-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JhdFuF2H5V/dVaoHxxcNjaROwRbdR1OSTT3KcJBDfHCTT5/tMdZvfnri3OH9SGCT XVTwJbMDXadlLJ9272KerA== 0000720556-98-000005.txt : 19980401 0000720556-98-000005.hdr.sgml : 19980401 ACCESSION NUMBER: 0000720556-98-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980331 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALENERGY CO INC CENTRAL INDEX KEY: 0000720556 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 942213782 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-09874 FILM NUMBER: 98581031 BUSINESS ADDRESS: STREET 1: 302 S 36TH ST STREET 2: STE 400 CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FORMER COMPANY: FORMER CONFORMED NAME: CALIFORNIA ENERGY CO INC DATE OF NAME CHANGE: 19920703 10-K 1 2 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K Annual Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1997 Commission File No. 1-9874 CALENERGY COMPANY, INC. (Exact name of registrant as specified in its charter) Delaware 94-2213782 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 302 S. 36th Street, Suite 400, Omaha, NE 68131 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (402) 341-4500 Securities registered pursuant to Section 12(b) of the Act: Name of exchange Title of each class on which registered Common Stock, $0.0675 New York Stock Exchange par value ("Common Stock") Pacific Stock Exchange London Stock Exchange Securities registered pursuant to Section 12(g) of the Act: N/A Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ] Based on the closing sales price of Common Stock on the New York Stock Exchange on March 23, 1998 the aggregate market value of the Common Stock held by non-affiliates of the Company was $1,865,191,447. 60,411,059 shares of Common Stock were outstanding on March 23, 1998. TABLE OF CONTENTS PART I 1 ITEM 1. BUSINESS 1 GENERAL 1 RECENT SUCCESSFUL ACQUISITIONS 1 STRATEGY 2 THE GLOBAL ENERGY MARKET 4 THE UNITED STATES 6 THE UNITED KINGDOM 6 THE PHILIPPINES 8 THE COMPANY'S DISTRIBUTION AND SUPPLY BUSINESS 8 POWER GENERATION PROJECTS 10 PROJECTS IN OPERATION 10 PROJECTS IN CONSTRUCTION 11 PROJECTS WITH SIGNED POWER SALES CONTRACTS OR AWARDED DEVELOPMENT RIGHTS 12 PROJECTS IN OPERATION 13 UNITED STATES OPERATIONS 13 U.S. GAS PROJECTS 16 OTHER U.S. GEOTHERMAL OPERATIONS 18 UNITED KINGDOM OPERATIONS AND CONSTRUCTION 18 THE PHILIPPINES OPERATIONS AND CONSTRUCTION 18 INDONESIA OPERATIONS AND CONSTRUCTION 22 PROJECTS IN DEVELOPMENT 23 UNITED STATES 23 UNITED KINGDOM 24 PHILIPPINES 24 INDONESIA 25 PRODUCING GAS FIELD OPERATIONS AND FIELDS IN DEVELOPMENT 25 THE COMPANY'S PRODUCING GAS FIELD OPERATIONS AND FIELDS IN DEVELOPMENT 25 FIELDS IN DEVELOPMENT 26 REGULATORY, ENERGY AND ENVIRONMENTAL MATTERS 27 UNITED STATES 27 UNITED KINGDOM 28 EMPLOYEES 28 ITEM 2. PROPERTIES 29 ITEM 3. LEGAL PROCEEDINGS 29 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 29 PART II 30 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER'S MATTERS 30 ITEM 6. SELECTED FINANCIAL DATA 31 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION 31 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 31 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 31 PART III 32 MANAGEMENT 32 ITEM 10. DIRECTORS, EXECUTIVE AND OTHER OFFICERS OF THE COMPANY32 PART IV 38 ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 38 SIGNATURES 40 EXHIBIT INDEX 62 DOCUMENTS INCORPORATED BY REFERENCE Incorporated by reference into this Form 10-K, in response to Item 3 Part I, Items 6 through 8 of Part II and Items 10 through 13 of Part III, are the portions indicated herein of (i) the annual report of CalEnergy Company, Inc. (the "Company") to security holders for the fiscal year ended December 31, 1997 (the "Annual Report"), and (ii) the Company's proxy statement dated on or about April 3, 1998 for the annual meeting of stockholders to be held on May 21, 1998 (the "Proxy Statement"). PART I Item 1. Business General CalEnergy Company, Inc. (the "Company") is a fast-growing global power company whose goal is to be a leading provider of low cost and reliable energy services throughout the world as governments privatize or deregulate electricity and gas markets. The Company was founded in 1971 and, through its subsidiaries, manages and owns interests in over 5,000 megawatts ("MW") of power generation facilities in operation, construction and development worldwide, including 20 generating facilities which it currently operates. In addition, through its subsidiary, Northern Electric plc ("Northern"), the Company is engaged in the distribution of electricity to approximately 1.5 million customers primarily in northeast England as well as the supply of electricity and gas (together with other related business activities) throughout England and Wales. The Company has achieved significant growth in earnings and assets over the past five years through: (i) acquisitions that complement and diversify the Company's existing business, broaden the geographic locations of and fuel sources used by its projects and enhance its competitive capabilities; (ii) enhancement of the financial and technical performance of existing and acquired projects; and (iii) development and construction of new plants and facilities ("greenfield development"). The market capitalization of the Company has risen at a compound annual rate of 28% from approximately $656 million in December 1993 to approximately $1.9 billion in March 1998, the revenues of the Company have risen at a compound annual rate of 130% from approximately $186 million in 1994 to approximately $2.2 billion in 1997 and net income available to common stockholders excluding non-recurring and extraordinary items has risen at a compound annual rate of 60% from approximately $34 million in 1994 to approximately $139 million in 1997. From 1994 through 1997, the Company's EBITDA and total assets have increased by a compound annual growth rate of 84% and 88%, respectively. EBITDA for the year ended December 31, 1997 was $811 million before a non-recurring item. "EBITDA" means the Company's earnings, before interest, taxes, depreciation and amortization. Information concerning EBITDA is presented here not as a measure of operating results, but rather as a measure of the Company's ability to service debt. EBITDA should not be construed as an alternative to either (i) operating income (determined in accordance with Generally Accepted Accounting Principles ("GAAP")) or (ii) cash flow from operating activities (determined in accordance with GAAP). In this Annual Report, references to "U.S. dollars," "dollars," "US $," "$" or "cents" are to the currency of the United States and references to " pounds sterling," "pounds," "sterling," "pounds sterling," "pence" or "p" are to the currency of the United Kingdom. The Company's Common Stock is traded on the New York, Pacific and London Stock Exchanges. The principal executive offices of the Company are located at 302 South 36th Street, Suite 400, Omaha, Nebraska 68131 and its telephone number is (402) 341-4500. The Company was incorporated in 1971 under the laws of the State of Delaware. Recent Successful Acquisitions In the last three years, the Company has consummated several significant acquisitions, which have been successfully integrated and immediately accretive to earnings. In January 1995, the Company acquired Magma Power Company ("Magma"), a publicly-traded United States independent power producer with 228 net MW of operating capacity and 154 net MW of ownership capacity, for approximately $958 million. The Magma acquisition, combined with the Company's previously existing assets, made the Company the world's largest independent geothermal power producer (based on the Company's estimate of aggregate MW of electric generating capacity in operation and construction). In April 1996, the Company completed the purchase for approximately $70 million of its partner's interests in four electric generating plants in Southern California, resulting in sole ownership of the Imperial Valley Projects' 228 net MW of aggregate operating capacity. In August 1996, the Company acquired Falcon Seaboard Resources, Inc. ("Falcon Seaboard") for approximately $226 million, thereby acquiring significant ownership in 520 net MW of natural gas-fired electric production facilities located in New York, Texas and Pennsylvania and a related gas transmission pipeline. In December 1996, the Company acquired a majority of the common shares of Northern. Northern is one of the twelve regional electricity companies (each, a "REC") which came into existence as a result of the restructuring and subsequent privatization of the electricity industry in the United Kingdom ("U.K.") in 1990. Northern distributes electricity in its authorized area located in northeast England which covers approximately 14,400 square kilometers and has a population of approximately 3.2 million people. Northern also supplies electricity and gas inside and outside its authorized area and currently owns interests in four producing gas field operations in the North Sea. On September 11, 1997, the Company signed a definitive agreement with Kiewit Diversified Group Inc. ("KDG"), a wholly-owned subsidiary of Peter Kiewit Sons', Inc. ("PKS"), to acquire all of KDG's ownership interest in Northern and the various other international power generation projects and development opportunities (the "Energy Project Joint Venture Acquisition") which were jointly owned with, and managed by, the Company, as well as to repurchase all of KDG's outstanding ownership interests in the Company's Common Stock (the "Stock Repurchase," and together with the Energy Project Joint Venture Acquisition, the "KDG Acquisition"). The Company completed the KDG Acquisition on January 2, 1998. KDG's ownership interest in the Company consisted of 20,231,065 shares of Common Stock (including options to acquire 1,000,000 shares of Common Stock) which represented approximately 30% of the Company's then outstanding shares (26% on a fully diluted basis), a 30% interest in Northern and the following power project interests: 45% of the 165 net MW Mahanagdong project, 35% of the 150 net MW Casecnan project, 47% of the 400 net MW Dieng project, 44% of the 400 net MW Patuha project, and 30% of the 400 net MW Bali project. The Company is the managing partner and operator of each such project (collectively, the "Joint Venture Energy Projects"). In addition, KDG's 50% interest in all other power project opportunities which the Company had in development under the international joint venture agreement with KDG were transferred to the Company. The Company immediately added over 1,000 net MW of generating capacity in operation, construction and development to its project portfolio (including approximately 850 net MW of operating, construction and advanced stage development projects). The Company paid $1,159 million for KDG's ownership interest in Northern, the Joint Venture Energy Projects and the Company's Common Stock. The Company funded the KDG Acquisition with available cash, the net proceeds from the issuance of 19.1 million shares of Common Stock which closed on October 17, 1997 and the proceeds of an offering of 7.63% Senior Notes due 2007 which closed on October 28, 1997. These debt securities are senior unsecured obligations of the Company ranking pari passu in right of payment with all other existing and future senior unsecured obligations of the Company and will rank senior to all other existing and future subordinated debt of the Company. Strategy The Company's growth strategy remains focused upon taking advantage of the investment opportunities created by the continuing deregulation and privatization in energy sectors throughout the world. In order to effectively execute its growth strategy, the Company has organized its operations into a functional structure. The functional alignment is believed to allow for greater efficiencies in operations and better coordination and asset utilization in developing the Company's business. The Company's strategy is comprised of the following key elements: o Growth through international and domestic acquisitions. The Company has successfully completed five acquisitions in the past three years, each of which was immediately accretive to earnings. The Company believes several of these acquisitions provided it with specialized skills and experience that enhance its competitive position in the areas it has targeted for future growth. For example, the Company's acquisition of Northern, a U.K. regional electricity company engaged in electricity distribution and supply and gas supply and related businesses, is the first step in its planned expansion into those sectors in the U.S. and elsewhere throughout the world. In addition, since the U.K. is progressively deregulating its electricity and gas supply sectors, the Company believes that its Northern management team has the knowledge and skills to compete in a competitive supply market. Northern also possesses the sophisticated billing and proprietary information systems that are believed by the Company to be critically important components of the skill and technology base necessary to compete effectively in a deregulated environment. The Company believes that the electricity industry in the U.S. will also progressively deregulate over the next three to five years and will largely follow the regulatory model established in the U.K. (with incentive based rates or price caps). As currently regulated U.S. electricity distributors and electricity and gas suppliers attempt to rationalize their businesses to maintain profitability in a price competitive market, the Company believes that opportunities will become available to low cost and reliable providers of energy services to gain market share in energy supply and provide additional services to competitors (such as utility line construction and maintenance services, metering, customer billing and information systems services). As a result, the Company believes that by acquiring a U.S. utility operation and transferring the knowledge, skills and systems gained at Northern, it can create a platform from which a U.S. energy distribution and supply business can be profitably established and expanded in a deregulated market. Consistent with its disciplined approach to acquisitions, the Company will continue to evaluate U.S. utility available opportunities from time to time, although it currently has no specific acquisition plans. o Growth through greenfield development of energy projects. The Company continues to view the international power generation sector as an attractive market for the development of new greenfield energy opportunities, an area in which it has demonstrated substantial expertise. In the past three years, the Company has developed and financed seven new international power projects, three of which have already completed construction on schedule and within budget and are now earning revenues and the remaining four of which are still in the construction phase. With the acquisition of Sovereign Exploration Ltd. (now CalEnergy Gas UK) as part of the Northern acquisition, the Company has expanded its development strategy to include integrated generation and upstream natural gas operations. The addition of gas exploration, production and technical storage capabilities allows the Company to expand its number of target markets throughout the world. In addition, utilization of its geotechnical expertise in this manner allows early entrance with limited upfront capital expenditures into markets in which the Company might not otherwise have power development opportunities. The integration of power generation plants with the upstream gas sources in competitive energy markets will also produce market arbitrage opportunities to sell either gas or electricity depending upon market conditions at the time. The Company previously announced two upstream gas projects, one in Western Australia at the Gingin field in the Perth Basin and one in Poland at the large Pila Concession. o Profit enhancement through operating efficiencies while maintaining quality and reliability of service. The Company aggressively pursues profitability improvements through efficiency and productivity gains at existing operations. Since 1991, the cost of production per kilowatt hour ("kWh") at the Company's Coso Projects has declined from 2.7 cents/kWh to 2.0 cents/kWh. Since 1994, the cost of production per kWh at the Imperial Valley Projects (as defined herein) has declined from 5.3 cents/kWh to 2.9 cents/kWh. In each case, the Company has achieved these efficiencies while maintaining high reliability and safety in its operation. Through continuing advancements in drilling technology, reservoir modeling and well maintenance techniques, the production capacity of new and existing wells has been improved or maintained and, as a result, the useful output of the various geothermal resources has been improved or maintained. o Continued diversification of revenue base and fuel sources. The Company believes that it presently has a diversified revenue base, distributed among its ownership of an operating electricity utility, its ownership of 1,689 net MW in twenty-one operating projects and its ownership of producing gas fields. Other than the revenues of Northern, which are largely derived from its electricity distribution and supply activities, substantially all of the Company's current revenues are based on long-term contracts with seven large U.S. utility companies and the foreign government of the Philippines (sovereign ratings of Ba1/BB+). The Company intends to seek continued diversification of its revenue base and fuel sources through acquisitions and greenfield development. o Maintenance of prudent financial and risk management practices. The Company has consistently maintained, and intends in the future to maintain what it believes to be prudent financial and risk management practices. A primary objective of the Company is to structure project financing for development projects which can be rated investment grade by Moody's Investor Services Inc. and Standard & Poor's Ratings Services. Its Coso projects are rated Baa2/BBB; its Salton Sea Funding Corp. is rated Baa3/BBB-; its Northern Electric subsidiary is rated A3/BBB+, and its CE Electric UK Funding Company subsidiary's senior notes are rated Baa1/BBB+. The debt ratings reflected above have been published by Moody's Investors Services, Inc. and Standard & Poor's Ratings Services, respectively, in respect of certain senior indebtedness of the respective issuers shown. These ratings may be changed from time to time by the ratings agencies. The project financing structures engaged in to date by the Company include as a fundamental protection for the Company's other assets the requirement that (with certain minimal exceptions) the funds borrowed for the purpose of financing a project are to be financed primarily or entirely under loan agreements and related documents which provide that the loans are to be repaid solely from the project's revenues and that the security granted to secure the loan obligation be limited to the capital stock, assets, contracts and cash flow of the project or its holding company. Under this type of financing structure, the lenders cannot seek recourse against the Company or its other subsidiaries or projects. The Company intends to continue to structure future projects in a manner which minimizes the exposure of the Company's other assets through appropriate non-recourse project financings. o Continued adherence to strict project evaluation criteria. The Company intends to operate only in those countries where economic fundamentals are believed to be attractive and risks can be contractually mitigated or adequately covered by insurance. The Company's international investment criteria generally includes giving due consideration, where appropriate, to the following: o Sovereign guarantees; o Significant demand for new power generating facilities; o An established legal system providing for enforceability of contracts and regulations; o Contracts with utilities, governments or other parties with acceptable creditworthiness which provide for primarily US$-denominated payments and certain contractual protections regarding currency convertibility and transferability; o Fixed-price date-certain, turnkey construction contracts with liquidated damages and performance security provisions; and o Availability of political risk insurance. The Company intends to continue to focus primarily upon those development opportunities where it is permitted, directly or indirectly, to acquire a majority ownership interest and exercise operational control over the newly developed or acquired projects. The Global Energy Market The opportunity for independent power generation and energy distribution and supply has expanded from a United States market to a global competitive market as many foreign countries have initiated restructuring and privatization policies that encourage the development of independent power generation and independent distribution and supply of energy. Internationally, large amounts of new electric power generating capacity are required in developing countries. The movement toward privatization in some developing countries has created significant new markets outside the United States. The need for rapid economic expansion has caused many countries to select private power development as their only practical alternative and to restructure their legislative and regulatory systems to facilitate such development. The Company believes that the significant need for power in developing markets has created strong local support for private power projects in many foreign countries and has increased the availability of attractive long-term power contracts. The Company intends to take advantage of opportunities in these markets and to develop, construct and acquire power generation, distribution and supply and related energy projects meeting its strategic criteria outside the United States. In addition, as privatization, deregulation and restructuring initiatives are enacted in various countries and states, the Company has identified a number of promising opportunities to acquire power generation, distribution and supply assets, as well as other energy related infrastructure assets. These opportunities include bidding opportunities in connection with privatization initiatives in the electricity and gas distribution and supply sectors in various countries, including principally Eastern Europe, South America, Australia and New Zealand. The Company expects to see more of such acquisition opportunities in additional markets in the future. In pursuing its strategy, the Company presently intends to focus upon development and acquisition opportunities in countries possessing certain characteristics which meet the Company's investment criteria. At the present time, the Company is active in the United States, the Philippines and the United Kingdom and is pursuing development opportunities in Australia, New Zealand and Poland. Set forth below is certain general information concerning the present status of the energy markets in those countries in which the Company currently has significant operations. The United States In the United States, the independent power industry expanded rapidly in the 1980s, facilitated by the enactment of the Public Utilities Regulatory Policies Act ("PURPA"). PURPA was enacted to encourage the production of electricity by non-utility companies (frequently referred to as independent power companies) as well as to lessen reliance on imported fuels. According to the Utility Data Institute, independent power producers were responsible for the installation of approximately 30,000 MW of capacity, or 50%, of the United States electric generation capacity that has been placed in service since 1988. However, as the size of the United States independent power market increased, available domestic power capacity and competition in the industry also significantly increased and the need for new generating capacity has been reduced. During the last few years, many states began to accelerate the movement toward more competition in many aspects of the electric power market, including generation, transmission, distribution and supply. Extensive federal and state legislative and regulatory reviews are presently underway in an effort to further such competition. In particular, the state of California has adopted a bill to restructure the electric industry by providing for a phased-in competitive power generation industry, with a power exchange and independent system operator, and for direct access to generation for all power purchasers outside the power exchange under certain circumstances. The bill provides that existing qualifying facility power sales agreements will be honored. Other states have or are expected to take similar steps aimed at increasing competition by restructuring the electric industry, allowing retail competition and deregulating most electric rates. In addition, recent federal legislation has been proposed which would repeal PURPA and the Public Utility Holding Company Act of 1935, as amended, respectively. The Company cannot predict the final form or timing of the proposed industry restructuring or the result on its operations. However, the Company believes that the impending changes in the regulation of the United States power markets will reflect many aspects of the United Kingdom model (discussed below) for competitive generation, transmission, distribution and supply of energy. The Company further expects that the current effort to introduce broader wholesale and retail competition in the United States will result in a continuation and acceleration of the recent trend toward consolidation among domestic utilities and independent power producers and an increase in the trend toward disaggregation (or unbundling) of vertically integrated utilities into separate generation, transmission and distribution businesses. The United Kingdom The electricity industry in the United Kingdom has seen the ongoing privatization of electric supply and distribution since 1990. The Electricity Act of 1989 established an industry structure that permitted this phased-in privatization to occur. Since that time, in England and Wales, electricity is produced by generators, the largest of which are National Power, PowerGen and British Energy. Electricity is transmitted through the national grid transmission system by The National Grid Company plc ("NGC") and distributed to customers by the twelve regional electric companies ("RECs") in their respective authorized areas. Most customers currently are supplied with electricity by their local REC, although there are other suppliers holding second tier supply licenses, including other generators and RECs, who can compete to supply larger customers in that REC's authorized area. Under the current licensing regime, during 1998 it is expected that all customers, including those who are currently customers with a maximum demand of not more than 100kW ("Franchise Supply Customers"), will become free to choose their electricity supplier. Virtually all electricity generated in England and Wales is sold by generators and bought by suppliers through the Pool. A generator that is a Pool member and also a licensed supplier must nevertheless sell all the electricity it generates into the Pool, and purchase all the electricity that it supplies from the Pool. Because Pool prices fluctuate, generators and suppliers may enter into bilateral arrangements, such as contracts for differences ("CFDs"), to provide a degree of protection against such fluctuations. Distribution. Each of the RECs is required to offer terms for connection to its distribution system to any person, and for use of its distribution system to any authorized electricity operator. In providing use of its distribution system, a REC must not discriminate between its own supply business and that of any other authorized electricity operator, or between those of other authorized electricity operators; nor may its charges differ except where justified by differences in cost. Most revenue of the distribution business is controlled by a distribution price control formula. The Retail Price Index ("RPI") used in this formula reflects the average of the 12 month inflation rates recorded for the previous July to December period. The distribution price control formula also reflects an XD factor which is established by the Regulator following review and is set at 3% from April 1, 1997. This formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a REC is entitled to charge. The distribution price control formula permits RECs to receive additional revenues due to increased distribution of units and a predetermined increase in customer numbers. The price control does not seek to constrain the profits of a REC from year to year. It is a control on income which operates independently of the REC's costs. During the lifetime of the price control additional cost savings therefore contribute directly to profit. The distribution prices allowable under the current distribution price control formula are expected to be reviewed by the Regulator at the expiration of the formula's scheduled five-year duration, effective as of April 1, 2000. The formula may be further reviewed at other times in the discretion of the Regulator. With effect from April 1, 1998, domestic and smaller commercial customers' prices will be subject to a price cap which requires reductions of 4.2% (less inflation) compared to the prices prevailing in July 1997. A further reduction of 3% (less inflation) will be required on April 1, 1999. Supply. Subject to minor exceptions, all electricity customers in the United Kingdom must be supplied by a licensed supplier. Licensed suppliers purchase electricity and make use of the transmission and distribution networks to achieve delivery to customers' premises. There are two types of licensed suppliers: PES (or "first tier") suppliers and second tier suppliers. PESs are the RECs, Scottish Power and Hydro-Electric, each supplying in its respective authorized area. Second tier suppliers include National Power, PowerGen, British Energy, Scottish Power, Hydro-Electric and other PESs supplying outside their respective authorized areas. There are also a number of independent second tier suppliers. At present, a