreement (PPA) by 8 years, the Sycamore plant's estimated life exceeds the term of the Power Purchase Agreement (PPA) by 10 years and the Watson plant's estimated life exceeds the term of the Power Purchase Agreement (PPA) by 10 years. The viability of these plants subsequent to the expiration of the PPA is uncertain due to the current market for power, the cost to produce power compared to more efficient plants and the ability to increase rates to the steam host. Management periodically evaluates the expected viability of the plants subsequent to the expiration of the PPA's. While management currently believes that the useful lives are appropriate, management subsequently determines that the plants will not be able to operate profitably beyond the PPA, management will accelerate the depreciation charge to the facility over the remaining term of the PPA.
Inventories
Inventories are comprised of materials, supplies and spare parts, and are stated at their lower of average cost or market.
Intangible Assets
Intangible assets are stated net of accumulated amortization of $18.7 million and $16.4 million at December 31, 2001 and 2000, 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 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.
Major 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. Due to the position taken by the Securities Exchange Commission Staff, the two partnerships in 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, after tax, increase to net income, as a cumulative change in the accounting for major maintenance costs, during the year ended December 31, 2000.
Revenue Recognition
Revenue and related costs are recorded as electricity and steam sales are generated or services are provided.
New Accounting Pronouncements
Statements of Financial Accounting Standards Board No. 133 and No. 138
The Cogeneration Group adopted The Financial Accounting Standards Board (FASB) Statement No. 133, "Accounting for Derivative Instruments and Hedging Transactions" (FAS 133), as amended by FAS 138, "Accounting for Derivative Instruments and Hedging Transactions-an amendment of FASB Statement No. 133," effective January 1, 2001. Provisions in Statement No. 133, as amended, affect the accounting and disclosure of certain contractual arrangements and operations of the Partnership. Under Statement No. 133, as amended, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless the derivatives qualify as hedges of future cash flows or net investments. For derivatives qualifying as hedges of future cash flows, the effective portion of changes in fair value is recorded in equity until the related hedged items impact earnings. Any ineffective portion of a hedge is reported in earnings immediately. The Cogeneration Group reviewed the activities performed under its contracts and the respective terms and concluded that the contracts meet the Normal Purchases and Sales Exception defined in FAS 133, which resulted in accrual accounting consistent with the pre-adoption of FAS 133.
Statements of Financial Accounting Standards Board No. 141, No. 142, No. 143 and No. 144
In June 2001, the FASB approved the issuance of three new pronouncements, Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets," and SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 141 requires that the purchase method for accounting be used for all business combinations initiated after June 30, 2001. Management does not expect SFAS No. 141, when adopted to have a material effect on the financial position or results of operations of the Cogeneration Group. SFAS No. 142, effective for financial years beginning after December 15, 2001, changes the accounting for goodwill from an amortization method to one requiring at least an annual review for impairment. Management does not expect SFAS No. 142, when adopted, to have a material effect on the financial position or results of operations of the Cogeneration Group. SFAS No. 143, effective for fiscal years beginning after June 15, 2002, requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Management has not yet determined the impact, if any, of the adoption of SFAS No. 143 on the financial position or results of operations of the Cogeneration Group. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard provides guidance on the impairment of long-lived assets and for long-lived assets to be disposed of. The standard supercedes the current authoritative literature on impairments as well as disposal of a segment of a business and is effective for fiscal years and interim periods beginning after December 31, 2001. Management has not yet determined the impact, if any, of the adoption of this standard on the financial position or results of operation of the Cogeneration Group.
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. Unearned Revenues
Pursuant to the July 31, 2001 agreement to amend the PPA (See Note 1), SCE paid the Cogeneration Group one month in advance for the estimate of the expected monthly energy deliveries at the anticipated natural gas pricing formula of the original contract plus capacity. These advance payments are trued up the following month based on actual deliveries and gas pricing. The advance payments will continue until the past due amounts have been paid.