Franchise Supply Customer can only buy electricity from the PES authorized to supply the relevant authorized area. Franchise Supply Customers typically include domestic and small commercial and small industrial customers. Non-Franchise Supply Customers with demand over 100kW are not limited to buying electricity from the local PES and can choose to buy from a second tier supplier. Such customers are typically larger commercial, agricultural and industrial electricity users. Second tier suppliers compete with one another and with the local PES to supply customers in this competitive (or "non-franchise") sector of the market. The supply of electricity to all Franchise Supply Customers is subject to price control until March 31, 1998. The maximum permitted average charge per unit supplied (in pence per kilowatt hour) is controlled by a formula whereby certain costs are passed through in full (the Y term) to customers. The permitted income per unit supplied in respect of the supply business' own costs and margin increases (or decreases) each year by RPI--X (the "Supply Price Control Formula") where X is currently 2%. RPI reflects the average of the 12 month inflation rates recorded for the previous July to December period. The X factor is established by the Regulator during the price control review. The Y term is a pass-through of certain costs which are either largely outside the control of the REC or have been regulated elsewhere. It thus covers the REC's electricity purchase costs, including both direct Pool purchase costs and costs of hedging, transmission charges made by NGC, distribution charges made by its own and other REC distribution businesses and other levies which are attributable to Franchise Supply Customers. Associated with the deregulation occurring in 1998, a different form of price cap will be established for some of the current Franchise Supply Customers. The Pool. The Pool was established at the time of privatization for bulk trading of electricity in England and Wales between generators and suppliers. The Pool reflects two principal characteristics of the physical generation and supply of electricity from a particular generator to a particular supplier. First, it is not possible to trace electricity from a particular generator to a particular supplier. Second, it is not practicable to store electricity in significant quantities, creating the need for a constant matching of supply and demand. Subject to certain exceptions, all electricity generated in England and Wales must be sold and purchased through the Pool. All licensed generators and suppliers must become and remain signatories to the Pooling and Settlement Agreement, which governs the constitution and operation of the Pool and the calculation of payments due to and from generators and suppliers. The Pool also provides centralized settlement of accounts and clearing. The Pool does not itself buy or sell electricity. Prices for electricity are set by the Pool daily for each one-half hour of the following day based on the bids of the generators and a complex set of calculations matching supply and demand and taking account of system stability, security and other costs. A settlement system is used to calculate prices and to process metered, operational and other data and to carry out the other procedures necessary to calculate the payments due under the Pool trading arrangements. The settlement system is administered on a day-to-day basis by Energy Settlements and Information Services, Limited, a subsidiary of NGC, as settlement system administrator. The price control regulations which govern the authorized area supply market permit the pass-through to customers of certain permitted costs, which include the cost of arrangements such as CFDs to hedge against Pool price volatility. Generally, CFDs are contracts between generators and suppliers that have the effect of fixing the price of electricity for a contracted quantity of electricity over a specific time period. Differences between the actual price set by the Pool and the agreed prices give rise to difference payments between the parties to the particular CFD. At any time, Northern's forecast franchise supply market demand is substantially hedged through various types of agreements including CFDs. The Philippines According to the 1995 Power Development Program (1995-2005) (the "PDP") of the National Power Corporation of the Philippines ("NPC"), industrial growth, a rising standard of living and an expanding power distribution network have resulted in increased demand for electrical power in the Philippines by an average of 6% per year since 1987. NPC has projected that over the next 10 years the need for additional generating capacity in the Philippines will exceed 14,000 MW. Demand growth is expected to increase as industrialization continues, living standards rise and the power distribution network expands. According to the PDP, for the period 1996 to 2000, projected peak power demand is estimated to increase by approximately 60%, 64%, and 90% for Luzon, the Visayas, and Mindanao, respectively. For the country, total projected peak power is estimated to increase by 3,826 MW or 65% from 1996 to 2000. For the period 2001 to 2005, projected peak power is estimated to increase by approximately 50%, 43%, and 59% for Luzon, the Visayas, and Mindanao, respectively. For the country, total projected peak power is estimated to increase by 5,459 MW or 51% from 2001 to 2005. The PDP proposes to meet this demand by increasing the participation of the private sector in power generation to 32% in 2000, and to 61% in 2005, through direct sales to utilities by independent power producers and the use of build-own-operate-transfer projects. NPC also will offer existing power plants to the private sector through rehabilitate-operate-maintain and rehabilitate-operate-lease arrangements. Geothermal power has been identified as a preferred alternative by the Government of the Philippines due to the domestic availability and the minimal environmental effects of geothermal power in comparison to other forms of power production. The Company's Distribution and Supply Business Northern Electric Distribution Limited ("Northern Distribution"), a subsidiary of Northern, receives electricity from the national grid transmission system and distributes electricity to each customer's premises using Northern's network of transformers, switchgear and cables. Substantially all of the customers in Northern's authorized area are connected to Northern's network and can only be supplied with electricity through the Northern distribution system, regardless of whether the electricity is supplied by Northern's supply business or by other suppliers, thus providing Northern with distribution volume that is stable from year to year. Northern Distribution serves approximately 1.5 million customers in Northern's area and charges its customers access fees for the use of the distribution system. At December 31, 1997, Northern's electricity distribution network (excluding service connections to consumers) included approximately 17,000 kilometers of overhead lines and approximately 26,000 kilometers of underground cables. Substantially all substations are owned in freehold, and most of the balance are held on leases which will not expire within 10 years. In addition to the circuits referred to above, Northern's distribution facilities also include approximately 24,000 transformers and approximately 23,000 substations. Northern Electric Supply Limited ("Northern Supply") focuses on Northern's supply business and is responsible for marketing, tariff setting, contracts and customer service in connection with the supply of both electricity and gas. Northern's supply business involves the bulk purchase of electricity, primarily from the Pool, and subsequent sale to individual customers. Each of the RECs is currently the exclusive supplier of electricity in its authorized area to Franchise Supply Customers. The formula described above controls the income that the supply business may receive from Franchise Supply Customers and therefore the profits that can be derived from the supply of electricity to Franchise Supply Customers. Supplies to other customers are not regulated since the Director General of Electricity Supply (the "Regulator") believes that the market in excess of 100kW is sufficiently competitive not to require this. The current regulations that permit each of the RECs to be the exclusive supplier in each of their authorized areas are expected to expire during 1998. Under the terms of its public electricity supply ("PES") or "first tier" license, Northern currently holds the right to supply approximately 1.5 million Franchise Supply Customers within Northern's authorized area. In addition to competing for non-Franchise Supply Customers in its authorized area, Northern holds a second tier license to compete with the RECs and other suppliers to provide electricity to non-Franchise Supply Customers outside its authorized area. Northern is one of the largest suppliers in the competitive and open electricity market in the United Kingdom and supplies customers in all 15 PES areas in Great Britain and Northern Ireland. Northern supplies substantially more sites than it had previously supplied prior to the beginning of open competition in the supply business in the United Kingdom. Northern Supply also competes to supply gas inside and outside its authorized area. Over the last six months of 1997, Northern expanded its supply customer base by 20% by attracting nearly 300,000 new gas customers in part through the Dual Fuel marketing program. Northern Utility Services Limited ("Northern Utility") is an engineering company whose role is to adapt, maintain and restore the distribution network of Northern Distribution and to sell related services to third parties. Northern Utility has been able to make significant cost reductions for Northern during the past year by working with suppliers in order to improve core processes, close selected depot locations, increase staff productivity and reduce material and plant costs. Northern Utility has pioneered techniques using innovative diagnostic testing equipment which reduces the need for intrusive maintenance. The equipment can identify some of the causes of potential systems failures before breakdown and subsequent loss of supply occurs. Also, the continued development in the use of trenchless technology has brought both financial and environmental benefits to Northern and its customers. While Northern Utility's largest customer is Northern Distribution, it currently sells an average of approximately 14% of its services to third parties. Northern Utility is Northern's largest employer. Northern Electric Retail Limited ("Northern Retail"), a subsidiary of Northern, sells electrical and gas appliances and provides account collection and customer services for Northern's other businesses. Northern Metering Services Limited ("Northern Metering"), a subsidiary of Northern, provides meter supply, installation, refurbishment and certification services as well as meter operator and data collection services. Northern Metering has developed an energy profiling system which helps businesses reduce costs through the more efficient use of all fuels, not just electricity. The Company's Power Generation Project Portfolio The Company currently has net ownership interests of an aggregate of (i) 1,689 net MW in 21 projects in operation representing an aggregate net capacity of 3,510 net MW of electric generating capacity, (ii) 327 net MW in four projects under construction representing an aggregate net capacity of 415 net MW of electric generating capacity and (iii) 945 net MW in eight projects in advanced development stages with signed power sales agreements or under award representing an aggregate net capacity of 1,184 net MW of electric generating capacity. The following tables set out certain information concerning various Company projects in operation, under construction and in development pursuant to signed power sales agreements or awarded mandates. Power Generation Projects Projects in Operation PROJECT(6) FUEL FACILITY NET LOCATION PROJECT CONTRACT CONTRACT POWER SOURCE NET OWNERSHIP COMMERCIAL EXPIRATION TYPE PURCHASE CAPACITY INTEREST OPERATION (IN MW) (IN MW) DATE(9) (1)(2)(3) United States Navy I Geo 88 41 China 8/1987 8/2011 SO4 Edison Lake,CA BLM Geo 88 42 China 3/1989 3/2019 SO4 Edison Lake,CA Navy II Geo 88 44 China 1/1990 1/2010 SO4 Edison Lake,CA Vulcan Geo 34 34 Imperial 2/1986 2/2016 SO4 Edison Valley,CA Hoch (Del Geo 38 38 Imperial 1/1989 12/2018 SO4 Edison Ranch) Valley,CA Elmore Geo 38 38 Imperial 1/1989 12/2018 SO4 Edison Valley,CA Leathers Geo 38 38 Imperial 1/1990 12/2019 SO4 Edison Valley,CA Salton Geo 10 10 Imperial 7/1987 6/2017 Negot. Edison Sea I Valley,CA Salton Geo 20 20 Imperial 4/1990 4/2020 SO4 Edison Sea II Valley,CA Salton Geo 50 50 Imperial 2/1989 2/2019 SO4 Edison Sea III Valley,CA Salton Geo 40 40 Imperial 6/1996 9/2017 Negot. Edison Sea IV Valley,CA Saranac Gas 240 180 Plattsburg 6/1994 6/2009 Negot. NYSEG NY Power Gas 200 200 Big Spring,6/1988 9/2003 Negot. TUEC Resources TX NorCon Gas 80 64 North East,12/1992 12/2017 Negot. NIMO PA Yuma Gas 50 50 Yuma,AZ 5/1994 5/2024 Negot. SDG&E Roosevelt Geo 23 17 Milford,UT 5/1984 1/2021 Gathered UP&L Hot Springs (5) Steam Desert Geo 10 10 Sparks,NV 1985 Not Negot. SPPC Peak Fixed United Kingdom Teesside Gas 1,875 289 Wilton, 1993 2008 Negot. Various Power England Limited Philippines Upper Geo 119 119 Leyte, 1996 CO+10 Build, PNOC-EDC Mahiao Philippines Own (GOP)(8) (7) Transfer Malitbog Geo 216 216 Leyte, 1996-97 CO+10 Build, PNOC-EDC (7) Philippines Own (GOP)(8) Transfer Mahanagdong Geo 165 149 Leyte, 1997 CO+10 Build, PNOC-EDC (7) Philippines Own (GOP)(8) Transfer Total in 3,510 1,689 Operation (1)Excludes royalty income received by Magma from the Mammoth and East Mesa plants. (2)Actual MW may vary depending on operating and reservoir conditions and plant design. Facility Net Capacity (in MW) for projects in operation represents gross electric output of the facility less the parasitic load. Parasitic load is electrical output used by the facility and not made available for sale to utilities or other outside purchasers. Net MW owned indicates current ownership, but, in some cases, does not reflect the current allocation of partnership distributions. (3)With respect to the Vulcan, Hoch (Del Ranch), Elmore, Leathers, Salton Sea I, Salton Sea II, Salton Sea III and Salton Sea IV Projects, this represents nominal nameplate. (4)Southern California Edison Company ("Edison"); San Diego Gas & Electric Company ("SDG&E"); Utah Power & Light Company ("UP&L"); Sierra Pacific Power Company ("SPPC") ; New York State Electric & Gas Corporation ("NYSEG"); Texas Utilities Electric Company ("TUEC"); and Niagara Mohawk Power Corporation ("NIMO"); PNOC-Energy Development Corporation ("PNOC- EDC"); Government of Philippines ("GOP"). (5)Represents the electrical equivalent of delivered steam. (6)The Company operates all such projects other than Teesside Power Limited. (7)Construction of these facilities has been completed and, accordingly, these facilities have been "deemed complete" by PNOC-EDC and are currently receiving the full capacity payments under the "take or pay" provisions of their contracts with PNOC-EDC, pending NPC making available to these projects a full capacity transmission line. (8)Government of Philippines undertaking supports PNOC-EDC's obligations. (9)Commercial Operation ("CO") plus number of years. Projects in Construction PROJECT FUEL FACILITY NET LOCATION CONTRACT CONTRACT POWER POLITICAL SOURCE NET OWNER EXPIRATION TYPE PURCHASER RISK CAPACITY INTEREST (1) (2) INSURANCE (IN MW) (IN MW) AND (5) PRIMARILY US$ CONTRACT United Kingdom Viking Gas 50 25 Seal CO+10 Negot Northern No Sands on Teesside, England Philippines Casecnan Hydro 150 105 Luzon,the CO+20 Build, NIA Yes (4) Philippines Own (GOP)(3) Transfer Indonesia Dieng Geo 55 52 Central CO+30 Build, PLN Yes Unit Java, Own, (GOI) I(6) Indonesia Transfer Dieng Geo 80 75 Central CO+30 Build, PLN Yes Unit Java, Own, (GOI) II(6) Indonesia Transfer Patuha Geo 80 70 Western CO+30 Build, PLN Yes Unit Java, Own, (GOI) I(6) Indonesia Transfer Total in 415 327 Construction (1)Commercial Operation ("CO") plus number of years. (2)Government of the Philippines ("GOP"); P.T. PLN (Persero) ("PLN"); Government of Indonesia ("GOI"); and Philippine National Irrigation Administration ("NIA"), Northern Electric plc ("Northern"). (3)Government of the Philippines undertaking supports NIA's obligations. (4)NIA also purchases water from this facility. (5)Actual MW may vary depending on operating and reservoir conditions and final plant design. Significant contingencies exist in respect of awards, including without limitation, the need to obtain financing, permits and licenses, and the completion of construction. (6)See discussion of uncertainties caused by recent actions of Government of Indonesia below. Projects with Signed Power Sales Contracts or Awarded Development Rights PROJECT(S) FUEL FACILITY NET LOCATION CONTRACT CONTRACT POWER SOURCE NET OWNERSHIP EXPIRATION TYPE PURCHASER CAPACITY INTEREST (2) (3) (IN MW) (IN MW) (1) United States Salton Sea Geo 49 49 Imperial TBD TBD TBD Sea Mineral Valley, CA Extraction Telephone Geo 30 30 Siskiyou CO+20 Negot. BPA Flat(7) County, CA United Kingdom Exeter Gas 50 25 England CO+10 Negot. Northern Philippines Alto Peak Geo 70 70 Leyte,the CO+10 Build, PNOC-EDC Philippines Own, (GOP)(4) Transfer Indonesia Dieng Geo 265 249 Central Java, CO+30 Build, PLN Phase II Indonesia Own, (GOI) (6) Transfer Patuha Geo 320 282 Western Java, CO+30 Build, PLN Phase II Indonesia Own, (GOI) Transfer Bali(6) Geo 400 240 Bali, CO+30 Build, PLN Indonesia Own, (GOI) Transfer Total 1,184 945 Contracted/Awarded (1)Actual MW may vary depending on operating and reservoir conditions and plant design. Facility Net Capacity (in MW) represents facility gross capacity (in MW) less parasitic load. Parasitic load is electrical output used by the facility and not made available for sale to utilities or other outside purchasers. (2)Commercial Operation ("CO") plus number of years. (3)PNOC-Energy Development Corporation ("PNOC-EDC"), Government of the Philippines ("GOP"); P.T. PLN (Persero)("PLN"); Government of Indonesia ("GOI"); Northern Electric plc ("Northern"); Bonneville Power Authority ("BPA") (4)Government of the Philippines undertaking supports PNOC-EDC's obligations. (5)Significant contingencies exist in respect of awards, including without limitation, the need to obtain financing, permits and licenses, and the completion of construction. (6)See discussion of uncertainties caused by recent actions by the Government of Indonesia below. (7)The Newberry project has been moved to Telephone Flat to take advantage of better reservoir conditions at the latter location. A settlement agreement has been executed with BPA to recognize the move, subject to completion of certain activities including an environmental impact statement. PROJECTS IN OPERATION United States Operations The Coso Project In 1979, the Company entered into a 30-year contract (the "Navy Contract") with the United States Department of the Navy (the "Navy") to develop geothermal power facilities located on approximately 5,000 acres of the Naval Air Weapons Station at China Lake, California (150 miles northeast of Los Angeles). In 1985, the Company entered into a 30-year lease (the "BLM Lease") with the United States Bureau of Land Management ("BLM") for approximately 19,000 acres of land adjacent to the land covered by the Navy Contract. The Navy Contract and the BLM Lease provide for certain royalty payments as a percentage of gross revenue and certain other formulas. The Company formed three joint ventures (the "Coso Joint Ventures") with one primary joint venture partner to develop and construct the three facilities which comprise the Navy I project (the "Navy I Project"), the BLM project (the "BLM Project") and the Navy II project (the "Navy II Project") (collectively the "Coso Project"). The Coso Joint Ventures are as follows: (i) Coso Finance Partners, which owns the Navy I Project (the "Navy I Partnership"), (ii) Coso Energy Developers, which owns the BLM Project (the "BLM Partnership") and (iii) Coso Power Developers, which owns the Navy II Project (the "Navy II Partnership"). The Company holds ownership interests of 46.4%, 48% and 50% in the Navy I Partnership, the BLM Partnership, and the Navy II Partnership, respectively. The Company consolidates its respective share of the operating results of the Coso Joint Ventures into its financial statements. Each of the Coso Joint Ventures is managed by a management committee which consists of two representatives of the Company and two representatives of the Company's partners. The Company is the managing partner of each of the Coso Partnerships and operates the Coso Project, for which it receives fees from the Coso Joint Ventures. The Coso Project sells all electricity generated by the respective plants pursuant to three long-term SO4 Agreements between the Navy I Partnership, the BLM Partnership, and the Navy II Partnership, respectively, and Edison. These SO4 Agreements provide for capacity payments, capacity bonus payments and energy payments. Edison makes fixed annual capacity payments to the Coso Joint Ventures and, to the extent that capacity factors exceed certain benchmarks, is required to make capacity bonus payments. The price for capacity and capacity bonus payments is fixed for the life of the SO4 Agreements. Energy is sold at increasing fixed rates for the first ten years after firm operation and thereafter at Edison's Avoided Cost of Energy. The fixed price periods of the SO4 Agreements extend until at least August 1997, March 1999 and January 2000 for each of the units operated by the Navy I, BLM and Navy II Partnerships, respectively. For the year ended December 31, 1997 and 1996 Edison's average Avoided Cost of Energy was 3.3 cents and 2.5 cents, respectively, per kWh which is substantially below the contract energy prices earned for the year ended December 31, 1997. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year. The Company cannot predict the likely level of Avoided Cost of Energy prices under the SO4 Agreements and the modified SO4 Agreements at the expiration of the scheduled payment periods. The revenues generated by each of the projects operating under SO4 Agreements could decline significantly after the expiration of the respective scheduled payment periods. On June 9, 1997, Edison filed a complaint alleging breach of the power purchase agreements ("SO4 Agreements") between Edison and the Coso Joint Ventures as a result of alleged improper venting of certain noncondensible gases at the Coso geothermal energy project. In the complaint, Edison seeks unspecified damages, including the refund of certain amounts previously paid under the SO4 Agreements, and termination of the SO4 Agreements. In September 1997, the Coso Joint Ventures and the Company filed a cross-complaint against Edison and its affiliates, The Mission Group and Mission Power Engineering Company alleging, among other things, that Edison's lawsuit violates the 1993 settlement agreement which settled certain litigation arising from the construction of certain units at the Coso geothermal project by Edison affiliates. In addition, the Coso Joint Ventures filed a separate complaint against Edison alleging breach of the SO4 Agreements, unfair business practices, slander and various other tort and contract claims. The actions were effectively consolidated in December 1997. As a result of certain procedural actions by the parties and a November court order, Edison filed an amended complaint on December 16, 1997 and the Coso Joint Ventures amended their cross-complaint. The litigation is in its early procedural stages and the pleadings have not been settled. The Coso Joint Ventures believe that their claims and defenses are meritorious and that they will prevail if the matter is ultimately heard on its merits. The Coso Joint Ventures intend to vigorously defend this action and prosecute all available counterclaims against Edison. Navy I Project. The geothermal resource for the Navy I Project currently is produced from approximately 35 wells. The Navy I Project consists of three turbine generators, each with approximately 32 gross MW of electrical generating capacity. BLM Project. The BLM Project's geothermal resource currently is produced from approximately 24 wells. The BLM Project consists of three turbine generators. Two of these turbine generators are located at the BLM East site in a dual flash system, and one is located at the BLM West site in a single flash system, each with an electrical generating capacity of 32 gross MW. Navy II Project. The geothermal resource for the Navy II Project currently is produced from approximately 23 wells. The Navy II Project consists of three individual turbine generators, each with approximately 32 gross MW of electrical generating capacity. Imperial Valley Project The Company currently operates eight geothermal plants in the Imperial Valley in California (the "Imperial Valley Project"). Four of these Imperial Valley Project plants (the "Partnership Projects") were developed by Magma which originally owned a 50% interest. On April 17, 1996, the Company completed the Partnership Interest Acquisition pursuant to which the Company acquired the remaining 50% interests in each of the Partnership Projects for $70 million. The Partnership Projects consist of the Vulcan, Hoch (Del Ranch), Elmore and Leathers projects (the "Vulcan Project," the "Hoch (Del Ranch) Project," the "Elmore Project" and the "Leathers Project," respectively). The remaining four operating Imperial Valley Project plants (the "Salton Sea Projects") are wholly owned by subsidiaries of Magma. Three of these plants were purchased on March 31, 1993 from Union Oil Company of California. These geothermal power plants consist of the Salton Sea I project (the "Salton Sea I Project"), the Salton Sea II project (the "Salton Sea II Project") and the Salton Sea III project (the "Salton Sea III Project"). The fourth plant, the Salton Sea IV project (the "Salton Sea IV Project"), commenced commercial operations in 1996. Vulcan. The Vulcan Project sells electricity to Edison under a 30- year SO4 Agreement that commenced on February 10, 1986. The Vulcan Project has a contract capacity and contract nameplate of 29.5 MW and 34 MW, respectively. Under the SO4 Agreement, Edison is obligated to pay the Vulcan Project a capacity payment, a capacity bonus payment and an energy payment. The price for contract capacity payments is fixed for the life of such SO4 Agreement. The as-available capacity price is based on a payment schedule as approved by the CPUC from time to time. The contract energy payment increased each year for the first ten years, which period expired on February 9, 1996. Thereafter, the energy payments are based on Edison's Avoided Cost of Energy. Hoch (Del Ranch). The Hoch (Del Ranch) Project sells electricity to Edison under a 30-year SO4 Agreement that commenced on January 2, 1989. The contract capacity and contract nameplate are 34 MW and 38 MW, respectively. The provisions of such SO4 Agreement are substantially the same as the SO4 Agreement with respect to the Vulcan Project. The price for contract capacity payments is fixed for the life of the SO4 Agreement. The fixed price period for energy payments per kWh expires on January 1, 1999. After January 1, 1999, the energy payments will be based on Edison's Avoided Cost. Elmore. The Elmore Project sells electricity to Edison under a 30- year SO4 Agreement that commenced on January 1, 1989. The contract capacity and contract nameplate are 34 MW and 38 MW, respectively. The provisions of such SO4 Agreement are substantially the same as the SO4 Agreement with respect to the Vulcan Project. The price for contract capacity payments is fixed for the life of SO4 Agreement. The fixed price period for energy payments per kWh expires on December 31, 1998. After December 31, 1998, the energy payments will be based on Edison's Avoided Cost of Energy. Leathers. The Leathers Project sells electricity to Edison pursuant to a 30-year SO4 Agreement that commenced on January 1, 1990. The contract capacity and contract nameplate are 34 MW and 38 MW, respectively. The provisions of such SO4 Agreement are substantially the same as the SO4 Agreement with respect to the Vulcan Project. The price for contract capacity payments is fixed for the life of SO4 Agreement which expires on December 31, 1999. Thereafter, the energy payments will be based on Edison's Avoided Cost of Energy. Salton Sea I Project. The Salton Sea I Project sells electricity to Edison pursuant to a 30-year negotiated power purchase agreement, as amended (the "Salton Sea I PPA"), which provides capacity and energy payments. The contract capacity and contract nameplate are each 10 MW. The capacity payment is based on the firm capacity price which is currently $132.58kW-year. The contract capacity payment adjusts quarterly based on a basket of energy indices for the term of the Salton Sea I PPA. The energy payment is calculated using a Base Price (defined as the initial value of the energy payment (4.701 center per kWh for the second quarter of 1992)), which is subject to quarterly adjustments based on a basket of indices. The time period weighted average energy payment for Salton Sea I was 5.3 cents per kWh during 1997. As the Salton Sea I PPA is not an SO4 Agreement, the energy payments do not revert to Edison's Avoided Cost of Energy. Salton Sea II Project. The Salton Sea II Project sells electricity to Edison pursuant to a 30-year modified SO4 Agreement that commenced on April 5, 1990. The contract capacity and contract nameplate are 15 MW (16.5 MW during on-peak periods) and 20 MW, respectively,. The contract requires Edison to make capacity payments, capacity bonus payments and energy payments. The price for contract capacity and contract capacity bonus payments is fixed for the life of the modified SO4 Agreement. The energy payments for the first ten-year period, which period expires on April 4, 2000, are levelized at a time period weighted average of 10.6 cents per kWh. Thereafter, the monthly energy payments will be Edison's Avoided Cost of Energy. Edison is entitled to receive, at no cost, 5% of all energy delivered in excess of 80% of contract capacity through September 30, 2004. Salton Sea III Project. The Salton Sea III Project sells electricity to Edison pursuant to a 30-year modified SO4 Agreement that commenced on February 13, 1989. The contract capacity is 47.5 MW and the contract nameplate is 49.8 MW. The SO4 Agreement requires Edison to make capacity payments, capacity bonus payments and energy payments for the life of the SO4 Agreement. The price for contract capacity payments is fixed at $175/kW per year. The energy payments for the first ten-year period, which period expires on February 12, 1999, are levelized at a time period weighted average of 9.8 cents per kWh. Thereafter, the monthly energy payments will be Edison's Avoided Cost of Energy. The Salton Sea IV Project sells electricity to Edison pursuant to a modified SO4 agreement which provides for contract capacity payments on 34 MW of capacity at two different rates based on the respective contract capacities deemed attributable to the original Salton Sea PPA option (20 MW) and to the original Fish Lake PPA (14 MW). The capacity payment price for the 20 MW portion adjusts quarterly based upon specified indices and the capacity payment price for the 14 MW portion is a fixed levelized rate. The energy payment (for deliveries up to a rate of 39.6 MW) is at a fixed price for 55.6% of the total energy delivered by Salton Sea IV and is based on an energy payment schedule for 44.4% of the total energy delivered by Salton Sea IV. The contract has a 30-year term but Edison is not required to purchase the 20 MW of capacity and energy originally attributable to the Salton Sea I PPA option after September 30, 2017, the original termination date of the Salton Sea I PPA. U.S. Gas Projects Yuma Project. The Yuma Project is a 50 net MW natural gas-fired cogeneration project in Yuma, Arizona providing 50 MW of electricity to San Diego Gas & Electric Company ("SDG&E") under an existing 30-year power purchase contract. The energy is sold at SDG&E's Avoided Cost of Energy and the capacity is sold to SDG&E at a fixed price for the life of the power purchase contract. The power is wheeled to SDG&E over transmission lines constructed and owned by Arizona Public Service Company ("APS"). An agreement for interconnection and a firm transmission service agreement have been executed between APS and the Yuma Project entity and have been accepted for filing by the FERC. The Yuma Project commenced commercial operation in May 1994. The project entity has executed steam sales contracts with an adjacent industrial entity to act as its thermal host. Since the industrial entity has the right under its agreement to terminate the agreement upon one year's notice if a change in its technology eliminates its need for steam, and in any case to terminate the agreement at any time upon three years notice, there can be no assurance that the Yuma Project will maintain its status as a QF. However, if the industrial entity terminates the agreement, the Company anticipates that it will be able to locate an alternative thermal host in order to maintain its status as a QF. A natural gas supply and transportation agreement has been executed with Southwest Gas Corporation, terminable under certain circumstances by the Company and Southwest Gas Corporation. The Yuma Project is unleveraged other than intercompany debt. Saranac Project. Saranac is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York, which began commercial operation in June 1994. Saranac has entered into a 15-year power purchase agreement (the "Saranac PPA") with NYSEG. Saranac is a QF and has entered into 15-year steam purchase agreements (the "Saranac Steam Purchase Agreements") with Georgia-Pacific Corporation and Tenneco Packaging, Inc. Saranac has a 15-year natural gas supply contract (the "Saranac Gas Supply Agreement") with Shell Canada Limited ("Shell Canada") to supply 100% of Saranac's fuel requirements. Shell Canada is responsible for production and delivery of natural gas to the U.S.