Note 4. Property, Plant and Equipment
Plant and equipment consist of the following:
Note 5. Loans Payable
The fair value of the two Watson project notes was approximately $44.3 million and $34.5 million at December 31, 2001 and 2000, respectively. The Watson project notes mature in 2008.
The Cogeneration Group received a loan fom the Partners during 2001 of $71 million. The full extent of this loan was paid back to the Partners in 2001. This loan had an interest rate of 7% upon which $2.8 million of interest was paid during the year.
Note 6. Related-Party Transactions/Contractual Obligations
Operating and Other Costs
The amounts incurred by Edison Mission Energy and its affiliates and Chevron and its subsidiaries 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, 2001, 2000 and 1999.
Fuels Management Agreement
Certain partnerships of the Cogeneration Group are party to agreements with Texaco Natural Gas, Inc., a wholly-owned subsidiary of Chevron, whereby Texaco Natural Gas, Inc. is to procure, at prices based upon the spot market, and manage all fuel-gas supplies and transportation for two of the plants (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) until termination of the Parallel Generation Agreement.
As of January 1, 1996, the Amended and Restated Fuel Management Agreement, terminating on October 1, 2002, was entered into such that Texaco Natural Gas, Inc. will receive a fixed service fee 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, 2001, Texas Natural Gas, Inc. received a fixed service fee of $.039 per MMBtu. The amounts incurred under the amended agreements were $340.1 million, $315.3 million and $177.4 million, which included fees earned by Texaco Natural Gas, Inc. of $2.4 million, $2.5 million and $2.5 million, for the three years ended December 31, 2001, 2000 and 1999, 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 $208.6 million, $155.2 million and $32.4 million for the three years ended December 31, 2001, 2000 and 1999, 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 $6.2 million, $6.3 million, and $6.1 million, which included incentive compensation earned by Edison Mission Operation & Maintenance, Inc. of $0.9 million, $1.0 million and $0.9 million for the three years ended December 31, 2001, 2000 and 1999, 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 plant. 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 $10.4 million, $5.7 million, and $5.6 million for the three years ended December 31, 2001, 2000 and 1999, 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, 2001, 2000 and 1999.
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 certain partnerships in the Cogeneration Group to maintain qualifying facility status.
These agreements have been amended whereby the partnerships began receiving reduced steam revenues in 1998. The reduction in steam revenues based upon these agreements totaled $26.2 million, $24.2 million and $20.9 million for the three years ended December 31, 2001, 2000 and 1999 respectively.
One of the Partnerships entered into a Power Purchase Agreement with ARCO. Under the terms of the Steam and Water contract with ARCO, this Partnership contracted to sell steam and water generated by the Facility to ARCO's Los Angeles refinery.
Parallel Generation Agreements
The Cogeneration Group has two Parallel Generation Agreements with SCE for the sale of contract capacity and net energy generated by the Cogeneration Group. The Parallel Generation Agreements will remain in effect 20 years from the firm operation date, August 9, 1985 and January 1, 1998, respectively. The Parallel Generation Agreements was amended to contain energy pricing terms that maintain the intent of the Parallel Generation Agreement's original pricing terms. Energy payments are currently based on an energy rate that is calculated using a short-run-avoided-cost-based
formula (SRAC Floor 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. SCE also pays the Cogeneration Group for firm capacity based upon a contracted amount per kilowatt year, as defined in the Parallel Generation Agreement.
The Parallel Generation Agreements require the Cogeneration Group to make repayment of capacity payments to SCE, 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, 2001, would be approximately $84.5 million. Management has 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.
7. Commitments and Contingencies
Ship or Pay
Pursuant to the Master Agreement, entered into as of December 1, 1994, certain partnerships of the Cogeneration Group executed a Security of Supply Agreement with an affiliated partnership of Edison Mission Energy and Texaco. As such the Cogeneration Group has agreed to accept and underwrite, on a pro-rata basis, a portion of Texaco's commitment pursuant to the Transportation Agreement between Texaco, the Mojave Pipeline Company and the El Paso Pipeline Company, dated February 15, 1989 and extending through March 31, 2008. The Cogeneration Group has agreed that Mojave Pipeline Company and El Paso Pipeline Company shall be the exclusive means of delivery for certain partnerships within the Cogeneration Group of the lesser of 75 percent of the annual total natural gas fuel requirements for such Cogeneration Group and 52,012,500 MMBtu per year.
Except upon the occurrence of certain permissible events, two of the partnerships within the Cogeneration Group are subject to certain terms and conditions, whereby failure to transport the required quantity of natural gas on the Mojave Pipeline Company's pipeline will result in the Cogeneration Group paying $0.63 per deficit MMBtu. Such Cogeneration Group will share any ship-or-pay liabilities on a pro-rata basis, as defined in the Transportation Agreement, with the affiliated partnership.
For each of the years in the three-year period ended December 31, 2001, 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 ACCOUNTANTS
To the Stockholders of
Four Star Oil & Gas Company:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, stockholders' equity and cash flows present fairly, in all material respects, the financial position of Four Star Oil & Gas Company (a Delaware corporation) and its subsidiary at December 31, 2001 and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. 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 audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
February 15, 2002
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of
Four Star Oil & Gas Company:
We have audited the accompanying consolidated balance sheet of Four Star Oil & Gas Company (a Delaware corporation) and subsidiary as of December 31, 2000 and the related consolidated statements of income, stockholders' equity and cash flows for each of the two 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 the results of their operations and their cash flows for each of the two 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, 2001 AND 2000
(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 STATEMENT OF INCOME
Years Ended December 31, 2001, 2000 and 1999
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In Millions, Except Share Amounts)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
Years Ended December 31, 2001, 2000 and 1999
(In Millions)
The accompanying notes are an integral part of these consolidated financial statements.
FOUR STAR OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001 and 2000
1. BASIS OF PRESENTATION AND DESCRIPTION OF THE COMPANY:
Four Star Oil and Gas Company is a subsidiary of ChevronTexaco that explores for and produces crude oil, natural gas and natural gas liquids. Texaco Exploration and Production Inc. (TEPI) operates and manages the majority of Four Star's operations under the terms of a service agreement.
In October 2001, the merger between Texaco and Chevron Corporation (Chevron) was approved and ChevronTexaco Corporation (ChevronTexaco) became the ultimate parent of Texaco Inc. In these financial statements we continue to refer to the separate affiliates by their legal entity names. 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. In 1989, 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 31, 1991.
As a result of a series of stock transactions occurring between January 1, 1992 and December 31, 2001, Texaco's ownership interest in Four Star was reduced to 71%. As of December 31, 2001 and 2000, the ownership interests in Four Star were as follows:
2. SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation
The consolidated financial statements include the accounts of Four Star Oil & Gas Company (Four Star or the Company) and Mission Energy Methane, a wholly-owned subsidiary of Four Star. All significant intercompany accounts and transactions have been eliminated in consolidation.
Revenue Recognition
Revenue from product sales is recognized upon delivery of products to customers.
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 total 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 using the straight-line method, with depreciation rates based upon estimated useful lives applied to the cost of each class of property. The useful lives of such assets range from 3 to 20 years.
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.
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 2001 and 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. In each of 2001 and 2000, 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 impairment changes of $7 million and $25 million on its Green Canyon 184 property in 2001 and 2000, respectively, due to downward reserve revisions. The Company did not record any impairment charge in 1999.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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. The most significant estimates pertain to proved oil, NGL and gas reserve volumes and plug and abandonment costs as well as estimates relating to the calculation of impairment under SFAS No. 121. Actual results could differ from those estimates.
Reclassifications
Certain previously reported amounts have been reclassified to conform to current-year presentation. Such reclassification had no effect on reported net income or shareholders' equity.