-Canadian border; the gas is then transported by the North Country Gas Pipeline Corporation ("NCGP") the remaining 22 miles to the plant. NCGP is a wholly-owned subsidiary of Saranac Power Partners, L.P. (the "Saranac Partnership"), which also owns Saranac. NCGP also transports gas for NYSEG and Georgia-Pacific. Each of the Saranac PPA, the Saranac Steam Purchase Agreements and the Saranac Gas Supply Agreement contains rates that are fixed for the respective contract terms. Revenues escalate at a higher rate than fuel costs. The Saranac Partnership is owned by subsidiaries of the Company, Tomen Corporation ("Tomen"), and General Electric Capital Corporation. On February 14, 1995, NYSEG filed with the FERC a Petition for a Declaratory Order, Complaint, and Request for Modification of Rates in Power Purchase Agreements Imposed Pursuant to the Public Utility Regulatory Policies Act of 1978 ("Petition") seeking FERC (i) to declare that the rates NYSEG pays under the Saranac PPA, which was approved by the New York Public Service Commission (the "PSC"), were in excess of the level permitted under PURPA and (ii) to authorize the PSC to reform the Saranac PPA. On March 14, 1995, the Saranac Partnership intervened in opposition to the Petition asserting, Inter alia, that the Saranac PPA fully complied with PURPA, that NYSEG's action was untimely and that the FERC lacked authority to modify the Saranac PPA. On March 15, 1995, the Company intervened also in opposition to the Petition and asserted similar arguments. On April 12, 1995, the FERC by a unanimous (5-0) decision issued an order denying the various forms of relief requested by NYSEG and finding that the rates required under the Saranac PPA were consistent with PURPA and the FERC's regulations. On May 11, 1995, NYSEG requested rehearing of the order and, by order issued July 19, 1995, the FERC unanimously (5-0) denied NYSEG's request. On June 14, 1995, NYSEG petitioned the United States Court of Appeals for the District of Columbia Circuit (the "Court of Appeals") for review of FERC's April 12, 1995 order. FERC moved to dismiss NYSEG's petition for review on July 28, 1995. On October 30, 1996, all parties filed final briefs and the Court of Appeals heard oral arguments on December 2, 1996. On July 11, 1997, the Court of Appeals dismissed NYSEG's appeal from FERC's denial of the petition on jurisdictional grounds. On August 7, 1997, NYSEG filed a complaint in the U.S. District Court for the Northern District of New York against the FERC, the PSC (and the Chairman, Deputy Chairman and the Commissioners of the PSC as individuals in their official capacity), the Saranac Partnership and Lockport Energy Associates, L.P. ("Lockport") concerning the power purchase agreements that NYSEG entered into with Saranac Partners and Lockport. NYSEG's suit asserts that the PSC and the FERC improperly implemented PURPA in authorizing the pricing terms that NYSEG, the Saranac Partnership and Lockport agreed to in those contracts. The action raises similar legal arguments to those rejected by the FERC in its April and July 1995 orders. NYSEG in addition asks for retroactive reformation of the contracts as of the date of commercial operation and seeks a refund of $281 million from the Saranac Partnership. Saranac and other parties have filed motions to dismiss and oral arguments on those motions were heard on March 2, 1998. Saranac believes that NYSEG's claims are without merit for the same reasons described in the FERC's orders. Power Resources Project. Power Resources is a 200 net MW natural gas-fired cogeneration project located near Big Spring, Texas, which has a 15-year power purchase agreement (the "Power Resources PPA") with Texas Utilities Electric Company. Power Resources began commercial operation in June 1988. Power Resources is a QF and has entered into a 15-year steam purchase agreement (the "Power Resources Steam Purchase Agreement") with Fina Oil and Chemical Company ("Fina"), a subsidiary of Petrofina S.A. of Belgium. Power Resources has entered into an agreement (the "FSGC Gas Supply Agreement") with Falcon Seaboard Gas Company ("FSGC") for Power Resources' fuel requirements through December 2003. FSGC has fulfilled its commitments to Power Resources, Inc. ("PRI") to date using a combination of spot purchases plus short-term contracts. In June 1995, FSGC and Louis Dreyfus Natural Gas Corp. ("Dreyfus") executed an eight- year natural gas supply agreement (the "FSGC-Dreyfus Gas Supply Agreement"), with which FSGC will fulfill its supply commitment to PRI from October 1995 to the end of the term of the Power Resources PPA. Accordingly, through the FSGC-Dreyfus Gas Supply Agreement, all gas requirements have been contracted for through the end of the Power Resources PPA. Each of the Power Resources PPA, the Power Resources Steam Purchase Agreement and the FSGC Gas Supply Agreement contains rates that are fixed for the respective contract terms. Revenues escalate at a higher rate than fuel costs. NorCon Project. NorCon is an 80 net MW natural gas-fired cogeneration facility located in North East, Pennsylvania which began commercial operation in December 1992. NorCon has a 25-year power purchase agreement (the "NorCon PPA") with Niagara Mohawk Power Corporation ("NIMO"). NorCon is a QF and has entered into a 20-year steam purchase agreement (the "NorCon Thermal Energy Agreement") with Welch Foods Inc., a Cooperative ("Welch Foods"). NorCon has a 15-year natural gas supply contract (the "NorCon Gas Purchase Agreement") with Louis Dreyfus Gas Marketing Corp. to supply 100% of NorCon's fuel requirements. A twenty-year natural gas transportation agreement has been entered into with National Fuel Gas Supply Corporation ("National Fuel") to provide transportation to NorCon. Transportation costs are deducted from payments made pursuant to the NorCon Gas Purchase Agreement. The NorCon PPA has rates that are subject to a specified floor amount. The NorCon Thermal Energy Agreement contains rates that escalate at an inflation-based index, and the NorCon Gas Purchase Agreement's rates are fixed for the contract term. NorCon Power Partners, L.P. ("the "NorCon Partnership"), which owns NorCon, is owned by subsidiaries of the Company and Tomen. The NorCon project has had a number of on-going contractual disputes with NIMO which are unresolved and in August 1996 NIMO proposed a buyout of the NorCon PPA as part of a generic restructuring by NIMO of all of its QF contracts in an effort to restructure NIMO's purchased power obligations to meet the challenge of industry deregulation and avoid what NIMO alleges as the risk of a possible NIMO insolvency. The Company believes that any contractual restructuring or even a NIMO insolvency would not have a material adverse effect on its consolidated financial results of operations. Other U.S. Geothermal Operations Roosevelt Hot Springs. The Company operates and owns an approximately 70% indirect interest in a geothermal steam field which supplies geothermal steam to a 23 net MW power plant owned by Utah Power & Light Company ("UP&L") located on the Roosevelt Hot Springs property under a 30-year steam sales contract. The Company obtained approximately $20.3 million of cash under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by the steam field. The Company must make certain penalty payments to UP&L if the steam produced does not meet certain quantity and quality requirements. Desert Peak. The Company is the owner, and currently the operator, of a 10 net MW geothermal plant at Sparks, Nevada. The Desert Peak Project has been selling electricity to Sierra Pacific Power Company ("SPPC") on a spot market basis since its power sales contract with SPPC expired December 31, 1995. The Company recently executed an agreement pursuant to which the Desert Peak Project will be leased to a third party power producer and the Company will receive rental payments. Royalty Interests Mammoth. Magma receives royalty revenues from a 10 net MW and a 12 net MW contract nameplate geothermal power plant (the "First Mammoth Plant" and the "Second Mammoth Plant," respectively, and referred to herein, collectively, as the "Mammoth Plants") at Mammoth Lakes, California. Electricity from the Mammoth Plants is sold to Edison under two long-term power purchase agreements. The First Mammoth Plant and the Second Mammoth Plant began commercial operation in 1985 and 1991, respectively. Magma leases both property and geothermal resources to support the Mammoth Plants in return for certain base royalty and bonus royalty payments. For the First Mammoth Plant and the Second Mammoth Plant, the base royalty is 12.5% and 12%, respectively, of gross electricity sales revenues. The bonus royalty for the Mammoth Plants is 50% of the excess of annual gross electricity sales revenues over an annual revenue standard based on the Mammoth Plants operating at 85% of contract capacity. East Mesa. Magma also receives royalty revenues from a 37 net MW contract nameplate geothermal power plant (with two units) at East Mesa in Imperial Valley, California (the "East Mesa Project"). Electricity from the plant has been sold to Edison pursuant to two SO4 Agreements formerly held by Magma. The East Mesa Project participants have executed an agreement with Edison to terminate the SO4 Agreement. Pursuant to a Settlement Agreement, Magma consented to such termination. United Kingdom Operations and Construction In the United Kingdom, a Northern subsidiary, Northern Electric Generation Limited ("Northern Generation"), focuses on electricity generation, primarily through its ownership in Teesside (described herein). Northern Generation also operates a 5 MW diesel power generating plant located in Northallerton, England in which the Company has a 3 MW net ownership interest. Teesside. Teesside Power Limited ("Teesside") owns and operates an 1,875 net MW combined cycle gas-fired power plant at Wilton. Northern owns a 15.4% interest in Teesside, but does not operate the plant. Northern purchases 400 MW of electricity from Teesside under a long-term power purchase agreement. Viking. Viking Power Limited ("Viking") is a company owned 50% by Northern and 50% by Rolls-Royce Power Ventures. Viking is a project to construct a 50 net MW natural gas-fired power plant at Seal Sands on Teesside. The project will utilize an aero-derivative Rolls-Royce Trent Engine and it will be embedded on the Northern distribution network. Construction has commenced on the plant and the project is being managed by Northern and will be operated by Northern upon commercial operation. The Philippines Operations and Construction Upper Mahiao. The Upper Mahiao facility was "deemed complete" by PNOC-EDC as of June 17, 1996, meaning that construction of the facility was completed on time but the required full capacity transmission line was not completed and provided to CE Cebu Geothermal Power Company, Inc. ("CE Cebu"), a Philippine corporation that is 100% indirectly owned by the Company. During deemed completion, PNOC-EDC is required to pay all capacity fees under the take or pay provisions of the contract. PNOC-EDC is paying such capacity fees on a timely basis. Effective September 13, 1996, the "deemed completion" was modified, to allow delivery of up to 40 MW of power through a temporary transmission facility. This amendment allows for payment to CE Cebu of fees for energy delivered in addition to continuing the payment for the full capacity fee. A consortium of international banks provided the construction loans, supported by political risk insurance from the Ex-Im Bank. The construction loan is expected to be converted to a term loan promptly after NPC completes the full capacity transmission line. The transmission line is currently being tested and testing is expected to be completed in the second quarter of 1998. Under the terms of an energy conversion agreement, executed on September 6, 1993 (the "Upper Mahiao ECA"), CE Cebu will own and operate the Upper Mahiao Project during the ten-year cooperation period, after which ownership will be transferred to PNOC-EDC at no cost. The Upper Mahiao Project is located on land provided by PNOC-EDC at no cost. It takes geothermal steam and fluid, also provided by PNOC- EDC at no cost, and converts its thermal energy into electrical energy sold to PNOC-EDC on a "take-or-pay" basis. Specifically, PNOC-EDC is obligated to pay for 100% of the electric capacity that is nominated each year by CE Cebu, irrespective of whether PNOC-EDC is willing or able to accept delivery of such capacity. PNOC-EDC pays to CE Cebu a fee (the "Capacity Fee") based on the plant capacity nominated to PNOC- EDC in any year (which, at the plant's design capacity, is approximately 95% of total contract revenues) and a fee (the "Energy Fee") based on the electricity actually delivered to PNOC-EDC (approximately 5% of total contract revenues). Payments under the Upper Mahiao ECA are denominated in U.S. dollars, or computed in U.S. dollars and paid in Philippine pesos at the then-current exchange rate, except for the Energy Fee. Significant portions of the Capacity Fee and Energy Fee are indexed to U.S. and Philippine inflation rates, respectively. PNOC-EDC's payment requirements, and its other obligations under the Upper Mahiao ECA, are supported by the Government of the Philippines through a performance undertaking. The payment of the Capacity Fee is not excused if PNOC-EDC fails to deliver or remove the steam or fluids or fails to provide the transmission facilities, even if its failure was caused by a force majeure event. In addition, PNOC-EDC must continue to make Capacity Fee payments if there is a force majeure event (e.g., war, nationalization, etc.) that affects the operation of the Upper Mahiao Project and that is within the reasonable control of PNOC-EDC or the Government of the Philippines or any agency or authority thereof. PNOC-EDC is obligated to purchase CE Cebu's interest in the facility under certain circumstances, including (i) extended outages resulting from the failure of PNOC-EDC to provide the required geothermal fluid, (ii) certain material changes in policies or laws which adversely affect CE Cebu's interest in the project, (iii) transmission failure, (iv) failure of PNOC-EDC to make timely payments of amounts due under the Upper Mahiao ECA, (v) privatization of PNOC- EDC or NPC, and (vi) certain other events. The price will be the net present value (at a discount rate based on the last published Commercial Interest Reference Rate of the Organization for Economic Cooperation and Development) of the total remaining amount of Capacity Fees over the remaining term of the Upper Mahiao ECA. Mahanagdong. The Mahanagdong Project is a 165 net MW geothermal power project owned and operated by CE Luzon Geothermal Power Company, Inc. ("CE Luzon"), a Philippine corporation that is currently 100% indirectly owned by the Company. Up to a 10% financial interest in CE Luzon may be purchased at completion by another industrial company at the option of such company. The Mahanagdong Project was "deemed complete" by PNOC-EDC as of July 25, 1997. The Mahanagdong Project will sell 100% of its capacity on a similar basis as described above for the Upper Mahiao Project to PNOC-EDC, which will in turn sell the power to NPC for distribution to the island of Luzon. The project financing construction and term loan is being provided by OPIC, Ex-Im Bank and a consortium of international banks. Political risk insurance from Ex-Im Bank has been obtained for the commercial lenders. The construction loan is expected to be converted to a term loan promptly after NPC completes the full capacity transmission line which is currently expected to be in the second quarter of 1998. The terms of an energy conversion agreement, executed on September 18, 1993 (the "Mahanagdong ECA"), are substantially similar to those of the Upper Mahiao ECA. The Mahanagdong ECA provides for an approximately three-year construction period and a ten-year cooperation period. At the end of the cooperation period, the facility will be transferred to PNOC-EDC at no cost. All of PNOC-EDC's obligations under the Mahanagdong ECA are supported by the Government of the Philippines through a performance undertaking. The capacity fees are expected to be approximately 97% of total revenues at the design capacity levels and the energy fees are expected to be approximately 3% of such total revenues. Malitbog. The Malitbog Project is a 216 net MW geothermal project owned and operated by Visayas Geothermal Power Company ("VGPC"), a Philippine general partnership that is wholly owned, indirectly, by the Company. The three Units of the Malitbog facility were "deemed complete" by PNOC-EDC as of July 25, 1996 (for Unit I) and July 25, 1997 (for Units II and III). During deemed completion, PNOC-EDC is required to pay, and has been paying, all capacity fees under the take or pay provisions of the contract. VGPC is selling 100% of its capacity on substantially the same basis as described above for the Upper Mahiao Project to PNOC-EDC, which will in turn sell the power to NPC. A consortium of international banks and OPIC have provided the construction and term loan facilities. The construction loan is expected to be converted to a term loan promptly after NPC completes the full capacity transmission line. The transmission line is currently being tested and testing is expected to be completed in the second quarter of 1998. The Malitbog Project is located on land provided by PNOC-EDC at no cost. The electrical energy produced by the facility will be sold to PNOC-EDC on a take-or-pay basis. Specifically, PNOC-EDC is obligated to make payments (the "Capacity Payments") to VGPC based upon the available capacity of the Malitbog Project. The Capacity Payments equal approximately 100% of total revenues. The Capacity Payments will be payable so long as the Malitbog Project is available to produce electricity, even if the Malitbog Project is not operating due to scheduled maintenance, because PNOC-EDC fails to supply steam to the Malitbog Project as required or because NPC is unable (or unwilling) to accept delivery of electricity from the Malitbog Project. In addition, PNOC-EDC must continue to make the Capacity Payments if there is a force majeure event (e.g., war, nationalization, etc.) that affects the operation of the Malitbog Project and that is within the reasonable control of PNOC-EDC or the Government of the Philippines or any agency or authority thereof. A substantial majority of the Capacity Payments are required to be made by PNOC-EDC in dollars. The portion of Capacity Payments payable to PNOC-EDC in pesos is expected to vary over the term of the Malitbog ECA from 10% of VGPC's revenues in the early years of the Cooperation Period (as defined below) to 23% of VGPC's revenues at the end of the Cooperation Period. Payments made in pesos will generally be made to a peso-dominated account and will be used to pay peso-denominated operation and maintenance expenses with respect to the Malitbog Project and Philippine withholding taxes, if any, on the Malitbog Project's debt service. The Government of the Philippines has entered into a performance undertaking (the "Performance Undertaking"), which provides that all of PNOC-EDC's obligations pursuant to the Malitbog ECA carry the full faith and credit of, and are affirmed and guaranteed by, the Government of the Philippines. PNOC-EDC is obligated to purchase VGPC's interest in the facility under certain circumstances, including (i) certain material changes in policies or laws which adversely affect VGPC's interest in the project, (ii) any event of force majeure which delays performance by more than 90 days and (iii) certain other events. The price will be the net present value of the capital cost recovery fees that would have been due for the remainder of the Cooperation Period with respect to such generating unit(s). The Malitbog ECA cooperation period will expire ten years after the date of commencement of commercial operation of Unit III. At the end of the cooperation period, the facility will be transferred to PNOC- EDC at no cost, on an "as is" basis. All of PNOC-EDC's obligations under the Malitbog ECA are supported by the Government of the Philippines through a performance undertaking. The capacity fees are 100% of total revenues and there is no energy fee. Casecnan. In November 1995, the Company closed the financing and commenced construction of the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project (the "Casecnan Project") located in the central part of the island of Luzon in the Republic of the Philippines. The Casecnan Project will consist generally of diversion structures in the Casecnan and Denip Rivers that will divert water into a tunnel of approximately 23 kilometers. The tunnel will transfer the water from the Casecnan and Denip Rivers into the Pantabangan Reservoir for irrigation and hydroelectric use in the Central Luzon area. An underground powerhouse located at the end of the water tunnel and before the Pantabangan Reservoir will house a power plant consisting of approximately 150 MW of newly installed rated electrical capacity. A tailrace tunnel of approximately three kilometers will deliver water from the water tunnel and the new powerhouse to the Pantabangan Reservoir, providing additional water for irrigation and increasing the potential electrical generation of two downstream existing hydroelectric facilities of the NPC. CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE Casecnan") which is presently indirectly owned as to approximately 70% of its equity by the Company, is developing the Casecnan Project under the terms of the Project Agreement between CE Casecnan and the National Irrigation Administration ("NIA"). Under the Project Agreement, CE Casecnan will develop, finance and construct the Casecnan Project over the construction period, and thereafter own and operate the Casecnan Project for 20 years (the "Cooperation Period"). During the Cooperation Period, NIA is obligated to accept all deliveries of water and energy, and so long as the Casecnan Project is physically capable of operating and delivering in accordance with agreed levels set forth in the Project Agreement, NIA will pay CE Casecnan a guaranteed fee for the delivery of water and a guaranteed fee for the delivery of electricity, regardless of the amount of water or electricity actually delivered. In addition, NIA will pay a fee for all electricity delivered in excess of a threshold amount up to a specified amount. NIA will sell the electricity it purchases to NPC, although NIA's obligations to CE Casecnan under the Project Agreement are not dependent on NPC's purchase of the electricity from NIA. All fees to be paid by NIA to CE Casecnan are payable in U.S. dollars. The guaranteed fees for the delivery of water and energy are expected to provide approximately 70% of CE Casecnan's revenues. The Project Agreement provides for additional compensation to the CE Casecnan upon the occurrence of certain events, including increases in Philippine taxes and adverse changes in Philippine law. Upon the occurrence and during the continuance of certain force majeure events, including those associated with Philippines political action, NIA may be obligated to buy the Casecnan Project from CE Casecnan at a buy out price expected to be in excess of the aggregate principal amount of the outstanding CE Casecnan debt securities, together with accrued but unpaid interest. At the end of the Cooperation Period, the Casecnan Project will be transferred to NIA and NPC for no additional consideration on an "as is" basis. The Republic of the Philippines has provided a Performance Undertaking under which NIA's obligations under the Project Agreement are guaranteed by the full faith and credit of the Republic of the Philippines. The Project Agreement and the Performance Undertaking provide for the resolution of disputes by binding arbitration in Singapore under international arbitration rules. The Casecnan Project was being constructed pursuant to a fixed- price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Company Ltd. ("HECC"), both of which are South Korean corporations. As of May 7, 1997, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of each such company. CE Casecnan entered into a new turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract will be conducted by a consortium of contractors and subcontractors including Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. and will be headed by Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa (collectively, the "Replacement Contractor"). In connection with the Hanbo Contract termination, CE Casecnan tendered a certificate of drawing to Korea First Bank ("KFB") on May 7, 1997 under the irrevocable standby letter of credit issued by KFB as security under the Hanbo Contract to pay for certain transition costs and other presently ascertainable damages under the Hanbo Contract. As a result of KFB's dishonor of the draw request, CE Casecnan filed an action in New York State Court. That Court granted CE Casecnan's request for a temporary restraining order requiring KFB to deposit $79,329,000, the amount of the requested draw, in an interest bearing account with an independent financial institution in the United States. KFB appealed this order, but the appellate court denied KFB's appeal and on May 19, 1997, KFB transferred funds in the amount of $79,329,000 to a segregated New York bank account pursuant to the Court order. On August 6, 1997, CE Casecnan announced that it had issued a notice to proceed to the Replacement Contractor. The Replacement Contractor was already on site and thereafter fully mobilized and commenced engineering, procurement and construction work on the project. On or about August 27, 1997 CE Casecnan received a favorable summary judgment ruling in New York State Court against KFB. The judgment, which has been appealed by the bank, requires KFB to honor the $79,329,000 drawing by CE Casecnan on the $117,850,000 irrevocable standby letter of credit. On September 29, 1997, CE Casecnan tendered a second certificate of drawing for $10,828,000 to KFB and on December 30, 1997, CE Casecnan tendered a third certificate of drawing for $2,920,000 to KFB. KFB also wrongfully dishonored these draws, but pursuant to a stipulation agreed to deposit the draw amounts in an interest bearing account with the same independent financial institution in the United States pending resolution of the appeal regarding the first draw and agreed to expedite the appeal. The receipt of the letter of credit funds from KFB remains essential and CE Casecnan will continue to press KFB to honor its clear obligations under the letter of credit and to pursue Hanbo and KFB for any additional damages arising out of their actions to date. If KFB were to fail to honor its obligations, under the Casecnan letter of credit, such action could have a material adverse effect on the Casecnan Project and CE Casecnan. On September 2, 1997, Hanbo and HECC filed a Request for Arbitration before the International Chamber of Commerce ("ICC"). The Request for Arbitration asserts various claims by Hanbo and HECC against CE Casecnan relating to the terminated Hanbo Contract and seeks damages. On October 10, 1997, CE Casecnan served its answer and defenses in response to the Request for Arbitration as well as counterclaims against Hanbo and HECC for breaches of the Hanbo Contract. The arbitration proceedings before the ICC are ongoing and CE Casecnan intends to pursue vigorously its claims against Hanbo, HECC and KFB in the proceedings described above. Indonesia Operations and Construction Dieng. On December 2, 1994, a subsidiary of the Company, Himpurna California Energy Ltd. ("HCE") executed a joint operation contract (the "JOC") for the development of the geothermal steam field and geothermal power facilities at the Dieng geothermal field, located in Central Java (the "Dieng Project") with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara ("Pertamina"), the Indonesian national oil company, and executed a "take-or-pay" energy sales contract (the "ESC") with both Pertamina and PLN, the Indonesian national electric utility. HCE was formed pursuant to a joint development agreement with P.T. Himpurna Enersindo Abadi ("P.T. HEA"), its Indonesian partner, which is a subsidiary of Himpurna, an association of Indonesian military veterans, whereby the Company and P.T. HEA have agreed to work together on an exclusive basis to develop the Dieng Project (the "Dieng Joint Venture"). Subsequent to closing the KDG Acquisition in January 1998, the Dieng Joint Venture is structured with subsidiaries of the Company holding an approximate 94% interest (including certain assignments of dividend rights representing an economic interest of 4%), and P.T. HEA holding a 6% interest in the Dieng Project. All government approvals for Units I (55 net MW) and II (80 net MW) necessary for closing were received, including a support letter from the Republic of Indonesia, an off-shore loan board approval, consents to assignment from the Republic of Indonesia, PLN and Pertamina, and all required environmental approvals. Financial closing for Unit I occurred on October 3, 1996, and construction for financing for Unit II was funded on November 17, 1997. Pursuant to the Dieng JOC and ESC, Pertamina has granted to HCE the geothermal field and the wells and other facilities presently located thereon and HCE will build, own and operate power production units with an aggregate capacity of up to 400 MW. HCE will accept the field operation responsibility for developing and supplying the geothermal steam and fluids required to operate the plant. The Dieng JOC is structured as a build own transfer agreement and will expire (subject to extension by mutual agreement) on the date which is the later of (i) 42 years following effectiveness of the Dieng JOC and (ii) 30 years following the date of commencement of commercial generation of the final unit. Upon the expiration of the proposed Dieng JOC, all facilities will be transferred to Pertamina at no cost. HCE is required to pay Pertamina a production allowance equal to three percent of HCE's net operating income from the Dieng Project. Pursuant to the Dieng ESC, PLN agreed to purchase and pay for all of the Project's capacity and energy output on a "take or pay" basis regardless of PLN's ability to accept such energy made available from the Dieng Project for a term equal to that of the Dieng JOC. The price paid for electricity includes a base energy price per kWh multiplied by the number of kWhs the plants deliver or are "capable of delivering", whichever is greater. Energy price payments are also subject to adjustment for inflation. PLN will also pay a capacity payment based on plant capacity. All such payments are payable in U.S. dollars. PT Kiewit/Holt Indonesia, an affiliate of PKS, executed agreements to construct Dieng Unit I and Unit II pursuant to a fixed price, date certain, turnkey construction contract. Affiliates of PKS will provide the engineered supply with respect to Dieng Unit I and Unit II pursuant to a fixed price, date certain, turnkey supply contract. Patuha. The Company's subsidiary, Patuha Power, Ltd. ("PPL") executed a JOC and ESC with Pertamina and PLN, respectively on substantially the same terms as the Dieng project. The Patuha project is located in Western Java. All government approvals for Patuha Unit I (80 net MW) necessary for closing were received, including a support letter from the Republic of Indonesia, on offshore loan board approval, consents to assignment from the Republic of Indonesia, PLN and Pertamina, and all required environmental approvals. Construction financing was funded for Patuha Unit I in September 1997. Patuha Unit I is being constructed by PT Kiewit/Holt Indonesia pursuant to a fixed price, date certain, turnkey construction contract. Affiliates of PKS will provide engineered supply with respect to Patuha Unit I pursuant to a fixed price, date certain, turnkey supply contract. Bali. Significant infrastructure construction and well drilling has occurred at the Bali site, but power plant construction has not commenced. On about June 12, 1997, the Company's special purpose subsidiary, CE Indonesia Funding Corp., entered into a $400 million revolving credit facility (which is nonrecourse to the Company) to finance the development and construction of the Company's geothermal power facilities in Indonesia. Funding under such facility has occurred for Dieng Unit I, Dieng Unit II and Patuha Unit I. Recent Presidential Decrees in Indonesia have created uncertainties regarding the Company's Indonesian activities resulting in the Company recognizing an $87 million non-recurring charge in the fourth quarter of 1997. The Company is proceeding cautiously and is actively pursuing resolution of the issues involving the Indonesian projects in order to protect the Company's interests. Less than five percent of the Company's total assets are invested in Indonesia. The Company intends to take all actions necessary to ensure the Government of Indonesia honors the project contracts. Economies of emerging countries typically experience periods of success and periods of setback. The Company's projects in emerging regions have been and will continue to be structured to minimize risk and have consistently obtained political risk insurance for investments and sovereign guarantees for our projects in Indonesia. In addition, payments in accordance with the project contracts, are in U.S. dollars and therefore are not directly affected by local currency fluctuations. PROJECTS IN DEVELOPMENT The following is a summary description of certain information concerning the Company's advanced stage development projects. Since these projects are still in development there can be no assurance that this information will not change materially over time. In addition, there can be no assurance that development efforts on any particular project, or the Company's development efforts generally, will be successful. See also "Risk Factors" contained in the accompanying Prospectus. United States Salton Sea Minerals Extraction. The Company has developed a process providing for the extraction of minerals from elements in solution in the geothermal brine and fluids utilized at its Imperial Valley plants (the "Salton Sea Extraction Project") as well as the production of power to be used in the extraction process. The initial phase of the project would require delivery of at least 15 MW of power. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Project. Zinc is primarily used in galvanizing steel for use in the automobile industry. The Company intends to sequentially develop manganese, silver, gold, lead, boron, lithium and other products as it further develops the extraction technology. If successfully developed, the mineral extraction process will provide an environmentally responsible and low cost minerals recovery methodology. The Company is also investigating producing silica from the solids precipitated out of the geothermal power process. Silica is used as a filler for such products as paint, plastics and high temperature cement. Telephone Flat. Under a Bonneville Power Administration ("BPA") geothermal pilot program, the Company has been developing a 30 net MW geothermal project which was originally located in the Newberry Known Geothermal Resource Area in Deschutes County, Oregon (the "Telephone Flat Project"). The BPA contract arrangements have been amended to reflect the relocation of the project to Telephone Flat in Northern California where the Company has two successful production wells. Under the amended BPA contract arrangements, BPA will purchase 30 MW from the project and has an option to purchase an additional 100 MW. The movement of the project to this alternative location and BPA's purchase obligation are subject to obtaining a final environmental impact statement relating to the new site location. United Kingdom Exeter. Exeter Power Limited ("Exeter") is a company owned 50% by Northern Electric Generation Limited and 50% by Rolls-Royce Power Ventures. Exeter is developing a 50 net MW gas-fired power plant at Exeter, England. This project is based upon the U.K. "Mid-merit" model (described below) and will be managed and operated by Northern upon commercial operation. The power purchase contract and permits for the project are currently being finalized. U.K. Mid-merit Projects. The Company, through Northern Generation, is pursuing a number of "Mid-merit" project opportunities in addition to Exeter and Viking (which is under construction), in conjunction with and separate from Rolls-Royce. "Mid-merit" projects are those projects which have generation units having a registered capacity of 50 net MW or less. As a result, these projects only require local planning permission and limited central government permits. In addition, these projects are connected to the local distribution system and not the National Grid, which means these projects do not have to be a member of the Pool and pay generator related grid and Pool charges. These Mid-merit generating projects are also not subject to central dispatch by the National Grid and therefore allow for the potential of gas arbitrage between the electricity day-ahead pool market and the within-day gas spot market. Northern supplies gas to these projects through a gas tolling contract arrangement. Finally, these projects are based on open (simple) cycle aero derivative gas turbines which are ideally suited to multiple start/stop operations. This flexible capability provides significant economic benefits to Northern's electricity supply business in buying electricity from the Mid-merit plant and avoiding pool purchases at high pool price times and making Pool purchases when the Pool price is below the Mid-merit plant's marginal costs. U.K. Gas Transportation and Storage. The Company, through CE Gas, is pursuing a number of gas transportation and storage opportunities in the U.K. to integrate with its North Sea upstream gas production operations. Philippines Alto Peak. The Alto Peak Project is a smaller geothermal project in the same general area of Leyte as the Upper Mahiao, Mahanagdong and Malitbog Projects. A subsidiary of the Company and PNOC-EDC have executed a 70 net MW Energy Conversion Agreement, dated May 7, 1994. The general terms and conditions are similar to the Malitbog Energy Conversion Agreement ("ECA"). However, the plant design has not been initiated because PNOC-EDC has not finalized the steam conditions (pressure, composition and pH). PNOC-EDC is still drilling and testing the geothermal wells that will supply steam to such project. Consequently, the ECA has been extended and the Company has not commenced financing arrangements for the Alto Peak Project. Indonesia Dieng Phase II, Patuha Phase II and Bali. The Company's Dieng, Patuha and Bali projects in Indonesia represent ongoing, development programs of 985 MW under contract, to be brought into commercial operation on a modular basis as the steam fields are drilled and developed. However, the situation in Indonesia has created some significant challenges for the Company, requiring an $87 million non- recurring charge in the fourth quarter of 1997. Producing Gas Field Operations and Fields in Development CE Gas UK Limited. CE Gas UK Limited ("CE Gas") is a gas exploration and production company which is focused on developing integrated upstream gas projects. Its "upstream gas" business consists of the exploration, development and production, including transportation and storage, of gas for delivery to a point of sale into either a gas supply market or a power generation facility. CE Gas holds various interests in the southern basin of the United Kingdom sector of the North Sea, as described below. Also as is more fully discussed below, CE Gas has recently been involved in certain gas development and exploration activities relating to a large gas field prospect in Poland and the Gingin field in the Perth Basin in Australia. The Company's Producing Gas Field Operations and Fields in Development PRODUCING GAS FIELDS SHARE OF CURRENT LOCATION REMAINING % WORKING RESERVES INTEREST BCF(1) Windermere 15.0 20% U.K. Offshore (North Sea) Victor 12.1 5% U.K. Offshore (North Sea) Schooner 11.1 2% U.K. Offshore (North Sea) Johnston 18.0 18.264% U.K. Offshore (North Sea) FIELDS IN DEVELOPMENT Size Km2 Gingin Concession 2,960 9%(2) S.W. Australia Onshore (Perth Basin) Pila Concession 13,000(3) 100% N.W. Poland (Polish Trough) (1)Gas reserves in Billion cubic feet (or "Bcf") as of December 31, 1997. The Classification "Remaining" means reserves which geophysical, geological and engineering data indicate to be in place or recoverable (as the case may be) with a 50% probability the reserves will exceed the estimate. (2)Currently CE Gas beneficially owns 9% of Gingin Concession with a right to earn up to a 50% working interest. (3)Subject to 25% relinquishment after every 2 years during the 8 year contract term based on work program results. Producing Fields Windermere Field (Producing). The Windermere Field is located in the Eastern part of the Southern North Sea approximately 62 miles east of Hull on the U.K. coast and has Remaining reserves of 15.0 bcf net to CE Gas. The field is produced by an unmanned platform which has two wells. The gas is transported via an 8" pipeline to the Markham Field where it is processed, compressed and delivered through the K13 pipeline system to the Den Helder terminal on the Netherlands coast. CE Gas holds a 20% working interest in this field which commenced production in April 1997 and currently has average net daily production of 9.0 MM scfd (million standard cubic feet per day). Gas is sold to N.V. Nederlandse Gasunie. Victor Field (Producing). The Victor gas field is located in the central part of the Southern North Sea, approximately 80 miles east of the Theddlethorpe terminal on the U.K. coast and has net Remaining reserves of 12.1 bcf net to CE Gas. An unmanned platform is installed and the field produces from 5 production wells and a sixth subsea well tied back to the platform. The gas is exported through a 16" pipeline to the Viking field and then onwards to the Theddlethorpe shore terminal. The Victor field has been in production since September 1984, and currently has average daily production of 5.94 MM scfd and sells its gas to British Gas Trading Limited. CE Gas holds a 5% working interest in this field. Schooner Field (Producing). The Schooner Field is located in the Northern part of the Southern North Sea and has Remaining reserves of 11.1 bcf. The field is produced by an unmanned platform which is tied back through a 28km 16" flowline to the Murdoch platform. Production is achieved from four wells with a fifth well planned this year. The gas is transported through the CMS pipeline to the Theddlethorpe shore terminal. CE Gas holds a 2.07% working interest in the Schooner Field, which commenced production in October 1996 and currently has average net daily production of 1.8 MM scfd. The CE Gas share of the gas is sold to its affiliate Northern. Johnston Field (Producing). The Johnston gas field is located in the Southern North Sea approximately 56 miles north east of Scarborough on the U.K. coast and has Remaining reserves of 18 bcf net to CE gas. The field is produced from three subsea wells tied back to the Ravenspurn North field via a 4.5 mile, 12" pipeline. Gas is exported via the Cleeton field to the Dimlington terminal via a 33 mile, 36" pipeline. The Johnston field has been in production since October 1994 at an average daily rate of 53 MMscfd. Gas is sold to Eastern Natural Gas. CE Gas has a 18.264% working interest in this field. Fields in Development Pila. In August 1997, CE Gas signed an eight year concession development agreement with the Polish government providing it with the exclusive right (a 100% working interest) to develop the extensive (13,000 square kilometers) undeveloped Pila gas concession in the Polish Trough in northwest Poland. CE Gas is committed to a seismic and drilling work program to develop producing areas within the concession over that period, subject to relinquishment of up to 25% of the concession area after every two years, with only developed areas to be retained by CE Gas at the end of the eight year term. The Company believes that there is the potential to structure an integrated upstream gas/power generation project at the Pila concession, subject to (among other things) identifying a suitable site and negotiating an acceptable power offtake agreement. Gingin Gas Field. In August 1997, CE Gas signed an earn-in agreement with Empire Gas of Australia, the permit holder for various concession areas in the Gingin field in the Perth Basin in Western Australia. The earn-in agreement provides CE Gas with the ability, through a seismic and drilling phased work program, to obtain up to a 50% working interest in the main concession area totaling 2,960 square kilometers and up to a 33% working interest in four ancillary concession areas totaling 9,451 square kilometers. Gingin gas reserves are estimated by Empire Gas to be 470 bcf. Given the advantages of the location of the Gingin field, in close proximity to an industrial area and electric residential load center, the Company believes that the Gingin field possesses the potential for an integrated upstream gas/power generation project. Both electricity and gas are in the process of being opened up for competition. 95% of all gas to SW Australia is currently supplied from the NW shelf (Dampier to Bunbury pipeline--1500km). The Onshore Perth Basin is known to be gas prone but has been significantly underexplored and underdeveloped. Historically, gas has been a state controlled energy sector in Australia. The Gingin field proved gas in the early 1970s. The Company believes that new technologies now offer the potential for extracting significant gas reserves through more advanced recovery methods, and the Company, which currently beneficially owns a 9% interest in the Gingin Concession, has the right to earn up to a 50% working interest under its phased seismic and drilling work program with Empire Gas of Australia. Regulatory, Energy and Environmental Matters United States The Company is subject to a number of environmental laws and other regulations affecting many aspects of its present and future operations, including the construction or permitting of new and existing facilities, the drilling and operation of new and existing wells and the disposal of various geothermal solids. Such laws and regulations generally require the Company to obtain and comply with a wide variety of licenses, permits and other approvals. No assurance can be given, however, that in the future all necessary permits and approvals will be obtained and all applicable statutes and regulations complied with. In addition, regulatory compliance for the construction of new facilities is a costly and time-consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for permitting and create the risk of expensive delays or material impairment of project value if projects cannot function as planned due to changing regulatory requirements or local opposition. The Company believes that its operating power facilities are currently in material compliance with all applicable federal, state and local laws and regulations. There can be no assurance that existing regulations will not be revised or that new regulations will not be adopted or become applicable to the Company which could have an adverse impact on its operations. In particular, the independent power market in the United States is dependent on the existing energy regulatory structure, including PURPA and its implementation by utility commissions in the various states. Each of the Company's operating domestic power facilities meets the requirements promulgated under PURPA to be qualifying facilities. Qualifying facility status under PURPA provides two primary benefits. First, regulations under PURPA exempt qualifying facilities from the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), most provisions of the Federal Power Act (the "FPA") and the state laws concerning rates of electric utilities, and financial and organization regulations of electric utilities. Second, FERC's regulations promulgated under PURPA require that (1) electric utilities purchase electricity generated by qualifying facilities, the construction of which commenced on or after November 9, 1978, at a price based on the purchasing utility's full Avoided Cost, (2) the electric utility sell back-up, interruptible, maintenance and supplemental power to the qualifying facility on a non-discriminatory basis, and (3) the electric utility interconnect with a qualifying facility in its service territory. Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from qualifying facilities at prices based on Avoided Costs. The Company does not know whether such legislation will be passed or what form it may take. The Company believes that if any such legislation is passed, it would apply to new projects only and thus, although potentially impacting the Company's ability to develop new domestic projects, it would not affect the Company's existing qualifying facilities. There can be no assurance, however, that any legislation passed would not adversely impact the Company's existing domestic projects. In addition, many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry and increase access to electric utilities' transmission and distribution systems for independent power producers and electricity consumers. On September 1, 1996, the California legislature adopted an industry restructuring bill that would provide for a phased-in competitive power generation industry with a power pool and independent system operator and also would permit direct access to generation for all power purchasers outside the power exchange under certain circumstances. Under the bill, consistent with the requirements of PURPA, existing qualifying facilities power sales agreements would be honored. The Company cannot predict the final form or timing of the proposed industry restructuring or the results of its operations. The structure of such federal and state energy regulations have in the past, and may in the future, be the subject of various challenges and restructuring proposals by utilities and other industry participants. The implementation of regulatory changes in response to such changes or restructuring proposals, or otherwise imposing more comprehensive or stringent requirements on the Company, which would result in increased compliance costs, could have a material adverse effect on the Company's results of operations. United Kingdom Northern's businesses are subject to numerous regulatory requirements with respect to the protection of the environment. The Electricity Act obligates the UK Secretary of State or the Regulator to take into account the effect of electricity generation, transmission and supply activities upon the physical environment when approving applications for the construction of generating facilities and the location of overhead power lines. The Electricity Act requires Northern to consider the desirability of preserving natural beauty and the conservation of natural and man-made features of particular interest, when it formulates proposals for development in connection with certain of its activities. Northern mitigates the effects its proposals have on natural and man-made features and administers an environmental assessment when it intends to lay cables, construct overhead lines or carry out any other development in connection with its licensed activities. The Environmental Protection Act 1990 addresses waste management issues and imposes certain obligations and duties on companies which handle and dispose of waste. Some of Northern's distribution activities produce waste, but Northern believes that it is in compliance with the applicable standards in such regard. Possible adverse health effects of electromagnetic fields ("EMFs") from various sources, including transmission and distribution lines, have been the subject of a number of studies and increasing public discussion. Current scientific research is inconclusive as to whether EMFs may cause adverse health effects. The only United Kingdom standards for exposure to power frequency EMFs are those promulgated by the National Radiological Protection Board and relate to the levels above which non-reversible physiological effects may be observed. Northern fully complies with these standards. However, there is the possibility that passage of legislation and change of regulatory standards would require measures to mitigate EMFs, with resulting increases in capital and operating costs. In addition, the potential exists for public liability with respect to lawsuits brought by plaintiffs alleging damages caused by EMFs. Northern believes that it has taken and continues to take measures to comply with the applicable laws and governmental regulations for the protection of the environment. There are no material legal or administrative proceedings pending against Northern with respect to any environmental matter. In the general election held in the United Kingdom on May 1, 1997, the Labour Party won a majority of seats in the United Kingdom Parliament. On July 31, 1997, the United Kingdom Parliament passed the so called "windfall tax" to be levied on privatized utilities which resulted in a charge to net income of approximately $136 million. See the Company's Current Report on Form 8-K dated July 7, 1997, incorporated herein by reference. There can be no assurance that other possible changes in tax or utility regulation by the United Kingdom government, by whichever party it is controlled, would not have a material adverse effect on the Company's results of operations. In March 1998 the Government published a consultation on utility regulation. This paper outlined a number of proposals for discussion. The stated objectives are "fairness and efficiency" which the Government regard as "the key to securing a long-term, stable and effective framework capable of serving consumers well and of taking these industries into the next millennium". Some of the proposals under consideration would require legislative changes. Employees At December 31, 1997, the Company and its subsidiaries (including Northern) employed approximately 4,300 people. None of the Coso Partnerships, the Falcon Project nor the Imperial Valley Project partnerships hire or retain any employees. All employees necessary to the operation of the Coso Project are provided by the Company under certain plant and field operations and maintenance agreements. All employees necessary to operate the Falcon and Imperial Valley Projects are provided by affiliates of the Company under certain administrative services and operation and maintenance agreements. International development activities in Indonesia and the Philippines are principally performed by employees of affiliates of the Company and operations will be performed by employees of the local project entities. The Company's affiliates currently maintain offices in Manila and Jakarta. Of Northern's employees, at December 31, 1997, approximately 86% are represented by labor unions. All Northern employees who are not party to a personal employment contract are subject to collective bargaining agreements that are covered by eight separate business agreements. These arrangements may be amended by joint agreement between the trade unions and the individual business through negotiation in the appropriate Joint Business Council. Northern believes that its relations with its employees are good. Item 2. Properties Property. The Company's most significant physical properties, other than those owned by Northern (described herein), are its 21 operating power facilities, its plants under construction and related real property interests. The Company also maintains an inventory of approximately 200,000 acres of geothermal property leases. The Company owns its principal executive offices and leases its offices in Jakarta and Manila. Certain of the producing acreage owned by Magma is leased to Mammoth-Pacific as owner and operator of the Mammoth Plants, and Magma, as lessor, receives royalties from the revenues earned by such power plants. The Company, as lessee, pays certain royalties and other fees to the property owners and other royalty interest holders from the revenue generated by the Imperial Valley Project. Lessors and royalty holders are generally paid a monthly or annual rental payment during the term of the lease or mineral interest unless and until the acreage