Income Taxes
Deferred taxes result from temporary differences in the recognition of revenues and expenses for tax and financial reporting purposes and are calculated based upon cumulative book and tax differences in the balance sheet in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes."
Derivatives
The adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," did not have a material effect on the Company's financial position as the Company has no derivatives as of December 31, 2001 and 2000, except for its physical sale contracts, which qualify as normal sales. The Company adopted SFAS 133 as of January 1, 2001.
New Accounting Pronouncements
The following SFASs were issued in 2001: SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, SFAS No. 143, Accounting for Asset Retirement Obligations and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 141 requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001 and for all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite
lives not be amortized but be tested annually for impairment, effective for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 142 on January 1, 2002 and such adoption did not have a material effect on the Company's financial position, result of operations or cash flows. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and long-lived assets to be disposed of. It supersedes, with limited exceptions, SFAS No. 121 and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore, at this time, cannot reasonably estimate the effect of these statements on its consolidated financial position, results of operations or cash flows.
3. RELATED PARTY TRANSACTIONS:
Four Star has various business transactions with ChevronTexaco and other ChevronTexaco subsidiaries and affiliates. These transactions principally involve sales by Four Star of crude oil, natural gas and natural gas liquids. In addition, ChevronTexaco charges Four Star for management, professional, technical and administrative services, as well as direct charges for exploration and production-related activities.
Prior to December 1, 1999, TEPI charged Four Star for certain management, professional, technical and administrative services pursuant to a service agreement. In 1999, Four Star paid $18 million to TEPI under the service agreement.
Effective December 1, 1999, Four Star entered into a revised service agreement with TEPI for management, administrative, professional and technical services through November 1, 2004. During 2000, Four Star paid TEPI a monthly fixed fee of $568,417 through November 15, 2000. Beginning November 15, 2000, the monthly fixed fee was adjusted to $579,785, and this rate remained in effect throughout 2001. An aggregate amount of $7.0 million and $6.8 million in service fees was included as a component of operating expenses in the accompanying consolidated statement of income for the years ended December 31, 2001 and 2000, respectively.
In addition, Four Star paid a monthly unit fee of $612,368 during the period from January 1, 2000 to November 15, 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. Total unit fees of $7.7 million and $7.3 million are included as a component of operating expenses in the accompanying consolidated statements of income for the years ended December 31, 2001 and 2000, respectively.
In March 1999, Four Star issued 300 shares of preferred stock in exchange for TEPI's interest in the Hugoton Gas Field.
Pursuant to the contractual agreement described in Note 10, certain tax benefits and liabilities are assumed by ChevronTexaco.
The following table summarizes sales to and purchases from affiliates during 2001, 2000 and 1999 (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 pretax gain on the sale.
5. NOTE PAYABLE TO AFFILIATE:
In September 1999, Four Star retired its loan facility 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, 2001 and 2000. The loan bears interest at LIBOR plus one percent and matures on December 31, 2005. The interest rate was 3.4%, 7.0% and 7.5% at December 31, 2001, 2000 and 1999, respectively. Interest expense during 2001, 2000 and 1999 was $13 million, $18 million and $15 million, respectively. Four Star pays ChevronTexaco an annual facility fee and administrative fee of $50,000.
The Company's borrowing base is redetermined annually each September 30 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 repay such excess to ChevronTexaco in four equal quarterly installments. Throughout 2001 and 2000, Four Star's borrowing base exceeded the outstanding loan balance, thus no principal payments were due. As of December 31, 2001, the Company's borrowing base was $388 million.
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:
Substantially all of the Company's accounts receivable at December 31, 2001, result from sales to the Company's two largest customers both of which are ChevronTexaco affiliates, as discussed in Note 3. The Company's credit policy and relatively short duration of receivables mitigate the risk of uncollected receivables. During each of the three years in the period ended December 31, 2001, the Company did not incur any credit losses on receivables.