goes into production, in which case the rental typically stops and the (generally higher) royalty payments begin. Leases of federal property are transacted with the Department of Interior, Bureau of Land Management, pursuant to standard geothermal leases under the Geothermal Steam Act and the regulations promulgated thereunder (the "Regulations"), and are for a primary term of 10 years, extendible for an additional five years if drilling is commenced within the primary term and is diligently pursued for two successive five-year periods upon certain conditions set forth in the Regulations. A secondary term of up to 40 years is available so long as geothermal resources from the property are being produced or used in commercial quantities. Leases of state lands may vary in form. Leases of private lands vary considerably, since their terms and provisions are the product of negotiations with the landowners. Northern owns the freehold of its principal executive offices in Newcastle upon Tyne, England. Northern has both network and non-network land and building. At December 31, 1997, Northern had freehold and leasehold interests in approximately 7,500 network properties, comprising principally sub-station sites. The recorded historical cost account net book value of total network land and buildings at December 31, 1997 was pounds sterling 23.9 million. Northern owns, directly or indirectly, the freehold or leasehold interests of such land and buildings. At December 31, 1997 Northern had freehold and leasehold interests in approximately 102 non-network properties comprising chiefly offices, former retail outlets, depots, warehouses and workshops. The recorded historical cost account net book value of total non-network land and buildings at December 31, 1997 was pounds sterling 25.6 million. Item 3. Legal Proceedings The Company is not a party to any material pending legal proceedings. However, as described herein, certain of the Company's projects are parties to litigation or other disputes. Item 4. Submission of Matters to a Vote of Security Holders. Not applicable. PART II Item 5. Market for Registrant's Common Equity and Related Stockholder's Matters The Common Stock is listed on the New York Stock Exchange (the "NYSE"), the Pacific Stock Exchange and the London Stock Exchange under the symbol "CE." The following table sets forth for the fiscal quarters indicated the high and low last reported sale prices of the Common Stock as reported on the NYSE Composite Tape. PRICE RANGE HIGH LOW Fiscal Year Ending December 31, 1997 Fourth Quarter 39.625 28.00 Third Quarter 41.75 30.9375 Second Quarter 41.625 32.625 First Quarter 38.375 32.125 Fiscal Year Ending December 31, 1996 Fourth Quarter 33.625 28.125 Third Quarter 31.875 22.875 Second Quarter 28.375 24.00 First Quarter 26.875 18.375 Fiscal Year Ending December 31, 1995 Fourth Quarter 20.875 17.875 Third Quarter 21.50 16.125 Second Quarter 17.125 15.50 First Quarter 18.875 15.375 On March 23, 1998, the last reported sale price of the Common Stock on the NYSE Composite Tape was $30 7/8 per share. As of March 23, 1998, there were approximately 1,091 holders of record of the Common Stock. The Company's present policy is to reinvest earnings in the business and pay no dividends on its Common Stock. In addition, certain of the Company's current debt indentures restrict the payment of cash dividends based upon a formula and limit the amount of dividends and other distributions generally to no more than 50% of the Company's accumulated adjusted consolidated net income as defined, subsequent to April 1, 1994, plus the proceeds of any stock issuances. The Company's 10-1/4% senior discount notes due 2004, the Company's 9 1/2% senior notes due 2006 and the Company's 7.63% senior notes due 2007 restrict the payment of cash dividends based upon a formula and limit the amount of dividends and other distributions generally to no more than 50% of the Company's accumulated adjusted consolidated net income as defined, subsequent to April 1, 1994, plus the proceeds of any stock issuance. The Company's ability to pay dividends is dependent upon receipt of dividends or other distributions from the Company's subsidiaries and the partnerships and joint ventures in which the Company has interests. The availability of distributions from the Company's joint ventures is subject to the satisfaction of various covenants and conditions contained in the venture's financing documents (such as those contained in the Salton Sea Funding, Coso Funding, or international project financing documents) and the Company anticipates that future project level financings will contain certain conditions and similar restrictions on the distribution of cash flow to the Company. Item 6. Selected Financial Data There is hereby incorporated by reference the information which appears under the caption "Selected Financial Data" in the Annual Report. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation There is hereby incorporated by reference the information which appears under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report. Item 8. Financial Statements and Supplementary Data There is hereby incorporated by reference the information which appears in the Consolidated Financial Statements and notes thereto in the Annual Report. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Not applicable. PART III MANAGEMENT Item 10. Directors, Executive and Other Officers of the Company There is hereby incorporated by reference the information which appears under the caption "Information Regarding Nominees for Election as Directors and Directors Continuing in Office at the Annual Meeting" in the Proxy Statement. The Company's management structure is organized functionally and the current executive and other officers of the Company and their positions are as follows: David L. Sokol Chairman of the Board and Chief Executive Officer Gregory E. Abel President and Chief Operating Officer Steven A. McArthur Executive Vice President, General Counsel and Secretary Craig M. Hammett Senior Vice President and Chief Financial Officer Douglas L. Anderson Assistant General Counsel, Assistant Secretary and General Counsel, CalEnergy Operating Company David A. Baldwin General Manager, Philippines Edward F. Bazemore Vice President, Human Resources Robert Beck Director, Information Systems Donald C. Blachly General Manager, Coso Geothermal Operations Malcolm Chandler Director, Northern Electric and Managing Director, Supply P. Eric Conner Director, Northern Electric and Managing Director, Utility Services Dave Crompton Managing Director, Northern Electric, Retail Richard B. Dalton General Manager, Leyte Geothermal Operations Alan Dickson Tax Manager, Northern Electric J. Douglas Divine Vice President, Project Development David A. Faulkner Director, Personnel and Corporate Affairs, Northern Electric John L. Featherstone General Manager, Minerals Vincent R. Fesmire Vice President, Construction and Engineering James A. Flores Vice President, Project Finance Adrian M. Foley III Vice President, Marketing Dr. John M. France Regulation Director, Northern Electric G. Valerie Giles Company Secretary, Northern Electric Patrick J. Goodman Vice President, Chief Accounting Officer and Controller Brian K. Hankel Vice President and Treasurer Edward J. Heinrich General Manager, U.S. Gas Operations Gary L. Hood General Manager, NorCon Gas Operations Walter Keenan Director, Human Resources Dr. Philip S. Lawless Managing Director, Generation, Northern Electric Kenneth R. Lewis General Manager, Power Resources Gas Operations Ken Linge Director, Financial Planning, Northern Electric Steven G. Lyons Project Manager, Casecnan Thomas R. Mason President, CalEnergy Operating Company Frederick L. Manuel Vice President and Chief Operating Officer, Asia Patti J. McAtee Director, Corporate Communications Neil W. Midgley Managing Director, Northern Metering Services Donald M. O'Shei, Jr. President, CalEnergy Development Company David Pearson Managing Director, Marketing and Sales, Northern Electric Steve Raine Managing Director, Northern Information Systems and Northern Electric Telecom P. Dan Rorabaugh General Manager, Saranac Gas Operations John A. Schretlen General Manager, Yuma Gas Operations James J. Sellner Director, Taxation Robert S. Silberman Senior Vice President, Administration James D. Stallmeyer General Counsel, Northern Electric and General Counsel, CalEnergy Development Company David Swan Director, Northern Electric and Managing Director, Distribution James T. Turner General Manager, Imperial Valley Geothermal Operations David A. Waters Managing Director, Northern Utility Services Jonathan M. Weisgall Vice President, Legislative and Regulatory Affairs Peter Youngs Managing Director, Gas Exploration and Development Set forth below is certain information with respect to each of the foregoing officers: DAVID L. SOKOL, 41, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and served as President of CalEnergy from April 19, 1993 until January 21, 1995. Mr. Sokol has been Chairman of the Board of Directors since May 1994 and a director since March 1991. Formerly, among other positions held in the independent power industry, Mr. Sokol served as President and Chief Executive Officer of Kiewit Energy Company, which at that time was a wholly owned subsidiary of PKS, and Ogden Projects, Inc. GREGORY E. ABEL, 35, President and Chief Operating Officer. Mr. Abel joined the Company in 1992. Mr. Abel is a Chartered Accountant and from 1984 to 1992 he was employed by Price Waterhouse. As a Manager in the San Francisco office of Price Waterhouse, he was responsible for clients in the energy industry. STEVEN A. McARTHUR, 40, Executive Vice President, General Counsel and Secretary. Mr. McArthur joined the Company in February 1991. From 1988 to 1991 he was an attorney in the Corporate Finance Group at Shearman & Sterling in San Francisco. From 1984 to 1988 he was an attorney in the Corporate Finance Group at Winthrop, Stimson, Putnam & Roberts in New York. CRAIG M. HAMMETT, 37, Senior Vice President and Chief Financial Officer. Mr. Hammett joined the Company in 1996. Prior to joining the Company, Mr. Hammett served as Director of Project Finance for Energy Power group, as Director, Project Finance and M&A for CSW Energy and as a corporate loan officer for various financial institutions. DOUGLAS L. ANDERSON, 40, Assistant General Counsel, Assistant Secretary and General Counsel, CalEnergy Operating Company. Mr. Anderson joined the Company in February 1993. From 1990 to 1993, Mr. Anderson was a business attorney with Fraser, Stryker, Vaughn, Meusey, Olson, Boyer & Bloch, P.C. in Omaha. From 1987 through 1989, Mr. Anderson was a principal in the firm Anderson & Anderson. Prior to that, from 1985 to 1987, he was an attorney with Foster, Swift, Collins & Coey, P.C. in Lansing, Michigan. DAVID A. BALDWIN, 33, General Manager, Philippines. Mr. Baldwin joined the Company in June 1997. From December 1996 to June 1997, Mr. Baldwin served as Vice President, Project Development for Asia Power Ltd. in Hong Kong. From October 1994 to December 1996, Mr. Baldwin was Project Director at SouthPac Corporation Ltd. in New Zealand and, prior to that, he held a series of project management and engineering positions at Shell International in the Netherlands and New Zealand. EDWARD F. BAZEMORE, 61, Vice President, Human Resources. Mr. Bazemore joined the Company in July 1991. From 1989 to 1991, he was Vice President, Human Resources, at Ogden Projects, Inc. in New Jersey. Prior to that, Mr. Bazemore was Director of Human Resources for Ricoh Corporation, also in New Jersey. Previously, he was Director of Industrial Relations for Scripto, Inc. in Atlanta, Georgia. ROBERT BECK, 36, Director, Information Systems. Mr. Beck joined the Company in April 1996. Prior to that he was employed by Inacom, Corp., Sequoia Systems, Inc., AT&T - Brandon Consulting Group, U.S. West Marketing Resources Group, Inc., United Phone Book Advertisers, Inc. and Henningsen, Durham & Richardson ("HDR"). DONALD C. BLACHLY, 50, General Manager, Coso Geothermal Operations. Mr. Blachly joined the Company in June 1993. Prior to that Mr. Blachly had been employed by Santa Fe Geothermal and the Sacramento Municipal Utility District in various management and engineering capacities. MALCOLM CHANDLER, 55, Director, Northern Electric and Managing Director, Supply. Mr. Chandler joined Northern in 1970 from Manweb as Tariffs Engineer. His management positions have included Tariffs & Supplies Manager, Regional Manager and Director of Tariffs & Contracts. ERIC CONNOR, 49, Director, Northern Electric and Managing Director, Utility Services. Mr. Connor joined Northern in 1992 as a Director. Prior to joining Northern, he was a Director at NEI Reyrolle Ltd. and prior to that, his appointments included: deputy group head of engineering, National Nuclear Corporation; manager computer systems, NEI Electronics (C&I Systems); systems engineer, Davy-Leowy; software engineer, Marconi Space & Defence. DAVE CROMPTON, 44, Managing Director, Northern Electric Retail. Mr. Crompton joined Northern Electric Retail in April 1990 where he served as Sales Director, and earlier this year also took over the Marketing function. He became Managing Director in June 1997. During his time with Northern Electric he has gained a Master in Business Administration at Durham University. Mr. Crompton has 26 years experience in electrical retailing of which 19 years were with Dixons/Currys where he held the posts of Regional Sales Manager and Divisional Marketing Manager. RICHARD B. DALTON, 45, General Manager, Leyte Geothermal Operations. Mr. Dalton joined the Company in November 1989. Prior to that he was Plant Superintendent at Imperial Valley from 1987 to 1989. From 1976 to 1987 Mr. Dalton was an Engineering Officer with the U.S. Merchant Marines. ALAN DICKSON, 49, Tax Manager, Northern Electric. Mr. Dickson joined Northern in September 1989. Prior to that Mr. Dickson served in various posts with the Inland Revenue and as District Inspector, Hexham. J. DOUGLAS DIVINE, 41, Vice President, Project Development. Mr. Divine joined the Company in September 1996. Prior to that, he was Director of Planning and Regulatory Affairs with Falcon Seaboard Resources Inc. from 1990 to 1996. From 1987 to 1990, he was Senior Manager of Management Consulting Services with Price Waterhouse; from 1984 to 1986 Mr. Divine was Director of Operations Review Divisions and Executive Assistant to Commissioner of the Public Utility Commission of Texas; and from 1983 to 1984, he was Coordinator of Revenue and Economic Analysis for the Governor's Office, State of Texas. DAVID A. FAULKNER, 50, Director, Personnel and Corporate Affairs, Northern Electric. Mr. Faulkner's management positions with the Company have included Industrial Relations Manager, Privatization Manager and Director of Corporate Affairs, to which he added responsibility for Personnel and Training in 1994. JOHN L. FEATHERSTONE, 53, General Manager, Minerals. Mr. Featherstone joined the Company in April 1996. From July 1995 to March 1996 he was Plant Manager with Unocal Geothermal of Indonesia. From 1993 to July 1995 he served in various supervisory capacities with the Company. From 1981 to 1995 he was Production Engineer and Production Superintendent for Unocal Geothermal. VINCENT R. FESMIRE, 57, Vice President, Construction and Engineering. Mr. Fesmire joined the Company in October 1993. Since joining CalEnergy, Mr. Fesmire's responsibilities have shifted from project development and implementation to construction in parallel with the status of the Company's projects. Prior to joining the Company, Mr. Fesmire was employed for 19 years with Stone & Webster, an engineering firm, serving in various management level capacities with an expertise in geothermal design engineering. JAMES A. FLORES, 44, Vice President, Project Finance. Prior to joining CalEnergy in May 1994, Mr. Flores was employed for 12 years with Mellon Bank, first in its Latin American Group and subsequently in its Project Finance Group. ADRIAN M. FOLEY, III, 51, Vice President, Marketing. Mr. Foley joined the Company in January 1994 as Project Development Manager and continued in that capacity until January 1997 when he was promoted to Vice President, Marketing. Prior to joining CalEnergy, Mr. Foley was Regional Manager, Business Development with Ogden Projects, Inc. from 1989 to 1993 and Executive Vice President with Rescom Development Company from 1980 to 1989. DR. JOHN M. FRANCE, 40, Regulation Director, Northern Electric. Mr. France joined Northern in 1989. From 1982 to 1989, Mr. France held a number of regulatory positions with British Gas. G. VALERIE GILES, 46, Company Secretary, Northern Electric. Ms. Giles joined Northern Electric in 1989. From 1987 to 1989 she was Assistant Company Secretary at Amersham International plc and worked in their legal department from 1974 to 1987. PATRICK J. GOODMAN, 31, Vice President, Chief Accounting Officer and Controller. Mr. Goodman joined the Company in June 1995, and served as Manager of Consolidation Accounting until September 1996 when he was promoted to Controller. Prior to joining the Company, Mr. Goodman was an accountant at Coopers & Lybrand. BRIAN K. HANKEL, 35, Vice President and Treasurer. Mr. Hankel joined the Company in February 1992 as Treasury Analyst and served in that position to December 1995. Mr. Hankel was appointed to Assistant Treasurer in January 1996 and was appointed Treasurer in January 1997. Prior to joining the Company, Mr. Hankel was a Money Position Analyst at FirsTier Bank of Lincoln from 1988 to 1992 and Senior Credit Analyst at FirsTier from 1987 to 1988. EDWARD J. HEINRICH, 44, General Manager, U.S. Gas Operations. Mr. Heinrich joined the Company in November 1993. Prior to the joining the Company Mr. Heinrich was plant supervisor with Sithe Energies, Inc. and prior to that he was with the United States Navy. GARY L. HOOD, 43, General Manager, NorCon Gas Operations. Mr. Hood joined NorCon Gas Operations in January 1997. Prior to that, Mr. Hood held various positions at Saranac, the most recent position from August 1996 to January 1997 as Operations Manager. From 1977 to the mid 1990's Mr. Hood served in the U.S. Navy with positions as Nuclear Machinists's Mate, Leading Petty Officer, Division Leading Petty Officer, Crew Chief/Plant Division Leading Officer, Nuclear Planner and Leading Crew Chief, Navy Nuclear Power Training Unit. WALTER G. KEENAN, 42, Director, Human Resources. Mr. Keenan joined CalEnergy in November 1991 as Director of Human Resources. From August 1990 to October 1991 he served as Human Resources Coordinator for Texaco Refining & Marketing, Inc. Prior to that Mr. Keenan was Human Resources Manager with Empire of America, FSB from September 1986 to July 1990 and Employee Relations Manager Training/Development Specialist with Gould Semiconductors from May 1982 to August 1986. DR. PHILIP S. LAWLESS, 36, Managing Director, Generation, Northern Electric. Mr. Lawless joined Northern in 1989 as Contract Development Officer (Power Purchase). His previous positions in Northern include Project Manager-Teesside Power Limited and Generation Projects Manager. Prior to joining Northern, he worked at NEI Parsons Ltd, where he held various positions, and North Kalgurlie Mines Ltd, Australia, as an Assistant Plant Metallurgist. KENNETH R. LEWIS, 62, General Manager, Power Resources Gas Operations. Mr. Lewis joined the Company as Manager for Power Resources, Inc. after extensive power plant background during thirty- two years of service with TU Electric. Mr. Lewis received his BSME from the University of Oklahoma School of Engineering. He is a Registered Professional Engineer and a member of the American Society of Mechanical Engineers. KEN LINGE, 48, Director, Financial Planning, Northern Electric. Mr. Linge joined Northern as an accountancy trainee in 1968. He has held a variety of finance posts. In charge of Financial Planning since 1987, he has been involved in privatization, regulatory reviews and financial and treasury functions. STEVEN G. LYONS, 51, Project Manager, Casecnan. Mr. Lyons joined the Company in August 1997. Prior to that he was a Construction Specialist and Senior Construction Engineer for Stone & Webster. Prior to that he held a variety of engineering positions at various generating facilities and was a construction Superintendent at the Salton Sea plants. THOMAS R. MASON, 54, President, CalEnergy Operating Company. Mr. Mason joined the Company in March 1991. From October 1989 to March 1991, Mr. Mason was Vice President and General Manager of Kiewit Energy Company. Prior to that, Mr. Mason was Director of Marketing for Energy Factors, Inc. (now Sithe Energies U.S.A., Inc.), a non-utility developer of power facilities. Prior to that Mr. Mason was a worldwide Market Manager of power generation for Caterpillar's Solar Gas Turbines, a gas turbine manufacturer. FREDERICK L. MANUEL, 39, Vice President and Chief Operating Officer, Asia. Mr. Manuel joined the Company in 1991. Prior to that, he was employed by Chevron Corporation with responsibilities including land and offshore drilling, reservoir and production engineering, project management and technical research. PATTI J. MCATEE, 40, Director, Corporate Communications. Marketing and Public Relations Manager. Ms. McAtee joined the Company in 1995. Ms. McAtee was previously employed by Bergan Mercy Medical Center since 1984. Since 1990 she was Marketing and Public Relations Manager for the hospital. NEIL W. MIDGLEY, 50, Managing Director, Northern Metering Services. Mr. Midgley has spent more than 28 years in Northern Electric with 18 years in management including seven years as a Senior Manager prior to his current appointment. Mr. Midgley was appointed to his present post in April 1996. DONALD M. O'SHEI, JR., 38, President, CalEnergy Development Company. Mr. O'Shei joined the Company in August 1992. Prior to 1997, he served as General Manager--Indonesia and Vice President of CE International Investments, Ltd. for the Company. From 1991 to 1992, he was employed by Proven Alternatives Capital Corporation as a Financial Analyst. Prior to 1991, Mr. O'Shei served in the U.S. Army in the Special Forces, Airborne and Pathfinder Units. DAVID PEARSON, 43, Managing Director, Marketing and Sales, Northern Electric. Mr. Pearson joined Northern in 1992 as Managing Director, Retail. Prior to that his directorships included Midlands Electricity, Sodexho, Thorn EMI, and Moulinex UK. He also held management positions at General Foods and Gilette. STEVE RAINE, 51, Managing Director, Northern Information Systems and Northern Electric Telecom. Mr. Raine's appointments have included: Head of Computer Services for North Yorkshire County Council; Director of IT at Northern; General Manager and Executive Director of Northern Information Systems (NIS). He currently represents the UK electricity industry in UNIPEDE (the European electricity utility forum) on IT matters and is a member of the UK Electricity Pool Programme Board responsible for delivery of the new trading systems for the opening up of the electricity market. P. DAN RORABAUGH, 36, General Manager, Saranac Gas Operations. Mr. Rorabaugh joined the Company in 1996. Prior to joining the Company, he was employed by Stewart & Stevenson Operations and Sithe Energies, Inc. Prior to that time, Mr. Rorabaugh was with the United States Navy in San Diego, California where he served as Gas Turbine Technician. JOHN A. SCHRETLEN, 35, General Manager, Yuma Gas Operations. Mr. Schretlen joined the Company in September 1989. Prior to that, he served as Maintenance Manager for Falcon Power Operating Company, Power Resources, Inc. and Big Spring, Texas. Prior to joining CalEnergy, Mr. Schretlen was employed by Custom Equipment Rebuilders, Inc., Amerada Hess Company, Inc. and Callaway Aviation, Inc. JAMES J. SELLNER, 51, Director, Taxation. Director Taxation. Mr. Sellner joined CalEnergy in November, 1997. Prior to joining CalEnergy, Mr. Sellner was employed by Central and South West Corporation and Banc One/Mcorp. ROBERT S. SILBERMAN, 40, Senior Vice President, Administration. Mr. Silberman joined the Company in 1995. Prior to that, Mr. Silberman served as Executive Assistant to the Chairman and Chief Executive Officer of International Paper Company, as Director of Project Finance and Implementation for the Ogden Corporation and as a Project Manager in Business Development for Allied-Signal, Inc. He has also served as the Assistant Secretary of the Army for the United States Department of Defense. JAMES D. STALLMEYER, 40, General Counsel, Northern Electric and General Counsel, CalEnergy Development Company. Mr. Stallmeyer joined the Company in 1993. Mr. Stallmeyer practiced in the public finance and banking areas at Chapman and Cutler in Chicago from 1984 to 1987 and in the corporate finance department from 1989 to 1993. Prior to that, Mr. Stallmeyer was an attorney in the public finance department of the Chicago office of Skadden, Arps, Slate, Meagher & Flom in 1987 and 1988 and was a legal writing instructor at the University of Illinois College of Law in 1988 and 1989. DAVID SWAN, 53, Director, Northern Electric and Managing Director, Distribution. Mr. Swan joined Northern in 1966 and has held posts in varying disciplines including distribution, engineering design, operations, customers engineering, customer relationships, engineering contracting, logistics, computer systems development and project management. JAMES T. TURNER, 48, General Manager, Imperial Valley Geothermal Operations. Mr. Turner joined the Company as Director of Engineering & Technology for Magma Power Company in 1993. From 1974 to 1993 he held various engineering positions with The Dow Chemical Company. Those positions included Technical Manager, Engineering Manager and Physicist. DAVID A. WATERS, 55, Managing Director, Northern Utility Services. Mr. Waters joined Northern in September 1960 as a Student Apprentice. In 1982 he became a Resources Engineer and received appointments as Cleveland (Teesside) Technical Distribution System Planning Manager, Business Development Manager, later promoted to Business Services Manager and General Manager, NUSL. The following March 1998 he was appointed as Managing Director. JONATHAN M. WEISGALL, 49, Vice President, Legislative and Regulatory Affairs. Mr. Weisgall joined the Company in May 1995. Prior to that, Mr. Weisgall was an attorney in private practice with extensive energy and regulatory experience and is currently Adjunct Professor of Energy Law at Georgetown University Law Center. PETER YOUNGS, 43, Managing Director, Gas Exploration and Development. Mr. Youngs joined Neste Oy in 1974 as a Geoscientist and held the following positions within the company: International Exploration Manager, General Manager (Europe-Africa Region), Vice President and Managing Director UKEXPRO. From 1994 to present, he has been the General Manager of Sovereign Exploration Ltd. (now CalEnergy Gas (UK) Limited). PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) Financial Statements and Schedules 1. Financial Statements Filed herewith and incorporated by reference are the consolidated balance sheets of the Company and subsidiaries as of December 31, 1997 and 1996, and the consolidated statements of operations, cash flows and stockholders' equity for the years ended December 31, 1997, 1996 and 1995, and the related report of independent auditors. 2. Financial Statement Schedules Independent Auditor's Report on Schedule I, Financial Statements of the Company (Parent Company only) The consolidated Magma financial statement schedules which are excluded from the annual report to shareholders by Rule 14a- 3(b) are required by Regulation S-X (17 CFR 210) as Magma is an affiliate whose securities are pledged as collateral and are included at Item 14(d). (b) Reports on Form 8-K The Company filed a Current Report on Form 8-K dated October 9, 1997 reporting the investment grade credit rating of the Company's senior unsecured debt by Duff & Phelps Credit Rating Co. The Company filed a Current Report on Form 8-K dated October 13, 1997 reporting the pricing of its public offering of common stock. The Company filed a Current Report on Form 8-K dated October 23, 1997 reporting the consumation of its public offering of common stock and the concurrent sale of 2 million shares of common stock in a direct sale. The Company filed a Current Report on Form 8-K dated October 28, 1997 reporting the closing of the sale of $350 million aggregate principal amount of its 7.63% senior notes due 2007. The Company filed a Current Report on Form 8-K dated December 5, 1997 reporting that its indirect subsidiary, CE Electric UK Funding Company had arranged for the sale of $362 million Senior Notes and 200 million pounds Sterling Bonds. The Company filed a Current Report on Form 8-K dated December 11, 1997 reporting the increase in the authorized purchase amounts under its stock repurchase program. The Company filed a Current Report on Form 8-K dated December 16, 1997 reporting the closing of the sale of $125 million of its 6.853% Senior Notes due 2004, $237 million of its 6.995% Senior Notes due 2007 and 200 million pounds of its 7.25% Sterling Bonds due 2022. (c) Exhibits The exhibits listed on the accompanying Exhibit Index (except in the case of Exhibit 13.0, in which case only the portion of the Annual Report which constitutes the Company's Consolidated Financial Statements and notes thereto) are filed as part of this Annual Report. For the purposes of complying with the amendments to the rules governing Form S-8 effective July 13, 1990 under the Securities Act of 1933, the undersigned Registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into the Company's currently effective Registration Statements on Form S-8: Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer of controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. (d) Financial statements required by Regulations S-X, which are excluded from the Annual Report by Rule 14a-3(b). The consolidated financial statements of Magma Company and subsidiaries (financial statements of affiliates whose securities are pledged as collateral) are filed as part of this report immediately following Schedule I. 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, in the City of Omaha, State of Nebraska, on this 27th day of March, 1998. CALENERGY COMPANY, INC. /s/ David L. Sokol* By David L. Sokol Chairman of the Board and Chief Executive Officer *By: /s/ Steven A. McArthur Steven A. McArthur Attorney-in-Fact 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 Date /s/ David L. Sokol* March 27, 1998 David L. Sokol Chairman of the Board, Chief Executive Officer, and Director /s/ Gregory E. Abel* March 27, 1998 Gregory E. Abel President and Chief Operating Officer /s/ Craig M. Hammett March 27, 1998 Craig M. Hammett Senior Vice President, Chief Financial Officer /s/ Patrick J. Goodman March 27, 1998 Patrick J. Goodman Vice President, Chief Accounting Officer and Controller /s/ Edgar D. Aronson* March 27, 1998 Edgar D. Aronson Director *By:/s/ Steven A. McArthur March 27, 1998 Steven A. McArthur Attorney-in-Fact /s/ Judith E. Ayres* March 27, 1998 Judith E. Ayres Director /s/ Richard K. Davidson* March 27, 1998 Richard K. Davidson Director /s/ David H. Dewhurst* March 27, 1998 David H. Dewhurst Director /s/ Richard R. Jaros* March 27, 1998 Richard R. Jaros Director /s/ David R. Morris* March 27, 1998 David Morris Director /s/ John R. Shiner* March 27, 1998 John R. Shiner Director /s/ Bernard W. Reznicek* March 27, 1998 Bernard W. Reznicek Director /s/ Walter Scott, Jr.* March 27, 1998 Walter Scott, Jr. Director /s/ David E. Wit* March 27, 1998 David E. Wit Director *By:/s/ Steven A. McArthur March 27, 1998 Steven A. McArthur Attorney-in-Fact CalEnergy Company, Inc. Schedule I Parent Company Only Condensed Balance Sheets as of December 31, 1997 and 1996 (dollars and shares in thousands, except per share amounts) ASSETS 1997 1996 Cash and cash equivalents $ 1,280,477$ 68,449 Restricted cash 114,492 21,208 Short-term investment 421 192 Investments in and advances to subsidiaries and joint ventures 1,793,413 1,952,612 Equipment, net 19,016 9,797 Notes receivable - joint ventures --- 27,375 Deferred income taxes 25,007 --- Deferred charges and other assets 104,802 90,234 Total assets $ 3,337,628 $2,169,867 LIABILITIES AND STOCKHOLDERS' EQUITY Liabilities: Accounts payable and other accrued liabilities $ 46,964 $ 12,999 Parent company debt 1,303,845 1,146,685 Deferred income taxes --- 12,688 Total liabilities 1,350,809 1,172,372 Deferred income 12,827 12,775 Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts 553,930 103,930 Common stock and options subject to redemption 654,736 --- Stockholders' equity: Preferred stock - authorized 2,000 shares --- --- Common stock - par value $0.0675 per share, authorized 180,000 shares, issued 82,980 and 63,747 shares,outstanding 81,322 and 63,448 shares, respectively 5,602 4,303 Additional paid in capital 1,261,081 563,567 Retained earnings 213,493 297,520 Cumulative effect of foreign currency translation adjustment (3,589) 29,658 Common stock and options subject to redemption (654,736) --- Treasury stock-1,658 and 299 common shares at cost (56,525) (8,787) Unearned compensation - restricted stock --- (5,471) Total stockholders' equity 765,326 880,790 Total liabilities and stockholders' equity $3,337,628 $2,169,867 The notes to the consolidated CalEnergy financial statements are an integral part of these financial statements. CalEnergy Company, Inc. Schedule I Parent Company Only (continued) Condensed Statements Of Operations for the three years ended December 31, 1997 (dollars in thousands) 1997 1996 1995 Revenue: Equity in undistributed earnings of subsidiary companies and joint ventures $ 87,006 $ 91,528 $52,960 Cash dividends and distributions from subsidiary companies and joint ventures 156,686 102,428 88,360 Interest and other income 49,488 22,459 16,065 Total revenues 293,180 216,415 157,385 Expenses: General and administration 51,519 22,958 16,354 Interest, net of capitalized interest 67,636 54,484 46,985 Total expenses 119,155 77,442 63,339 Income before provision for income taxes 174,025 138,973 94,046 Provision for income taxes 99,044 41,821 30,631 Income before minority interest 74,981 97,152 63,415 Minority interest 23,158 4,691 --- Income before extraordinary item 51,823 92,461 63,415 Extraordinary item, net of minority interest of $58,222 (135,850) --- --- Net income (loss) (84,027) 92,461 63,415 Preferred dividends --- --- 1,080 Net income (loss) available to common stockholders $(84,027) $92,461 $62,335 Income per share before extraordinary item $ .77 $ 1.69 $ 1.32 Extraordinary item $ (2.02) $ --- $ --- Net income (loss) per share $ (1.25) $ 1.69 $ 1.32 Income per share before extraordinary item - diluted $ .75 $ 1.54 $ 1.22 Extraordinary item-diluted $ (1.97) $ --- $ --- Net income (loss) per share-diluted $ (1.22) $ 1.54 $ 1.22 Average number of shares outstanding 67,268 54,739 47,249 Diluted shares 68,686 65,072 56,195 The notes to the consolidated CalEnergy financial statements are an integral part of these financial statements. CalEnergy Company, Inc. Schedule I Parent Company Only (continued) Condensed Statements Of Cash Flows for the three years ended December 31, 1997 (dollars in thousands) 1997 1996 1995 Cash flows from operating activities $(237,752) $(51,621) $(33,469) Cash flows from investing activities: Decrease (increase) in advances to and investments in subsidiaries and joint ventures 305,563 (531,410) (747,516) Decrease (increase) in short-term investments (229) 33,998 15,810 Decrease (increase) in restricted cash (93,284) 19,423 50,274 Other 18,330 (5,179) 10,699 Cash flows from investing activities 230,380 (483,168) (670,733) Cash flows from financing activities: Proceeds from sale of common and treasury stock and exercise of stock options 703,624 54,935 299,649 Proceeds from issuance of parent company debt 350,000 324,150 200,000 Proceeds from convertible preferred securities of subsidiary trusts 450,000 103,930 --- Repayment of parent company debt (100,000) --- --- Net proceeds from revolver (95,000) 95,000 --- Purchase of treasury stock (55,505) (12,008) (1,590) Deferred charges relating to debt financing (33,719) (8,811) --- Cash flows from financing activities 1,219,400 557,196 498,059 Net increase (decrease) in cash and cash equivalents 1,212,028 22,407 (206,143) Cash and cash equivalents at beginning of period 68,449 46,042 252,185 Cash and cash equivalents at end of period $1,280,477 $ 68,449 $ 46,042 Supplemental disclosures: Interest paid (net of amount capitalized) $ 38,176 $ 1,705 $ 5,172 Income taxes paid $ 35,302 $ 23,211 $ 14,812 The notes to the consolidated CalEnergy financial statements are an integral part of these financial statements. INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders CalEnergy Company, Inc. Omaha, Nebraska We have audited the consolidated financial statements of CalEnergy Company, Inc. and subsidiaries as of December 31, 1997 and 1996, and for each of the three years in the period ended December 31, 1997, and have issued our report thereon dated February 12, 1998; such financial statements and reports are included in your 1997 Annual Report to Stockholders and are incorporated herein by reference. Our audits also included the financial statement schedule of CalEnergy Company, Inc. and subsidiaries, listed in Item 14. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Deloitte & Touche, LLP Omaha, Nebraska February 12, 1998 MAGMA POWER COMPANY AND SUBSIDIARIES (A wholly-owned subsidiary of CalEnergy Company, Inc.) INDEX TO FINANCIAL STATEMENTS The following consolidated financial statements of Magma Power Company and the related independent accountants' reports are included in Items 14(d): Independent Auditors' Report--Deloitte & Touche LLP F-2 Consolidated balance sheets at December 31, 1997 and 1996 F-3 Consolidated statements of operations for the three years ended December 31, 1997 F-4 Consolidated statements of stockholder's equity for the three years ended December 31, 1997 F-5 Consolidated statements of cash flows for the three years ended December 31, 1997 F-6 Notes to consolidated financial statements F-7 All schedules have been omitted because they are not applicable or not required, or because the required information is shown in the consolidated financial statements or notes thereto. INDEPENDENT AUDITORS' REPORT Board of Directors and Shareholder Magma Power Company Omaha, Nebraska We have audited the accompanying consolidated balance sheets of Magma Power Company and subsidiaries, a wholly-owned subsidiary of CalEnergy Company, Inc., as of December 31, 1997 and 1996 the related consolidated statements of operations, stockholder's equity and cash flows for the years then ended. 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 generally accepted auditing standards. 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, such consolidated financial statements present fairly, in all material respects, the financial position of Magma Power Company and subsidiaries at December 31, 1997 and 1996 and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. Deloitte & Touche LLP Omaha, Nebraska February 12, 1998 MAGMA POWER COMPANY AND SUBSIDIARIES (A wholly-owned subsidiary of CalEnergy Company, Inc.) CONSOLIDATED BALANCE SHEETS as of December 31, 1997 and 1996 dollars and shares in thousands except per share amounts ASSETS 1997 1996 Cash and cash equivalents $ 14,051 $ 13,429 Restricted cash 51,835 23,695 Accounts receivable 57,411 44,966 Due from parent 80,924 68,694 Properties, plants, contracts and equipment, net 1,207,605 1,225,684 Excess of cost over fair value of net assets acquired, net 291,303 299,055 Deferred charges and other assets 69,788 62,874 Total assets $1,772,917 $1,738,397 LIABILITIES AND STOCKHOLDER'S EQUITY Liabilities: Accounts payable and other accrued liabilities $ 32,773 $ 52,281 Construction and project loans 176,657 137,881 Salton Sea notes and bonds 448,754 538,982 Limited recourse senior secured notes 200,000 200,000 Deferred income taxes 228,246 210,969 Total liabilities 1,086,430 1,140,113 Deferred income 12,396 --- Commitments and contingencies (Note 9) Stockholder's equity: Preferred stock - par value $0.10 per share, authorized 1,000 shares --- --- Common stock - par value $0.10 per share, authorized 30,000 shares, outstanding 100 shares --- --- Additional paid in capital 501,626 501,626 Retained earnings 172,465 96,658 Total stockholder's equity 674,091 598,284 Total liabilities and stockholder's equity$1,772,917 $1,738,397 The accompanying notes are an integral part of these financial statements. MAGMA POWER COMPANY AND SUBSIDIARIES (A wholly-owned subsidiary of CalEnergy Company, Inc.) CONSOLIDATED STATEMENTS OF OPERATIONS for the three years ended December 31, 1997 dollars in thousands 1997 1996 1995 Revenue: Sales of electricity and steam $ 328,248 $ 249,293 $ 162,418 Royalty income 3,489 6,846 19,962 Interest and other income 3,978 9,368 17,812 Total revenues 335,715 265,507 200,192 Cost and expenses: Plant operations 72,196 67,350 57,782 General and administration 1,380 503 3,282 Depreciation and amortization 89,134 69,853 46,895 Interest expense 72,386 67,652 60,596 Less interest capitalized (20,549) (27,382) (24,568) Total expenses 214,547 177,976 143,987 Income before provision for income taxes and minority interest 121,168 87,531 56,205 Provision for income taxes 45,361 25,489 17,498 Income before minority interest 75,807 62,042 38,707 Minority interest --- --- 4,091 Net income $75,807 $62,042 $34,616 The accompanying notes are an integral part of these financial statements. MAGMA POWER COMPANY AND SUBSIDIARIES (A wholly-owned subsidiary of CalEnergy Company, Inc.) CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY for the three years ended December 31, 1997 dollars and shares in thousands Outstanding Additional Common Common Paid-In Retained Shares Stock Capital Earnings Total Balance, January 1, 1995 24,117 $ 2,411 $ 144,916 $ 242,489 $ 389,816 Net income in 1995 prior to acquisition --- --- --- 4,091 4,091 Purchase accounting push-down adjustments, net (24,049) (2,415) 332,857 (246,580) 83,862 Contributions from parent --- --- 22,947 --- 22,947 Other equity transactions, net 32 4 906 --- 910 Net income --- --- --- 34,616 34,616 Balance, December 31, 1995 100 --- 501,626 34,616 536,242 Net income --- --- --- 62,042 62,042 Balance, December 31, 1996 100 --- 501,626 96,658 598,284 Net income --- --- --- 75,807 75,807 Balance, December 31, 1997 100 $ --- $501,626 $ 172,465 $ 674,091 The accompanying notes are an integral part of these financial statements. MAGMA POWER COMPANY AND SUBSIDIARIES (A wholly-owned subsidiary of CalEnergy Company, Inc.) CONSOLIDATED STATEMENTS OF CASH FLOWS for the three years ended December 31, 1997 Dollars in thousands 1997 1996 1995 Cash flows from operating activities: Net income $ 75,807$ 62,042 $ 34,616 Adjustments to reconcile net cash flows from operating activities: Minority interest --- --- 4,091 Provision for deferred income taxes 17,277 7,277 7,614 Depreciation and amortization 89,134 69,853 46,895 Changes in other items: Accounts receivable (12,445) (7,735) 4,354 Accounts payable and other accrued liabilities (19,508) 3,325 14,153 Net cash flows from operating activities 150,265 134,762 111,723 Cash flows from investing activities: Capital expenditures (50,907)(190,152) (171,063) Purchase of Partnership Interest, net of cash acquired --- (58,044) --- Purchase of Magma, net of cash acquired --- --- (907,614) Decrease (increase) in restricted cash (28,140) 59,071 (4,785) Increase in other assets (6,914) (3,345) (24,037) Net cash flows from investing activities (85,961)(192,470)(1,107,499) Cash flows from financing activities: Due from parent (12,230) (53,203) (29,669) Proceeds from debt offerings --- 135,000 675,000 Repayment of Salton Sea notes and bonds (90,228) (48,106) (22,912) Repayment of project loans --- (102,999) (124,839) Proceeds from construction and other loans 38,776 101,018 36,863 Other equity transactions, net --- --- 910 Advances from parent --- --- 499,850 Net cash flows from financing activities (63,682) 31,710 1,035,203 Net increase (decrease) in cash and cash equivalents 622 (25,998) 39,427 Cash and cash equivalents at beginning of period 13,429 39,427 --- Cash and cash equivalents at end of period $ 14,051 $ 13,429 $ 39,427 Interest paid (net of amounts capitalized) $ 50,802 $ 49,129 $ 50,840 Income taxes paid $ --- $ --- $ 14,812 The accompanying notes are an integral part of these financial statements. MAGMA POWER COMPANY AND SUBSIDIARIES (A wholly-owned subsidiary of CalEnergy Company, Inc.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for the three years ended December 31, 1997 dollars and shares in thousands 1. BUSINESS Magma Power Company (the "Company" or "Magma"), a wholly-owned subsidiary of CalEnergy Company, Inc. (CalEnergy), is primarily engaged in the exploration for and development of geothermal resources and conversion of such resources into electrical power and steam for sale to electric utilities, and the development of other environmentally responsible forms of power generation. The Company currently operates eight geothermal power plants in the Imperial Valley in California. On April 17, 1996 the Company completed the acquisition of Edison Mission Energy's partnership interests (the "Partnership Interest Acquisition") in four geothermal operating facilities in California for a cash purchase price of $71,000 including acquisition costs. The four projects, Vulcan, Hoch (Del Ranch), Leathers and Elmore are located in the Imperial Valley of California. Prior to this transaction, the Company was a 50% owner of these facilities. The remaining four plants are the Salton Sea Project which are wholly-owned by subsidiaries of the Company. These geothermal power plants consist of the Salton Sea I, Salton Sea II, Salton Sea III, and Salton Sea IV. The Salton Sea IV project commenced operations in June 1996. In 1995 the Company, through its wholly-owned subsidiary, Visayas Geothermal Power Company ("VGPC"), began construction of the Malitbog Geothermal Project on the island of Leyte in the Republic of the Philippines. Unit I was deemed complete on July 25, 1996. Units II and III were deemed complete on July 25, 1997. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Prior to the Partnership Interest Acquisition, the consolidated financial statements include the Company's proportionate share of the joint ventures in which it had an undivided interest in the assets and was proportionately liable for its share of liabilities. All significant inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company's proportionate share of the results of operations of entities acquired as of the date of acquisition. The consolidated financial statements reflect the acquisition by CalEnergy and the resulting push down to the Company of the accounting as a purchase business combination. Restricted Cash The restricted cash balance is mainly composed of restricted accounts for debt service reserve funds and a capital expenditure fund. The debt service reserve funds are legally restricted to their use and require the maintenance of specific minimum balances. Well, Resource Development and Exploration Costs The Company follows the full cost method of accounting for costs incurred in connection with the exploration and development of geothermal resources. All such costs, which include dry hole costs and the cost of drilling and equipping production wells and directly attributable administrative and interest costs, are capitalized and amortized over their estimated useful lives when production commences. The estimated useful lives of production wells are ten to twenty years depending on the characteristics of the underlying resource; exploration costs and development costs, other than production wells, are generally amortized over the weighted average remaining term of the Company's power and steam purchase contracts. Deferred Well and Rework Costs Well rework costs are deferred and amortized over the estimated period between reworks. These deferred costs, net of accumulated amortization, are $4,811 and $7,664 at December 31, 1997 and 1996, respectively, and are included in other assets. Properties, Plants, Contracts, Equipment and Depreciation The cost of major additions and betterments are capitalized, while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed. Depreciation of the operating power plant costs, net of salvage value, is computed on the straight line method over the estimated useful lives, between 10 and 30 years. Depreciation of furniture, fixtures and equipment, which are recorded at cost, is computed on the straight line method over the estimated useful lives of the related assets, which range from three to ten years. The Magma and Partnership Interest Acquisitions by the Company have been accounted for as purchase business combinations. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring the respective companies, equal to their fair values at the date of the acquisition and include the following: Power sales agreements are amortized separately over (1) the remaining portion of the scheduled price periods of the power sales agreements and (2) the 20 year avoided cost periods of the power sales agreements using the straight line method. The carrying value of the mineral reserves will be amortized upon commencement of commercial operation. Excess of Cost over Fair Value Total acquisition costs in excess of the fair values assigned to the net assets acquired are amortized over a 40 year period using the straight line method. Capitalization of Interest and Deferred Financing Costs Prior to the commencement of operations, interest is capitalized on the costs of the plants and geothermal resource development to the extent incurred. Capitalized interest and other deferred charges are amortized over the lives of the related assets. Deferred financing costs are amortized over the term of the related financing using the effective interest method. Revenue Recognition Revenues are recorded based upon service rendered and electricity and steam delivered to the end of the month. See Note 4 for contractual terms of power sales agreements. Royalties earned from providing geothermal resources to power plants operated by other geothermal power producers are recorded on an accrual basis. Prior to the Partnership Interest Acquisition, royalties contractually payable to the Company by the Partnership Project were recorded on an accrual basis, net of the Company's 50% share of the corresponding partnership project expense. All intercompany royalties were eliminated after the acquisition of the remaining 50% partnership interest. Income Taxes The Company is included in the consolidated income tax returns of CalEnergy and affiliates. The provision for income taxes is computed on a separate return basis. The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax bases of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. Fair Values of Financial Instruments The following methods and assumptions were used by the Company in estimating fair values of financial instruments as discussed herein. Fair values have been estimated based on quoted market prices for debt issues listed on exchanges. Fair values of financial instruments that are not actively traded are based on market prices of similar instruments and/or valuation techniques using market assumptions. Cash Equivalents The Company considers all investment instruments purchased with an original maturity of three months or less to be cash equivalents. Restricted cash is not considered a cash equivalent. Impairment of Long-Lived Assets The Company reviews long-lived assets and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized whenever evidence exists that the carrying value is not recoverable. Reclassification Certain amounts in the fiscal 1996 and 1995 financial statements and supporting footnote disclosures have been reclassified to conform to the fiscal 1997 presentation. Such reclassification did not impact previously reported net income or retained earnings. 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. 3. ACQUISITIONS Magma Power Company On January 10, 1995, CalEnergy acquired approximately 51% of the outstanding shares of common stock of the Company through a cash tender offer and completed the acquisition on February 24, 1995 by acquiring the remaining 49% of outstanding shares of common stock through a merger (the "Magma Acquisition"). The Magma Acquisition has been accounted for as a purchase business combination. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring Magma, equal to their fair values at the date of the acquisition. Edison Mission Energy's Partnership Interest On April 17, 1996 the Company completed the acquisition of Edison Mission Energy's partnership interests (the "Partnership Interest Acquisition") in four geothermal operating facilities in California for a cash purchase price of $71,000 including acquisition costs. The four projects, Vulcan, Hoch (Del Ranch), Leathers and Elmore are located in the Imperial Valley of California. Prior to this transaction, the Company was a 50% owner of these facilities. The Partnership Interest Acquisition has been accounted for as a purchase business combination. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring the Partnership Interest, equal to their fair values at the date of the acquisition. Unaudited pro forma combined revenue and net income of the Company and the Partnership Interest for the twelve months ended December 31, 1996 and 1995, as if the acquisition had occurred at the beginning of 1995 after giving effect to certain pro forma adjustments related to the acquisition were $284,193 and $63,135 compared to $291,812 and $52,477, respectively. 4. PROPERTIES, PLANTS, CONTRACTS AND EQUIPMENT Properties, plants, contracts and equipment comprise the following at December 31: 1997 1996 Power plants $741,853 $557,006 Wells and resource development 124,500 114,492 Power sales agreements 264,371 264,371 Licenses and equipment 46,290 46,290 Total operating facilities 1,177,014 982,159 Less accumulated depreciation and amortization (185,085) (103,702) Net operating facilities 991,929 878,457 Mineral reserves 211,674 189,198 Construction in progress: Malitbog --- 155,410 Other development 4,002 2,619 Total $1,207,605 $1,225,684 Imperial Valley Project Operating Facilities The Partnership Project and the Salton Sea Project are collectively referred to as the Imperial Valley Project. The Imperial Valley Project commencement dates and nominal capacities are as follows: Imperial Valley Commencement Nominal Plants Date Capacity Vulcan February 10, 1986 34 MW Del Ranch January 2, 1989 38 MW Elmore January 1, 1989 38 MW Leathers January 1, 1990 38 MW Salton Sea I July 1, 1987 10 MW Salton Sea II April 5, 1990 20 MW Salton Sea III February 13, 1989 49.8 MW Salton Sea IV May 24, 1996 39.6 MW Significant Customers and Contracts All of the Company's sales of electricity from the Imperial Valley Project, which comprise approximately 82% of 1997 electricity and steam revenues, are to Southern California Edison Company ("Edison") and are under long-term power purchase contracts. The Partnership Project sells all electricity generated by the respective plants pursuant to four long-term SO4 Agreements between the project and Edison. These SO4 Agreements provide for capacity payments, capacity bonus payments and energy payments. Edison makes fixed annual capacity and capacity bonus payments to the projects to the extent that capacity factors exceed certain benchmarks. The price for capacity and capacity bonus payments is fixed for the life of the SO4 Agreements. Energy is sold at increasing scheduled rates for the first ten years after firm operation and thereafter at Edison's Avoided Cost of Energy. The scheduled energy price periods of the Partnership Project SO4 Agreements extended until February 1996 for the Vulcan Partnership and extend until December 1998, December 1998, and December 1999 for each of the Del Ranch, Elmore and Leathers Partnerships, respectively. Excluding Vulcan, which is receiving Edison's Avoided Cost of Energy, the Company's SO4 Agreements provide for energy rates ranging from 13.6 cents per kWh in 1997 to 15.6 cents per kWh in 1999. The weighted average energy rate for all of the Company's SO4 Agreements was 10.0 cents per kWh in 1997. Salton Sea I sells electricity to Edison pursuant to a 30-year negotiated power purchase agreement, as amended (the "Salton Sea I PPA"), which provides for capacity and energy payments. The energy payment is calculated using a Base Price which is subject to quarterly adjustments based on a basket of indices. The time period weighted average energy payment for Salton Sea I was 5.3 cents per kWh during 1997. As the Salton Sea I PPA is not an SO4 Agreement, the energy payments do not revert to Edison's Avoided Cost of Energy. The capacity payment is approximately $1,100 per annum. Salton Sea II and Salton Sea III sell electricity to Edison pursuant to 30-year modified SO4 Agreements that provide for capacity payments, capacity bonus payments and energy payments. The price for contract capacity and contract capacity bonus payments is fixed for the life of the modified SO4 Agreements. The energy payments for the first ten year period, which period expires in April 2000 and February 1999 are levelized at a time period weighted average of 10.64 per kWh and 9.84 per kWh for Salton Sea II and Salton Sea III, respectively. Thereafter, the monthly energy payments will be Edison's Avoided Cost of Energy. For Salton Sea II only, Edison is entitled to receive, at no cost, 5% of all energy delivered in excess of 80% of contract capacity through September 30, 2004. The annual capacity and bonus payments for Salton Sea II and Salton Sea III are approximately $3,300 and $9,700, respectively. Salton Sea IV sells electricity to Edison pursuant to a modified SO4 agreement which provides for contract capacity payments on 34 MW of capacity at two different rates based on the respective contract capacities deemed attributable to the original Salton Sea PPA option (20 MW) and to the original Fish Lake PPA (14 MW). The capacity payment price for the 20 MW portion adjusts quarterly based upon specified indices and the capacity payment price for the 14 MW portion is a fixed levelized rate. The energy payment (for deliveries up to a rate of 39.6 MW) is at a fixed price for 55.6% of the total energy delivered by Salton Sea IV and is based on an energy payment schedule for 44.4% of the total energy delivered by Salton Sea IV. The contract has a 30-year term but Edison is not required to purchase the 20 MW of capacity and energy originally attributable to the Salton Sea I PPA option after September 30, 2017, the original termination date of the Salton Sea I PPA. For the year ended December 31, 1997 and 1996, Edison's average Avoided Cost of Energy was 3.3 cents and 2.5 cents per kWh, respectively, which is substantially below the contract energy prices earned for the year ended December 31, 1997. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year. The Company cannot predict the likely level of Avoided Cost of Energy prices under the SO4 Agreements and the modified SO4 Agreements at the expiration of the scheduled payment periods. The revenues generated by each of the projects operating under SO4 Agreements could decline significantly after the expiration of the respective scheduled payment periods. Subsidiaries of Magma sought new long-term final SO4 power purchase agreements in the Salton Sea area through the bidding process adopted by the California Public Utilities Commission ("CPUC") under its 1992 Biennial Resource Plan Update ("BRPU"). In its BRPU, the CPUC cited the need for an additional 9,600 MW of power production through 1999 among California's three investor-owned utilities, Edison, San Diego Gas and Electric ("SDG&E") and Pacific Gas and Electric Company. Of this amount, 275 MW was set aside for bidding by independent power producers (such as Magma) utilizing renewable resources. Pursuant to an order of the CPUC dated June 22, 1994 (confirmed on December 21, 1994), Magma was awarded 163 net MW for sale to Edison and SDG&E, with in-service dates in 1997 and 1998. On February 23, 1995 the Federal Energy Regulatory Commission ("FERC") issued an order finding that the CPUC's BRPU program violated the Public Utilities Regulatory Policies Act ("PURPA") and FERC's implementing regulations and recommended negotiated settlements. In response, the CPUC issued an Assigned Commissioners Ruling encouraging settlements between the final winning bidders and the utilities. The utilities are expected to continue to challenge the BRPU and, in the light of the regulatory uncertainty, there can be no assurance that power sales contracts will be executed or that any such projects will be completed. In light of these developments, the Company agreed to execute an agreement with Edison on March 16, 1995 providing that in certain circumstances it would withdraw its Edison BRPU bid in consideration for the payment of certain sums. In December, 1996, the Company entered into a confidential cash buyout agreement with SDG&E. These agreements are subject to CPUC approval. Unit I of the Malitbog Project was deemed complete in July 1996 and Units II and III in July 1997 at which times such units commenced receiving capacity payments under the Malitbog Energy Conversion Agreement ("ECA"). The Malitbog Project is owned and operated by VGPC, a Philippine general partnership that is wholly owned, indirectly, by the Company. The Malitbog Project is structured as a ten year Build- Own-Operate-Transfer ("BOOT") project, in which the Company is responsible for providing operations and maintenance for the ten year BOOT period. The electricity generated by the Malitbog Project is sold to PNOC-Energy Development Corporation ("PNOC-EDC"), which will in turn sell the power to the National Power Corporation of the Philippines ("NPC"). After a ten year cooperation period, and the recovery by the Company of its capital investment plus incremental return, the plant will be transferred to PNOC-EDC at no cost. PNOC-EDC is obligated to pay for electric capacity that is nominated each year by VGPC, irrespective of whether PNOC-EDC is willing or able to accept delivery of such capacity. VGPC receives 100% of its revenues from such sales in the form of capacity payments. Payments under the Malitbog ECA are denominated in U.S. Dollars, or computed in U.S. dollars and paid in Philippine pesos at the then-current exchange rate. Significant portions of the capacity fee are indexed to U.S. and Philippine inflation rates, respectively. PNOC-EDC's payment requirements, and its other obligations under the Malitbog ECA are supported by the Government of the Philippines through a performance undertaking. Royalties Royalty expense for the years ended December 31, 1997, 1996 and 1995, which is included in plant operations in the consolidated statements of operations, comprise the following: 1997 1996 1995 Vulcan $ 326 $ 361 $ 1,207 Leathers 2,694 2,203 1,968 Elmore 2,213 1,883 1,713 Del Ranch 2,650 2,255 1,932 Salton Sea I & II 1,206 634 1,147 Salton Sea III 2,439 1,334 2,431 Salton Sea IV 2,815 1,558 - Total $14,343 $10,228 $10,398 The Partnership Project pays royalties based on both energy revenues and total electricity revenues. Hoch (Del Ranch) and Leathers pay royalties of approximately 5% of energy revenues and 1% of total electricity revenue. Elmore pays royalties of approximately 5% of energy revenues. Vulcan pays royalties of 4.167% of energy revenues. The Salton Sea Project's weighted average royalty expense in 1997 was approximately 6.1%. The royalties are paid to numerous recipients based on varying percentages of electrical revenue or steam production multiplied by published indices. 5. CONSTRUCTION LOANS Draws on the construction loan for the Malitbog geothermal power project at December 31, 1997 totaled $176,657. International banks and the Overseas Private Investment Corporation ("OPIC") have provided the construction and term loan facilities at variable interest rates (weighted average of 8.48% and 8.15% at December 31, 1997 and 1996, respectively). The international bank portion of the debt will be insured by OPIC against political risks and the Company's equity contribution to VGPC is covered by political risk insurance from the Multilateral Investment Guarantee Agency and OPIC. The construction loan is expected to be converted to a term loan promptly after NPC completes the full capacity transmission line, which is currently expected in 1998. 6. NOTES AND BONDS Each of the Company's direct or indirect subsidiaries is organized as a legal entity separate and apart from the Company and its other subsidiaries. Pursuant to separate project financing agreements, the assets of each subsidiary are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any such subsidiary will be available to satisfy the obligations of the Company or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to the Company or affiliates thereof. "Subsidiaries" means all of the Company's direct or indirect subsidiaries (1) owning interests in the Imperial Valley and Malitbog projects or (2) owning interests in the subsidiaries that own interests in the foregoing projects. Salton Sea Notes and Bonds The Salton Sea Funding Corporation, a wholly owned subsidiary of the Company, (the "Funding Corporation") debt securities are as follows: Final Maturity December 31, December 31, Senior Secured Series Date Rate 1997 1996 July 21, 1995 A Notes May 30, 2000 6.69% $ 97,354 $ 161,732 July 21, 1995 B Bonds May 30, 2005 7.37% 133,000 133,000 July 21, 1995 C Bonds May 30, 2010 7.84% 109,250 109,250 June 20, 1996 D Notes May 30, 2000 7.02% 44,150 70,000 June 20, 1996 E Bonds May 30, 2011 8.30% 65,000 65,000 $448,754 $538,982 Principal and interest payments are made in semi-annual installments. The Salton Sea Notes and Bonds are secured by the Company's four existing Salton Sea plants as well as an assignment of the right to receive various royalties payable to Magma in connection with its Imperial Valley properties and distributions from the Partnership Project. The Salton Sea Notes and Bonds are nonrecourse to CalEnergy. Pursuant to a depository agreement, Funding Corporation established a debt service reserve fund in the form of a letter of credit in the amount of $70,430 from which scheduled interest and principal payments can be made. Annual repayments of the Salton Sea Notes and Bonds for the years beginning January 1, 1998 and thereafter are as follows: 1998 $106,938 1999 57,836 2000 25,072 2001 22,376 2002 24,298 Thereafter 212,234 $448,754 On July 21, 1995, CalEnergy issued $200,000 of 9 7/8% Limited Recourse Senior Secured Notes Due 2003 (the "Notes"). Interest on the Notes is payable on June 30 and December 30 of each year, commencing December 1995. The Notes are secured by an assignment and pledge of 100% of the outstanding capital stock of Magma and are recourse only to such Magma capital stock, CalEnergy's interest in a secured Magma note and general assets of CalEnergy equal to the Restricted Payment Recourse Amount (as defined in the Note Indenture) which was $0 at December 31, 1997. At any time or from time to time on or prior to June 30, 1998, CalEnergy may, at its option, use all or a portion of the net cash proceeds of a CalEnergy equity offering (as defined in the Note Indenture) and shall at any time use all of the net cash proceeds of any Magma equity offering (as defined in the Note Indenture) to redeem up to an aggregate of 35% of the principal amount of the Notes originally issued at a redemption price equal to 109.875% of the principal amount thereof plus accrued interest to the redemption date. On or after June 30, 2000, the Notes are redeemable at the option of the CalEnergy, in whole or in part, initially at a redemption price of 104.9375% declining to 100% on June 30, 2002 and thereafter, plus accrued interest to the date of redemption. 7. INCOME TAXES Provision for income tax is comprised of the following at December 31: 1997 1996 1995 Currently payable: State $ 7,488 $ 6,420 $ 2,228 Federal 20,596 11,792 7,656 28,084 18,212 9,884 Deferred: State 1,342 1,232 924 Federal 15,207 4,908 6,690 Foreign 728 1,137 --- 17,277 7,277 7,614 Total $45,361 $25,489 $17,498 The deferred expense is primarily temporary differences associated with depreciation and amortization of certain assets. A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows: 1997 1996 1995 Federal statutory rate 35.00% 35.00% 35.00% Percentage depletion in excess of cost depletion (4.30) (5.15) (6.44) Investment and energy tax credits (.84) (12.30) (2.05) State taxes, net of federal tax effect 4.74 4.26 4.34 Goodwill amortization 2.24 3.10 4.99 Tax effect of foreign income .60 1.30 --- Lease investment --- --- (3.88) Other --- 2.91 (.83) 37.44% 29.12% 31.13% Deferred tax liabilities (assets) are comprised of the following at December 31: 1997 1996 Depreciation and amortization, net $249,622 $249,453 Unremitted foreign earnings 14,112 --- Other 77 788 263,811 250,241 Accruals not currently deductible for tax purposes (2,304) --- Tax credits (19,692) (33,407) Jr. SO4 royalty receivable (5,865) (5,865) Deferred income (7,588) --- Other (116) --- (35,565) (39,272) Net deferred taxes $228,246 $210,969 8. FAIR VALUE OF FINANCIAL INSTRUMENTS The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Although management uses its best judgment in estimating the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair value estimates presented herein are not necessarily indicative of the amounts which the Company could realize in a current transaction. The methods and assumptions used to estimate fair value are as follows: Debt instruments - The fair value of all debt issues listed on exchanges has been estimated based on the quoted market prices. Other financial instruments - All other financial instruments of a material nature fall into the definition of short-term and fair value is estimated as the carrying amount. The carrying amounts in the table below are included in the consolidated balance sheets under the indicated captions. 1997 1996 Estimated Estimated Carrying Fair Carrying Fair Value Value Value Value Construction and project loans 176,657 176,657 137,881 137,881 Salton Sea notes and bonds 448,754 463,720 538,982 531,807 Limited recourse senior secured notes 200,000 217,829 200,000 212,560 9. LITIGATION As of December 31, 1997 there were no material outstanding lawsuits. EXHIBIT INDEX 3.1 The Company's Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of the Company's Form 10-K for the year ended December 31, 1992, File No. 1-9874 (the "1992 Form 10- K")). 3.2 Certificate of Amendment of the Company's Restated Certificate of Incorporation, dated June 23, 1993 (incorporated by reference to the Company's Form 8-A, dated July 28, 1993, File No. 1-9874 ("Form 8-A")). 3.3 Certificate of Amendment of the Company's Restated Certificate of Incorporation dated, February 23, 1995 (incorporated by reference to Exhibit 3.3 to the Company's Form 10-K/A Amendment (dated March 31, 1995) to the Company's Form 10-K for the year ended December 31, 1994, File No. 1-9874 (the "1994 Form 10-K")). 3.4 Certificate of Ownership and Merger, effective March 26, 1996. (incorporated by reference to Exhibit 3.4 of the Company's Form 10- K for the year ended December 31, 1995, File No. 1-9874 (the 1995 Form 10-K")). 3.5 Certificate of Amendment to the Company's Restated Certificate of Incorporation dated May 19, 1997. 3.6 The Company's By-Laws as amended through February 21, 1997 (incorporated by reference to Exhibit 3.6 of the Company's Form 10- K for the year ended December 31, 1996, File No. 1-9874 (the "1996 Form 10-K")). 4.1 Specimen copy of form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Form 10-K for the year ended December 31, 1993, File No. 1-9874 (the "1993 Form 10-K")). 4.2 Shareholders Rights Agreement between the Company and Manufacturers Hanover Trust Company of California dated December 1, 1988 (incorporated by reference to Exhibit 1 to Company's Form 8-K dated December 5, 1988, File No. 1-9874). 4.3 Amendment Number 1 to Shareholder Rights Agreement, dated February 15, 1991 (incorporated by reference to Exhibit 4.2 to the Company's 1992 Form 10-K). 4.4 Escrow Deposit Agreement between Bank of American National Trust and Savings Association and the Company dated March 3, 1994 (incorporated by reference to Exhibit 4.7 to the Company's 1993 Form 10-K). 10.1 Joint Venture Agreement for China Lake Joint Venture between the Company and Caithness Geothermal 1980 Ltd., restated as of January 1, 1984 (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1, 33-7770). 10.2 Amended Joint Venture Agreement for Coso Land Company between the Company and Caithness Geothermal 1980 Ltd., dated as of June 1, 1983 (incorporated by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1, 33-7770). 10.3 Amended General Partnership Agreement for Coso Finance Partners between China Lake Operating Company and ESCA I L.P. dated July 13, 1988 (incorporated by reference to Exhibit 10.3 to the Company's 1992 Form 10-K). 10.4 First Supplemental Amendment to the Amended and Restated General Partnership Agreement for Coso Finance Partners between China Lake Operating Company and ESCA L.P. (Undated) (incorporated by reference to Exhibit 10.4 to the Company's 1992 Form 10-K). 10.5 Second Supplemental Amendment to the Amended and Restated General Partnership Agreement for Coso Finance Partners between China Lake Operating Company and ESCA L.P. dated as of July 13, 1988 (incorporated by reference to Exhibit 10.5 to the Company's 1992 Form 10-K). 10.6 Third Supplemental Amendment to the Amended and Restated General Partnership Agreement for Coso Finance Partners between China Lake Operating Company and ESCA L.P. dated as of December 16, 1992 (incorporated by reference to Exhibit 10.6 to the Company's 1992 Form 10-K). 10.7 General Partnership Agreement for Coso Finance Partners II between China Lake Geothermal Management Company and ESCA II L.P. dated July 7, 1987 (incorporated by reference to Exhibit 10.7 to the Company's 1992 Form 10-K). 10.8 Restated General Partnership Agreement for Coso Energy Developers between Coso Hotsprings Intermountain Power Inc. and Caithness Coso Holdings L.P. dated as of March 31, 1988 (incorporated by reference to Exhibit 10.8 to the Company's 1992 Form 10-K). 10.9 First Amendment to the Restated General Partnership Agreement for Coso Energy Developers between Coso Hotsprings Intermountain Power, Inc. and Caithness Coso Holdings, L.P. dated as of March 31, 1988 (incorporated by reference to Exhibit 10.9 to the Company's 1992 Form 10-K). 10.10 Second Amendment to the Restated General Partnership Agreement for Coso Energy Developers between Coso Hotsprings Intermountain Power, Inc. and Caithness Coso Holdings L.P. dated as of December 16, 1992 (incorporated by reference to Exhibit 10.10 to the Company's 1992 Form 10-K). 10.11 Amended and Restated General Partnership Agreement for Coso Power Developers between Coso Technology Corporation and Caithness Navy II Group L.P. dated July 31, 1989 (incorporated by reference to Exhibit 10.11 to the Company's 1992 Form 10-K). 10.12 First Amendment to the Amended and Restated General Partnership for Coso Power Developers between Coso Technology Corporation and Caithness Navy II Group L.P. dated as of March 19, 1991 (incorporated by reference to Exhibit 10.12 to the Company's 1992 Form 10-K). 10.13 Second Amendment to the Amended and Restated General Partnership Agreement for Coso Power Developers between Coso Technology Corporation and Caithness Navy II Group L.P. dated as of December 16, 1992 (incorporated by reference to Exhibit 10.13 to the Company's 1992 Form 10-K). 10.14 Form of Amended and Restated Field Operation and Maintenance Agreement between Coso Joint Ventures and the Company dated as of December 16, 1992 (incorporated by reference to Exhibit 10.14 of the Company's 1992 Form 10-K). 10.15 Form of Amended and Restated Project Operation and Maintenance Agreement between Coso Joint Venture and the Company dated as of December 16, 1992 (incorporated by reference to Exhibit 10.15 to the Company's 1992 Form 10-K). 10.16 Trust Indenture between Coso Funding Corp. and Bank of America National Trust and Savings Association dated as of December 16 1992 (incorporated by reference to Exhibit 10.16 to the Company's 1992 Form 10-K). 10.17 Form of Amended and Restated Credit Agreement between Coso Funding Corp. and Coso Joint Ventures dated as of December 16, 1992 (incorporated by reference to Exhibit 10.17 to the Company's 1992 Form 10-K). 10.18 Form of Support Loan Agreement among Coso Joint Ventures dated December 16, 1992 (incorporated by reference to Exhibit 10.18 to the Company's 1992 Form 10-K). 10.19 Form of Project Loan Pledge Agreement between Coso Joint Ventures and Bank of America National Trust and Savings dated as of December 16, 1992 (incorporated by reference to Exhibit 10.19 to the Company's 1992 Form 10-K). 10.20 Power Purchase Contracts between Southern California Edison Company and: (a) China Lake Joint Venture, executed June 4, 1984 with a term of 24 years; (b) China Lake Joint Venture, executed February 1, 1985 with a term of 23 years; and (c) Coso Geothermal Company, executed February 1, 1985 with a term of 30 years (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1, 33- 7770). 10.21 Contract No. N62474-79-C-5382 between the United States of America and China Lake Joint Venture, restated October 19, 1983 as "Modification P00004," including modifications through "Modification P00026", dated December 16, 1992 (the "Navy Contract")(incorporated by reference to Exhibit 10.21 to the Company's 1992 Form 10-K). 10.22 Modification to Contract No. P00028, dated June 28, 1993, Modification to Contract No. P00029, dated October 4, 1994 and Modification to Contract No. P00031, dated December 19, 1994 all amending the Navy Contract "(incorporated by reference to Exhibit 10.22 to the Company's 1994 Form 10-K)." 10.23 Lease between the BLM and Coso Land Company, effective November 1, 1985 (with Designation of Geothermal Operator) (incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1, 33-7770). 10.24 1996 Employee Stock Option Plan, as amended (incorporated by reference to Exhibit A to the Company's 1996 Proxy Statement). 10.25 1994 Employee Stock Purchase Plan (incorporated by reference to Exhibit A to the Company's 1994 Proxy Statement). 10.26 Indenture between the Company and The Chemical Trust Company of California dated as of June 24, 1993 (incorporated by reference to the Company's Form 8-K dated June 24, 1993, File No. 1-9874). 10.27 Registration Rights Agreement among the Company, Lehman Brothers, Inc. and Alex Brown & Sons Incorporated dated June 24, 1993 (incorporated by reference to the Company's Form 8-K dated June 24, 1993, File No. 1-9874). 10.28 Indenture dated March 24, 1994 between the Company and IBJ Schroder Bank and Trust Company (incorporated by reference to Exhibit 3 to the Company's Form 8-K dated March 28, 1994). 10.29 Amended and Restated Employment Agreement between the Company and David L. Sokol dated as of August 21, 1995 (incorporated by reference to Exhibit 10.82 to the Company's 1995 Form 10-K). 10.30 Restricted Stock Exchange Agreement between the Company and David L. Sokol dated as of November 29, 1995 (incorporated by reference to Exhibit 10.43 to the Company's 1995 Form 10-K). 10.31 Amendment No. 1 to the Amended and Restated Employment Agreement between the Company and David L. Sokol, dated August 28, 1996 (incorporated by reference to Exhibit 10.43 to the Company's 1996 Form 10-K). 10.32 Amendment No. 2 to the Amended and Restated Employment Agreement between the Company and David L. Sokol dated April 16, 1997. 10.33 Employment Agreement between the Company and Gregory E. Abel, dated August 6, 1996 (incorporated by reference to Exhibit 10.44 to the Company's 1996 Form 10-K). 10.34 Amendment No. 1 to the Employment Agreement between the Company and Gregory E. Abel dated April 16, 1997. 10.35 Employment Agreement between the Company and Craig M. Hammett, dated January 11, 1998. 10.36 Amendment No. 1 to the Employment Agreement between the Company and Craig M. Hammett dated January 12, 1998. 10.37 Employment Agreement between the Company and Steven A. McArthur, dated August 6, 1996 (incorporated by reference to Exhibit 10.46 to the Company's 1996 Form 10-K). 10.38 Amendment No. 1 to the Employment Agreement between the Company and Steven A. McArthur dated April 16, 1997. 10.39 Standard Offer Number 2, Standard Offer for Power Purchase with a Firm Capacity Qualifying Facility effective June 15, 1990 ("SO2") between San Diego Gas & Electric Company and Bonneville Pacific Corporation (incorporated by reference to Exhibit 10.42 to the Company's 1993 Form 10-K). 10.40 Amendment Number One to the SO2 dated September 25, 1990 (incorporated by reference to Exhibit 10.43 to the Company's 1993 Form 10-K). 10.41 Reserved 10.42 Reserved 10.43 Reserved 10.44 Stock Purchase Agreement between CalEnergy Imperial Valley Company, Inc. and Edison Mission Energy, dated as of March 27, 1996 (incorporated by reference to Exhibit 10.50 to the Company's 1995 Form 10-K). 10.45 Standard Offer No. 4 Power Purchase Agreement (Elmore), dated June 15, 1984, between Southern California Edison Company and Magma Electric Company including Amendments No. 1 and No. 2 (incorporated by reference to Exhibit 10.14 to Magma Power Company's Amendment No. 1 to Registration Statement Form S-4 dated February 2, 1988, ("Magma 1988 Form S-4")). 10.46 Standard Offer No. 4 Power Purchase Agreement (Del Ranch) dated February 22, 1984, between Southern California Edison Company and Imperial Energy Corporation, including Amendments No. 1 and No. 2 (incorporated by reference to Exhibit 10.15 to the Magma 1988 Form S-4). 10.47 Standard Offer No. 4 Power Purchase Agreement (Vulcan), dated June 15, 1984, between Southern California Edison Company and Magma Electric Company including Amendment No. 1 (incorporated by reference to Exhibit 10.16 to the Magma 1988 Form S-4). 10.48 Standard Offer No. 4 Power Purchase Agreement (River Ranch), dated April 16, 1985, between Southern California Edison Company and Imperial Energy Corporation, including Amendment No. 1 (incorporated by reference to Exhibit 10.20 to the Magma 1988 Form S-4). 10.49 Partnership Agreement dated August 30, 1985 between Vulcan Power Company and BN Geothermal, Inc. (incorporated by reference to Exhibit 10.88 to the Magma Power Company's Form 8 Amendment (dated December 18, 1990) to Magma Power Company's Form 10-K for the year ended December 31, 1989 ("Magma Form 8")). 10.50 Amended and Restated Limited Partnership Agreement of Del Ranch, Ltd., a California Limited Partnership, dated March 14, 1988 by and among Red Hill Geothermal, Inc. and Conejo Energy Company, as General Partners, and Magma Power Company and Conejo Energy Company, as Original Limited Partners (incorporated by reference to Exhibit 10.53 to the Magma Power Company Annual Report on Form 10-K for the year ended December 31, 1987, File No. 0-10533 ("1987 Magma Form 10-K")). 10.51 Limited Partnership Agreement of Leathers, L.P., dated August 15, 1988 by and among Red Hill Geothermal, Inc. and San Felipe Energy Company, as General Partners, and Magma Power Company and San Felipe Energy Company, as Limited Partners (incorporated by reference to Exhibit 10.79 to the Magma Power Company Annual Report on Form 10-K for the year ended December 31, 1988, File No. 0-10533 ("1988 Magma Form 10-K")). 10.52 Amended and Restated Limited Partnership Agreement of Elmore, Ltd., a California Limited Partnership, dated March 14, 1988 by and among Red Hill Geothermal, Inc. and Niguel Energy Company, as General Partners, and Magma Power Company and Niguel Energy Company, as Original Limited Partners (incorporated by reference to Exhibit 10.55 to the 1987 Magma Form 10-K). 10.53 Operating and Maintenance Agreement dated March 14, 1988 by and between Red Hill Geothermal, Inc. and Del Ranch, Ltd., a California Limited Partnership (incorporated by reference to Exhibit 10.56 to the 1987 Magma Form 10-K). 10.54 First Amendment to Operating and Maintenance Agreement dated as of April 14, 1989 between Red Hill Geothermal, Inc. and Del Ranch L.P. and the Second Amendment to the Operating and Maintenance Agreement dated April 18, 1990 "(incorporated by reference to Exhibit 10.60 to the Company's Form 10-K/A Amendment (dated March 31, 1995) to the Company's 1994 Form 10-K)." 10.55 Operating and Maintenance Agreement dated August 15, 1988 by and between Red Hill Geothermal, Inc. and Leathers, L.P. (incorporated by reference to Exhibit 10.84 to the 1988 Magma Form 10-K). 10.56 First Amendment to Operating and Maintenance Agreement dated as of April 14, 1989 between Red Hill Geothermal, Inc. and Leathers, L.P. and the Second Amendment to the Operating and Maintenance Agreement dated April 18, 1990 "(incorporated by reference to Exhibit 10.62 to the Company's 1994 Form 10-K)." 10.57 Operating and Maintenance Agreement dated March 14, 1988 by and between Red Hill Geothermal, Inc. and Elmore, Ltd., a California Limited Partnership (incorporated by reference to Exhibit 10.57 to the 1987 Magma Form 10-K). 10.58 First Amendment to the Operating and Maintenance Agreement dated as of April 14, 1988 between Red Hill Geothermal, Inc. and Elmore, Ltd., a California Limited Partnership and the Second Amendment to the Operating and Maintenance Agreement dated April 18, 1990 "(incorporated by reference to Exhibit 10.64 to the Company's 1994 Form 10-K)." 10.59 Brine Sales Agreement dated August 30, 1985 between Vulcan Power Company and Vulcan/BN Geothermal Power Company (incorporated by reference to Exhibit 10.90 to the Magma Power Company Form 8 Amendment (dated December 18, 1990) to the Magma Power Company Form 10-K for the year ended December 31, 1989). 10.60 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development dated March 14, 1988 by and between Magma Power Company and Del Ranch, Ltd., a California Limited Partnership (incorporated by reference to Exhibit 10.58 to the 1987 Magma Form 10-K). 10.61 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development dated August 15, 1988 by and between Magma Power Company and Leathers, L.P. (incorporated by reference to the 1988 Magma Form 10-K). 10.62 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development dated March 14, 1988 by and between Magma Power Company and Elmore, Ltd., a California Limited Partnership (incorporated by reference to Exhibit 10.59 to the 1987 Magma Form 10-K). 10.63 Administrative Services Agreement dated March 14, 1988 by and between Red Hill Geothermal, Inc. and Del Ranch, Ltd., a California Limited Partnership (incorporated by reference to the 1987 Magma Form 10-K). 10.64 Administrative Services Agreement dated August 15, 1988 by and between Red Hill Geothermal, Inc. and Leathers, L.P. (incorporated by reference to Exhibit 10.82 to the 1988 Magma Form 10-K). 10.65 Administrative Services Agreement dated March 14, 1988 by and between Red Hill Geothermal Inc. and Elmore, Ltd., a California Limited Partnership (incorporated by reference to Exhibit 10.63 to the 1987 Magma Form 10-K). 10.66 Amended and Restated Credit Agreement dated as of April 18, 1990 among Del Ranch, Ltd. a California Limited Partnership, the Banks Listed therein, and Morgan Guaranty Trust Company of New York, as Agent (incorporated by reference to Exhibit 10.72 to the Company's 1994 Form 10-K). 10.67 LOC Debt Facility Agreement dated as of April 18, 1990 among Del Ranch, Ltd., a California Limited Partnership, the Banks listed therein, Morgan Guaranty Trust Company of New York as the Agent and Fuji Bank, Limited, Los Angeles Agency, as Fronting Bank (incorporated by reference to Exhibit 10.73 to the Company's 1994 Form 10-K). 10.68 Security Agreement dated March 14, 1988 among Del Ranch, Ltd., a California Limited Partnership, Morgan Guaranty Trust Company of New York, as Agent for and on behalf of the Banks, Morgan Guaranty Trust Company of New York, and Morgan Guaranty Trust Company of New York, as Security Agent (incorporated by reference to the 1987 Magma Form 10-K). 10.69 Amendment Number One to Security Agreement dated as of April 14, 1989, and Amendment Number Two to the Security Agreement dated April 18, 1990 among Del Ranch, Ltd., a California Limited Partnership, Morgan Guaranty Trust Company of New York, as Agent for and on behalf of the Banks, Morgan Guaranty Trust Company of New York and Morgan Guaranty Trust Company of New York as Security Agent (incorporated by reference to Exhibit 10.75 to the Company's 1994 Form 10-K). 10.70 Deed of Trust, Assignment of Rents, Security Agreement and Fixture Filing Construction Deed of Trust dated as of March 14, 1988 among Del Ranch, Ltd., a California Limited Partnership, Ticor Title Insurance Company of California, and Morgan Guaranty Trust Company of New York as Security Agent (incorporated by reference to the 1987 Magma Form 10-K). 10.71 First Amendment to the Deed of Trust, dated April 18, 1990 between Del Ranch, Ltd. and Morgan Guaranty Trust Company of New York (incorporated by reference to Exhibit 10.77 to the Company's 1994 Form 10-K). 10.72 Amended and Restated Credit Agreement dated as of April 18, 1990 among Elmore, Ltd., a California Limited Partnership, the Banks Listed therein, and Morgan Guaranty Trust Company of New York, as Agent (incorporated by reference to Exhibit 10.78 to the Company's 1994 Form 10-K). 10.73 LOC Debt Facility Agreement dated as of April 18, 1990 among Elmore, Ltd., a California Limited Partnership, the Banks listed therein, Morgan Guaranty Trust Company of New York as Agent and Fuji Bank, Limited, Los Angeles Agency, as Fronting Bank (incorporated by reference to Exhibit 10.79 to the Company's 1994 Form 10-K). 10.74 Security Agreement dated March 14, 1988 among Elmore, Ltd., a California Limited Partnership, Morgan Guaranty Trust Company of New York, as Agent for and on behalf of the Banks, Morgan Guaranty Trust Company of New York, and Morgan Guaranty Trust Company of New York, as Security Agent (incorporated by reference to Exhibit 10.71 to the 1987 Magma Form 10-K). 10.75 Amendment Number One to Security Agreement dated as of April 14, 1989 among Elmore Ltd and Morgan Guaranty Trust Company of New York and Amendment Number Two to Security Agreement dated April 18, 1990 among Elmore, L.P., Morgan Guaranty Trust Company of New York, as Agent, on behalf of the Banks (incorporated by reference to Exhibit 10.81 to the Company's 1994 Form 10-K). 10.76 Deed of Trust, Assignment of Rents, Security Agreement and Fixture Filing Construction Deed of Trust dated as of March 14, 1988 among Elmore, Ltd., a California Limited Partnership, Ticor Title Insurance Company of California, and Morgan Guaranty Trust Company of New York as Security Agent (incorporated by reference to Exhibit 10.73 to the 1987 Magma Form 10-K). 