Two customers, Texaco Natural Gas Inc. and Equilon Enterprises LLC, individually accounted for more than 10 percent of the Company's total revenues in 2001, 2000 and 1999. Texaco Natural Gas Inc. accounted for 81 percent, 52 percent and 55 percent of sales in 2001, 2000 and 1999, respectively, and Equilon Enterprises LLC accounted for 14 percent, 17 percent and 22 percent of sales in 2001, 2000 and 1999, 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, 2001, 2000 and 1999, 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 (29 percent in 2001, 31 percent in 2000 and 22 percent in 1999), primarily as the result of certain tax credits available to the Company. Reconciliations of income taxes computed using the statutory rate to the Company's 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 (nonvoting), and preferred (Class A preferred and Class B preferred).
In 1999, 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 ChevronTexaco), provided that ChevronTexaco's aggregate ownership interest in the common stock at the time of purchase shall not be reduced to less than 51 percent of all common
stock outstanding at the time of purchase. In 2001, the agreement was amended to replace Texaco with CTGEI. The option expires on December 23, 2006. As of December 31, 2001 and 2000, Mission Energy owned 23 percent and 20 percent, respectively, of all voting common stock outstanding. Four Star Oil and Gas Holdings Company (owned jointly by CTGEI and Mission Energy) owned 26 percent of all voting common stock in the Company as of December 31, 2001.
Each share of Class A preferred stock is entitled to receive cumulative cash dividends of $5,112 per share per annum, payable semiannually. Each share of Class B preferred stock is entitled to receive cumulative cash dividends of $2,250 per annum, payable semiannually.
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 of such instruments approximate their fair market values 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 AND CONTINGENCIES:
ChevronTexaco 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, cash flows or results of operations of the Company.
11. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
In accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" (SFAS No. 69), this section provides supplemental information on oil and gas exploration and producing activities of the Company in seven separate tables. Tables I through IV provide historical cost information pertaining to costs incurred in exploration, property acquisitions and developments capitalized costs, and results of operations. Tables V and VII present information on the Company's estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.
Table I-Costs incurred in exploration, property acquisitions and development1
(millions of dollars)
Year ended December 31, 2001:
1Includes cost incurred whether capitalized or expensed. Excludes support equipment expenditures. Table II-Capitalized costs related to oil and gas producing activities:
(millions of dollars)
At December 31, 2001:
Table III-Results of operations for oil and gas producing activities:
The Company's results of operations from oil and gas producing activities for the year 2001 are shown in the following table. In accordance with SFAS No. 69, income taxes in Table III are based on statutory tax rates, reflecting allowable deductions and tax credits. Interest income and expense are excluded from the results reported in Table III.
(millions of dollars)
Year Ended December 31, 2001:
Table IV-Results of operations for oil and gas producing activities-unit prices and costs:
Year Ended December 31, 2001:
Table V-Reserve quantity information
The Company's estimated net proved underground oil and gas reserves and changes thereto for the year 2001 are shown in the following table. Proved reserves are estimated by Company asset teams composed of earth scientists and reservoir engineers. These proved reserve estimates are reviewed annually by the Company's Reserves Advisory Committee to ensure that rigorous professional standards and the reserves definitions prescribed by the U.S. Securities and Exchange Commission are consistently applied throughout the Company.
Proved reserves are the estimated quantities that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.
Proved reserves do not include additional quantities recoverable beyond the term of the lease or concession agreement or that may result from extensions of currently proved areas or from applying secondary or tertiary recovery processes not yet tested and determined to be economic.
Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
"Net" reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.
(1)Proved reserves of oil condensate, natural gas liquids and natural gas are located entirely within the United States. Table VI-Standardized measure of discounted future net cash flows related to provided oil and gas reserves:
The standardized measure of discounted future net cash flows, related to the preceding proved oil and gas reserves, is calculated in accordance with the requirements of SFAS No. 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using ten percent midperiod discount factors. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced.
The information provided does not represent management's estimate of the Company's expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserved quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become reserves in the future, are excluded from the calculations. The arbitrary valuation prescribed under SFAS No. 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the Company's future cash flows or value of its oil and gas reserves.
(millions of dollars)
At December 31, 2001:
Table VII-Changes in the standardized measure of discounted future net cash flows from proved reserves:
(millions of dollars)
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Changes in the timing of production are included with "Revisions of previous quantity estimates."
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EDISON MISSION ENERGY
(Registrant)
By:
/s/ KEVIN M. SMITH Kevin M. Smith
Senior Vice President, Chief Financial Officer and Treasurer
Date: March 28, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
Principal Executive Officer:
/s/ WILLIAM J. HELLER William J. Heller
President and Chief Executive Officer
March 28, 2002
Controller or Principal Accounting Officer:
/s/ KEVIN M. SMITH Kevin M. Smith
Senior Vice President, Chief Financial Officer and Treasurer
March 28, 2002
Majority of Board of Directors:
/s/ JOHN E. BRYSON John E. Bryson
Director, Chairman of the Board
March 28, 2002
/s/ BRYANT C. DANNER Bryant C. Danner
Director
March 28, 2002
/s/ THEODORE F. CRAVER, JR. Theodore F. Craver, Jr.
Director
March 28, 2002
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 (Loss)
(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)
(1)Excludes allowance for doubtful accounts of discontinued operations of $1.4 million.
(2)Excludes maintenance accruals of discontinued operations. Effective January 1, 2000, we recorded a $4.1 million, after tax, decrease to income (loss) from discontinued operations, as the cumulative effect of change in accounting for major maintenance costs.
(3)Through December 31, 1999, we accrued for major maintenance costs during the period between turnarounds (referred to as "accrue in advance" accounting method). In March 2000, we voluntarily decided to change our accounting policy to record major maintenance costs as an expense as incurred. This change in accounting policy is considered preferable based on guidance provided by the Securities and Exchange Commission. In accordance with Accounting Principles Board Opinion No. 20, "Accounting Changes," we have recorded a $21.8 million, after tax, increase to income from continuing operations, as the cumulative effect of change in the accounting for major maintenance costs during the quarter ended March 31, 2000.
PART I
PART II
RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
EDISON MISSION ENERGY AND SUBSIDIARIES REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollars in millions)
PART III
SUMMARY COMPENSATION TABLE
AGGREGATED OPTION EXERCISES IN 2001 AND YEAR-END OPTION VALUES
LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR(1)
PENSION PLAN TABLE(1)
PART IV
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
THE COGENERATION GROUP COMBINED STATEMENTS OF INCOME (In Thousands)
THE COGENERATION GROUP COMBINED BALANCE SHEETS (In Thousands)
THE COGENERATION GROUP COMBINED STATEMENTS OF PARTNERS' EQUITY AND MEMBERS' EQUITY (In Thousands)
THE COGENERATION GROUP COMBINED STATEMENTS OF CASH FLOWS (In Thousands)
THE COGENERATION GROUP NOTES TO COMBINED FINANCIAL STATEMENTS December 31, 2001, 2000 and 1999
REPORT OF INDEPENDENT ACCOUNTANTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
FOUR STAR OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS-DECEMBER 31, 2001 AND 2000 (In Millions, Except Share and Per Share Amounts)
FOUR STAR OIL & GAS COMPANY CONSOLIDATED STATEMENT OF INCOME Years Ended December 31, 2001, 2000 and 1999 (In Millions)
FOUR STAR OIL & GAS COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (In Millions, Except Share Amounts)
FOUR STAR OIL & GAS COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS Years Ended December 31, 2001, 2000 and 1999 (In Millions)
FOUR STAR OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2001 and 2000
SIGNATURES
EDISON MISSION ENERGY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT Condensed Statements of Income (Loss) (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES CONDENSED FINANCIAL INFORMATION OF PARENT Condensed Statements of Cash Flows (In thousands)
EDISON MISSION ENERGY AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (In thousands)