10.77 First Amendment to Deed of Trust dated April 18, 1990 between Elmore, Ltd. and Morgan Guaranty Trust Company of New York, as Security Agent (incorporated by reference to Exhibit 10.83 to the Company's 1994 Form 10-K). 10.78 Amended and Restated Credit Agreement dated April 18, 1990 among Leathers L.P. and the Banks listed therein and Morgan Guaranty Trust Company of New York as Agent (incorporated by reference to Exhibit 10.84 to the Company's 1994 Form 10-K). 10.79 Security Agreement dated March 14, 1988 among Leathers L.P., a California Limited Partnership, Morgan Guaranty Trust Company of New York, as Agent for and on behalf of the Banks, Morgan Guaranty Trust Company of New York, and Morgan Guaranty Trust Company of New York, as Security Agent, Amendment Number One to Security Agreement dated as of April 14, 1989 and Amendment Number Two to Security Agreement dated as of April 18, 1990 (incorporated by reference to Exhibit 10.85 to the Company's 1994 Form 10-K). 10.80 Deed of Trust, Assignment of Rents, Security Agreement and Fixture Filing Construction Deed of Trust dated as of March 14, 1988 among Leathers, L.P., a California Limited Partnership, Ticor Title Insurance Company of California, and Morgan Guaranty Trust Company of New York as Security Agent and First Amendment to Deed of Trust dated April 18, 1990 (incorporated by reference to Exhibit 10.85 to the Company's 1994 Form 10-K). 10.81 LOC Debt Facility Agreement dated as of April 18, 1990 among Leathers, L.P., a California Limited Partnership, the Banks listed therein, Morgan Guaranty Trust Company of New York as Agent and Fuji Bank, Limited, Los Angeles Agency, as Fronting Bank (incorporated by reference to Exhibit 10.87 to the Company's 1994 Form 10-K). 10.82 Loan Agreement dated as of October 1, 1990 between California Pollution Control Financing Authority and Desert Valley Company, relating to the California Pollution Control Financing Authority Pollution Control Revenue Bonds Small Business Series 1990-A (the "$4,000,000 Monofill Bond Financing") (incorporated by reference to Exhibit 10.92 to the Magma Power Company Form 10-K for the year ended December 31, 1990, File No. 0-10533 (the "1990 Magma Form 10- K")). 10.83 Master Reimbursement Agreement dated as of October 1, 1990, by and among the California Pollution Control Financing Authority, Desert Valley Company and the Sanwa Bank, Limited, Los Angeles Branch, relating to the $4,000,000 Monofill Bond Financing (incorporated by reference to Exhibit 10.93 to the 1990 Magma Form 10-K). 10.84 Sale and Purchase Agreement between Union Oil Company of California and Magma Power Company effective as of December 31, 1992 (incorporated by reference to Exhibit 10.97 to the Magma Power Company Form 8 dated June 2, 1993). 10.85 Contract for the Purchase and Sale of Electric Power (Unit I) from the Salton Sea Geothermal Generating Facility between Southern California Edison Company and Earth Energy, Inc., dated May 8, 1987, including Amendment No. 1 to such contract, dated March 30, 1993 (incorporated by reference to Exhibit 10.101 to the Magma Power Company Form 10-K for the year ended December 31, 1993, File No. 0-10533, (the "1993 Magma Form 10-K")). 10.86 Power Purchase Contract (Unit II) by and between Southern California Edison Company and Westmoreland Geothermal Associates, dated April 16, 1985, including Amendment No. 1 to such contract, dated December 18, 1987 (incorporated by reference to Exhibit 10.102 to the 1993 Magma Form 10-K). 10.87 Power Purchase Contract (Unit III) between Southern California Edison Company and Union Oil Company Salton Sea III, dated April 16, 1985 (incorporated by reference to the 1993 Magma Form 10-K). 10.88 Consolidated, Amended and Restated Power Purchase Agreement (Unit IV) between Southern California Edison Company and Fish Lake Power Company and Salton Sea Power Generation, L.P. (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-4 dated August 9, 1995 of Salton Sea Funding Corporation 33- 95538 (the "Funding Corporation S-4"). 10.89 125 MW Power Plant - Upper Mahiao Agreement (the "Upper Mahiao ECA") dated September 6, 1993 between PNOC-Energy Development Corporation ("PNOC-EDC") and Ormat, Inc. as amended by the First Amendment to 125 MW Power Plant Upper Mahiao Agreement dated as of January 28, 1994, the Letter Agreement dated February 10, 1994, the Letter Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant - Upper Mahiao Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to the Company's 1994 Form 10-K). 10.90 Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Size as Agent (incorporated by reference to Exhibit 10.96 to the Company's 1994 Form 10-K). 10.91 Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incorporated by reference to Exhibit 10.97 to the Company's 1994 Form 10-K). 10.92 Pledge Agreement among CE Philippines Ltd, Ormat-Cebu Ltd., Credit Suisse as Collateral Agent and CE Cebu Geothermal Power Company, Inc. dated as of April 8, 1994 (incorporated by reference to Exhibit 10.98 to the Company's 1994 Form 10-K). 10.93 Overseas Private Investment Corporation Contract of Insurance dated April 8, 1994 between the Overseas Private Investment Corporation ("OPIC") and the Company through its subsidiaries CE International Ltd., CE Philippines Ltd., and Ormat-Cebu Ltd. (incorporated by reference to Exhibit 10.99 to the Company's 1994 Form 10-K). 10.94 180 MW Power Plant - Mahanagdong Agreement ("Mahanagdong ECA") dated September 18, 1993 between PNOC-EDC and CE Philippines Ltd. and the Company, as amended by the First Amendment to Mahanagdong ECA dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong ECA dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to the Company's 1994 Form 10-K). 10.95 Credit Agreement dated as of June 30, 1994 among CE Luzon Geothermal Power Company, Inc., American Pacific Finance Company, the Lenders party thereto, and Bank of America National Trust and Savings Association as Administrative Agent (incorporated by reference to Exhibit 10.101 to the Company's 1994 Form 10-K). 10.96 Credit Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to the Company's 1994 Form 10-K). 10.97 Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to the Company's 1994 Form 10-K). 10.98 Pledge Agreement dated as of June 30, 1994 among CE Mahanagdong Ltd., Kiewit Energy International (Bermuda) Ltd., Bank of America National Trust and Savings Association as Collateral Agent and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to the Company's 1994 Form 10-K). 10.99 Overseas Private Investment Corporation Contract of Insurance dated July 29, 1994 between OPIC and the Company, CE International Ltd., CE Mahanagdong Ltd. and American Pacific Finance Company and Amendment No. 1 dated August 3, 1994 (incorporated by reference to Exhibit 10.105 to the Company's 1994 Form 10-K). 10.100 231 MW Power Plant - Malitbog Agreement ("Malitbog ECA") dated September 10, 1993 between PNOC-EDC and Magma Power Company and the First and Second Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to the Company's 1994 Form 10-K). 10.101 Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to the Company's 1994 Form 10-K). 10.102 Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to the Company's 1994 Form 10-K). 10.103 Pledge and Security Agreement dated as of November 10, 1994 among Broad Street Contract Services, Inc., Magma Power Company, Magma Netherlands B.V. and Credit Suisse as Bank Agent (incorporated by reference to Exhibit 10.109 to the Company's 1994 Form 10-K). 10.104 Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994 between OPIC and Magma Netherlands, B.V. (incorporated by reference to Exhibit 10.110 to the Company's 1994 Form 10-K). 10.105 Agreement as to Certain Common Representations, Warranties, Covenants and Other Terms, dated November 10, 1994 between Visayas Geothermal Power Company, Visayas Power Capital Corporation, Credit Suisse, as Bank Agent, OPIC and the Banks named therein (incorporated by reference to Exhibit 10.111 to the Company's 1994 Form 10-K). 10.106 Indenture dated as of July 21, 1995 between Salton Sea Funding Corporation ("Funding Corporation") and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1(a) to the Funding Corporation Form S-4). 10.107 First Supplemental Indenture dated as of October 18, 1995 between Funding Corporation and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1(b) to the Funding Corporation Form S-4). 10.108 Indenture dated July 1995 between the Company and The Bank of New York (incorporated by reference to the Company's Amendment No. 1 to Registration Statement on Form S-3 dated May 17, 1995). 10.109 Trust Indenture dated as of November 27, 1995 between the CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") and Chemical Trust Company of California (incorporated by reference to Exhibit 4.1 to CE Casecnan's Registration Statement on Form S-4 dated January 25, 1996 ("Casecnan S-4")). 10.110 Modification to Contract No. P00019 dated August 1, 1995, Modification to Contract No. P00020 dated August 1, 1995, Modification to Contract No. P00034 dated February 8, 1995 and Modification to Contract No. P00035 dated February 8, 1995, amending the Navy Contract (incorporated by reference to Exhibit 10.110 to the Company's 1996 Form 10-K). 10.111 Plant Connection Agreement between Imperial Irrigation District and Salton Sea Power Generation L.P. and Fish Lake Power Company dated July 14, 1995 (incorporated by reference to Exhibit 10.15 to the Funding Corporation S-4). 10.112 Transmission Services Agreement between Imperial Irrigation District and Salton Sea Power Generation L.P. and Fish Lake Power Company dated July 14, 1995 (incorporated by reference to Exhibit 10.17 to the Funding Corporation S-4). 10.113 Second Amended and Restated Administrative Services Agreement among CalEnergy Operation Company, Salton Sea Brine Processing L.P., Salton Sea Power Generation L.P. and Fish Lake Power Company dated July 15, 1995 (incorporated by reference to Exhibit 10.20 to the Funding Corporation S-4). 10.114 Second Amended and Restated Operating and Maintenance Agreement among Magma Power Company, Salton Sea Brine Processing L.P., Salton Sea Power Generation L.P., and Fish Lake Power Company dated July 15, 1995 (incorporated by reference to Exhibit 10.21 to the Funding Corporation S-4). 10.115 Amended and Restated Casecnan Project Agreement between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. dated June 26, 1995 (incorporated by reference to Exhibit 10.1 to the Casecnan Form S-4). 10.116 Stock Purchase Agreement, dated as of July 3, 1996, by and among CE/FS Holding Company, Inc., David H. Dewhurst and all remaining owners of capital stock of Falcon Seaboard Resources, Inc. (incorporated by reference to Exhibit 99.1 to the Company's Form 8-K, dated July 8, 1996, File No. 1-9874). 10.117 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures, dated as of April 1, 1996, among CalEnergy Company, Inc., as Issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.3 to Amendment 1 to the Company's Registration Statement on Form S-3, Registration No. 333- 08315). 10.118 Indenture, dated as of September 20, 1996, between the Company and IBJ Schroder Bank & Trust Company, as trustee, relating to $225,000,000 principal amount of 9 1/4% Senior Notes due 2006 (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-3, Registration No. 333- 15591). 10.119 Second Supplemental Indenture, dated as of June 20, 1996, between Chemical Trust Company of California and Funding Corporation (incorporated by reference to Exhibit 4.1(c) to Amendment No. 1 to the Funding Corporation's Registration Statement on Form S-4, Registration No. 333-07527 ("Funding Corp. II S-4"). 10.120 Third Supplemental Indenture, between Chemical Trust Company of California and the Funding Corporation (incorporated by reference to Exhibit 4.1(d) to the Funding Corp. II S-4). 10.121 Indenture for the 6 1/4% Convertible Junior Subordinated Debentures due 2012, dated as of February 26, 1997, between the Company, as issuer, and the Bank of New York, as Trustee (incorporated by reference to Exhibit 10.129 to the Company's 1996 Form 10-K). 10.122 Term Loan and Revolving Facility Agreement, dated as of October 28, 1996, among CE Electric UK Holdings, CE Electric UK plc and Credit Suisse (incorporated by reference to Exhibit 10.130 to the Company's 1996 Form 10-K). 10.123 Public Electricity Supply License (incorporated by reference to Exhibit 10.131 to the Company's 1996 Form 10-K) 10.124 Second Tier Supply Licenses to Supply Electricity for England & Wales and Scotland (incorporated by reference to Exhibit 10.132 to the Company's 1996 Form 10-K). 10.125 Pooling and Settlement Agreement for the Electricity Industry in England and Wales dated 30th March, 1990 (as amended at 17th October, 1996), among The Generators (named therein), the Suppliers (named therein), Energy Settlements and Information Services Limited (as Settlement System Administrator), Energy Pool Funds Administration Limited (as Pool Funds Administrator), Scottish Power plc, Electricite deFrance, Service National and Others (incorporated by reference to Exhibit 10.133 to the Company's 1996 Form 10-K). 10.126 Master Connection and User System Agreement with The National Grid Company plc (incorporated by reference to Exhibit 10.134 to the Company's 1996 Form 10-K). 10.127 Gas Suppliers License dated February 21, 1996 (incorporated by reference to Exhibit 10.135 to the Company's 1996 Form 10-K). 10.128 First Supplemental Trust Indenture dates as of February 18, 1997 between Coso Funding Corp. and First Bank, National Association (successor to Bank of America Nation Trust and Savings Association) (incorporated by reference to Exhibit 10.136 to the Company's 1996 Form 10-K). 10.129 Form First Amendment to Amended and Restated Credit Agreement, dated February 18, 1997, between First Bank, National Association (as successor to Coso Funding Corp.) and the Coso Joint Ventures (incorporated by reference to Exhibit 10.137 to the Company's 1996 Form 10-K). 10.130 Omnibus Acknowledgment and Agreement dated February 18, 1997 between Coso Funding Corp., the Coso Joint Ventures, First Bank, National Association and others (incorporated by reference to Exhibit 10.138 to the Company's 1996 Form 10-K). 10.131 Registration Rights Agreement, dated August 12, 1997, by and among CalEnergy Capital Trust III, CalEnergy Company, Inc., Credit Suisse First Boston Corporation and Lehman Brothers, Inc. (incorporated by reference Exhibit 10.1 to the Company's Registration Statement and on Form S-3, No. 333-45615). 10.132 Acquisition Agreement by and between CalEnergy Company, Inc. and Kiewit Diversified Group Inc. dated as of September 10, 1997 (incorporated by reference to Exhibit 2 to the Company's Current Report on Form 8-K dated September 11, 1997). 10.133 Indenture, dated as of October 15, 1997, among the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8- K dated October 23, 1997). 10.134 Form of First Supplemental Indenture, dated as of October 28, 1997, among the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K dated October 23, 1997). 13.0 The Company's 1997 Annual Report (only the portions thereof specifically incorporated herein by reference are deemed filed herewith). 21.0 Subsidiaries of Registrant. 23.0 Consent of Independent Auditors. 24.0 Power of Attorney. 27.1 Financial Data Schedule. 27.2 Restated Financial Data Schedule - fiscal year ended December 31, 1995 and 1996 and the three, six, and nine months ended March 31, 1996, June 30, 1996 and September 30, 1996, respectively. 27.3 Restated Financial Data Schedule - three, six and nine months ended March 31, 1997, June 30, 1997 and September 30, 1997, respectively. EX-3.5 2 Exhibit 3.5 CERTIFICATE OF AMENDMENT TO THE CERTIFICATE OF INCORPORATION OF CALENERGY COMPANY, INC. CALENERGY COMPANY, INC., a Delaware corporation (the "Company"), HEREBY CERTIFIES AS FOLLOWS: FIRST: The name of the Company is CalEnergy Company, Inc. The date of the filing of the Company's most recent Certificate of Amendment to the Restated Certificate of Incorporation with the Secretary of State of the State of Delaware was February 23, 1995; provided, however, that such Restated Certificate of Incorporation was further amended by a Certificate of Ownership and Merger dated March 22, 1996, which amended the Company's name. SECOND: That the following resolution was approved and adopted by the Board of Directors of the Company. THIRD: That the following resolution was approved and adopted pursuant to authorization by the stockholders of the Company at the annual meeting of the Company's stockholders duly called and held on May 15, 1997: RESOLVED: That paragraph A of Article Fourth of the Company's Restated Certificate of Incorporation be deleted in its entirety and the following be and hereby is inserted in lieu thereof: FOURTH: A. The Corporation is authorized to issue two classes of shares of stock, to be designated respectively as Preferred Stock shares and as Common Stock shares. The total number of shares of all classes of stock which the Corporation shall have authority to issue is One Hundred Eighty Two Million (182,000,000) shares, and the aggregate par value of all shares that are to have a par value is Twelve Million One Hundred Fifty Thousand Dollars ($12,150,000). The number of Preferred Stock shares is Two Million (2,000,000) shares, each without par value. The number of Common Stock shares that are to have a par value is One Hundred Eighty Million (180,000,000), and each such Common Stock share is to have a par value of Six and Seventy-Five One Hundredths Cents ($0.0675) per share. FOURTH: That said amendment herein certified was duly adopted in accordance with Section 242 of the General Corporation Law of the State of Delaware. The effective time of the amendment herein certified shall be immediately upon filing. IN WITNESS WHEREOF, CALENERGY COMPANY, INC. has caused this Certificate to be executed and attested by the undersigned, this 19th day of May, 1997. CALENERGY COMPANY, INC. By: /s/ Steven A. McArthur Name: Steven A. McArthur Title: Secretary ATTEST: By: /s/ Douglas L. Anderson Name: Douglas L. Anderson Title: Assistant Secretary EX-10.32 3 Exhibit 10.32 AMENDMENT NO. 2 TO THE AMENDED AND RESTATED EMPLOYMENT AGREEMENT BETWEEN CALENERGY COMPANY, INC. AND DAVID SOKOL This Amendment No. 2 (the "Amendment") to the Amended and Restated Employment Agreement dated as of August 21, 1995, as further amended by Amendment No. 1 thereto (the "Employment Agreement") by and between CalEnergy Company, Inc., a Delaware Corporation (the "Company"), and David L. Sokol (the "Executive"), is entered into as of April 16, 1997. WHEREAS, the Company and the Executive are presently parties to the Employment Agreement; and WHEREAS, the Company and the Executive desire to amend the Employment Agreement as set forth herein; NOW, THEREFORE, the Employment Agreement is hereby amended as follows: (1) By adding the following sentences at the end of Section 4(c): "The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Board. The Executive's annual bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as `Annual Bonus Compensation.'" (2) By adding the following sentence after the last sentence of Section 6(a): "The preceding sentence notwithstanding, if the Executive's resignation occurs upon or after a Change in Control (as defined in the Restricted Stock Exchange Agreement between the Company and the Executive dated as of November 29, 1995), he shall not be precluded from accepting employment or providing services to Peter Kiewit Sons', Inc. or any affiliate thereof." (3) By deleting the first sentence of Section 8(b) of the Employment Agreement and replacing it with the following sentence: "If the employment of the Executive is terminated pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), the Company will pay the Executive, on or before the related Termination Date, an amount equal to three times the sum of (1) the annual salary then in effect pursuant to Section 4, and (2) the greater of (x) the Minimum Bonus or (y) an amount equal to the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the fiscal year in which the Executive's employment with the Company terminates." (4) By inserting immediately following Section 8(b) a new Section 8(c), to read as follows: "(c) If the employment of the Executive is terminated pursuant to subsections (ii) or (iv) of Section 7(a), all Performance Accelerated Stock Options ("PASOs") held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date, and shall otherwise remain exercisable for their term in accordance with the terms thereof." (5) By inserting immediately following Section 8(c) a new Section 8(d) to read as follows: "(d) If the employment of the Executive is terminated for any reason after a Change in Control (as defined in the Restricted Stock Exchange Agreement between the Company and the Executive dated as of November 29, 1995), then without further action by the Company, the Board or any committee thereof, the Executive may exercise any vested stock options (including vested PASOs) held by the Executive pursuant to existing procedures approved by the Stock Option Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise." Except as provided herein and to the extent necessary to give full effect to the provisions of this Amendment, the terms of the Employment Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have entered into this Amendment effective as of April 16, 1997. CALENERGY COMPANY, INC. By: /s/ Steven A. McArthur Name: Steven A. McArthur Title: Senior Vice President EXECUTIVE /s/ David L. Sokol David L. Sokol EX-10.34 4 Exhibit 10.34 AMENDMENT NO. 1 TO THE EMPLOYMENT AGREEMENT BETWEEN CALENERGY COMPANY, INC. AND GREGORY E. ABEL This Amendment No. 1 (the "Amendment") to the Employment Agreement dated August 6, 1996 (the "Employment Agreement") by and between CalEnergy Company, Inc., a Delaware corporation (the "Company"), and Gregory E. Abel (the "Executive"), is entered into as of April 16, 1997. WHEREAS, the Company and the Executive are presently parties to the Employment Agreement; and WHEREAS, the Company and the Executive desire to amend the Employment Agreement as set forth herein; NOW, THEREFORE, the Employment Agreement is hereby amended as follows: (1) By adding the following sentences at the end of Section 4(c): "The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Chairman of the Board. The Executive's annual incentive merit bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as `Annual Bonus Compensation.'" (2) By adding the following sentence after the last sentence of Section 6 (a): "The preceding sentence notwithstanding, if the Executive's resignation occurs upon or after a Change in Control, he shall not be precluded from accepting employment or providing services to Peter Kiewit Sons', Inc. or any affiliate thereof." (3) By deleting from the first sentence of Section 8(b) the language following the parenthetical "(iii)" and replacing it with the following: "commencing one month after the month of his Termination Date, 24 monthly payments each equal to 1/24 of a sum equal to two times the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the year in which the Executive's employment with the Company terminates (with any such year for which no bonus was payable included in such two year average as a zero)." (4) By deleting current Section 8(d) and inserting new Section 8(d), to read as follows: "(d) If the employment of the Executive is terminated pursuant to subsections (ii) or (vi) of Section 7(a), all Performance Accelerated Stock Options ("PASOs") held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date and shall otherwise remain exercisable for their term in accordance with the terms thereof." (5) By inserting immediately following Section 8(d) a new Section 8(e) to read as follows: "(e) If the employment of the Executive is terminated for any reason after a Change in Control, then without further action by the Company, the Board or any committee thereof, the Executive may exercise any vested stock options (including vested PASOs) held by the Executive pursuant to existing procedures approved by the Stock Option Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise." (6) By inserting immediately following Section 8 a new Section 8A, which shall read in its entirety as follows: "Section 8A. Certain Additional Payments by the Company. (a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment, distribution, waiver of Company rights, acceleration of vesting of any stock options or restricted stock, or any other payment or benefit in the nature of compensation to or for the benefit of the Executive, alone or in combination (whether such payment, distribution, waiver, acceleration or other benefit is made pursuant to the terms of this Agreement or any other agreement, plan or arrangement providing payments or benefits in the nature of compensation to or for the benefit of the Executive, but determined without regard to any additional payments required under this Section 8A) (a "Payment") would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the executive shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount such that after payment by the Executive of all taxes with respect to the Gross-Up Payment (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. (b) Subject to the provisions of Section 8A(c), all determinations required to be made under this Section 8A, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by Deloitte and Touche, LLP, or such other nationally recognized accounting firm then auditing the accounts of the Company (the "Accounting Firm") which shall provide detailed supporting calculations both to the Company and the Executive within 15 business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is unwilling or unable to perform its obligations pursuant to this Section 8A, the Executive shall appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to hereunder as the Accounting Firm). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any Gross-Up Payment, determined pursuant to this Section 8A, shall be paid by the Company to the Executive within five days of the receipt of the Accounting Firm's determination. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. The parties hereto acknowledge that, as a result of the potential uncertainty in the application of Section 4999 of the Code (or any successor provision) at the time of the initial determination by the Accounting Firm hereunder, it is possible that the Company will not have made Gross-Up Payments which should have been made consistent with the calculations required to be made hereunder (an "Underpayment"). In the event that the Company exhausts its remedies pursuant to Section 8A(c) and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive. (c) The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than 20 business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive shall not pay such claim prior to the expiration of the 30-day period following the date on which he gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall: (i) give the Company any information reasonably requested by the Company relating to such claim, (ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company, (iii) cooperate with the Company in good faith in order effectively to contest such claim, and (iv) permit the Company to participate in any proceedings relating to such claim; provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limiting the foregoing provisions of this Section 8A(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Executive to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Executive, on an interest-free basis, and shall indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. (d) If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 8A(c), the Executive becomes entitled to receive any refund with respect to such claim, the Executive shall (subject to the Company's complying with the requirements of Section 8A(c)) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 8A(c), a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross- Up Payment required to be paid." Except as provided herein and to the extent necessary to give full effect to the provisions of this Amendment, the terms of the Employment Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have entered into this Amendment effective as of April 16, 1997. CALENERGY COMPANY, INC. By: /s/ David L. Sokol Name: David L. Sokol Title: Chairman of the Board EXECUTIVE /s/ Gregory E. Abel Gregory E. Abel EX-10.35 5 Exhibit 10.35 EMPLOYMENT AGREEMENT This Employment Agreement is entered into as of January 11, 1998, by and between CalEnergy Company, Inc. a Delaware corporation (the "Company"), and Craig M. Hammett (the "Executive"). RECITALS The Company desires to employ the Executive as its Senior Vice President and Chief Financial Officer on the terms set forth in this Agreement, and the Executive desires to accept such employment. Accordingly, the Company and the Executive agree as follows: AGREEMENT Section 1. Defined Terms. Terms used but not defined in this Agreement will have the meanings ascribed to them in Exhibit A to this Agreement. Section 2. Employment. (a) The Company will employ the Executive as, and the Executive will act as the Senior Vice President and Chief Financial Officer of the Company, subject to and upon the terms set forth in this Agreement, for the Term of Employment. (b) The Executive's primary place of employment will be Omaha, Nebraska or such other place as is determined, prior to a Change in Control, in good faith by the Chairman of the Board and Chief Executive Officer of the Company (hereinafter referred to as the "Chairman of the Board") to be in the best interests of the Company. Section 3. Duties. (a) The Executive (i) will perform and discharge the duties incident to and consistent with his title of Senior Vice President and Chief Financial Officer, and (ii) will perform and discharge such other duties, and will have such other authority, as are delegated to him by the Chairman of the Board. In performing such duties, the Executive will report directly to, and be subject to the direction of, the Chairman of the Board. Prior to a Change in Control, the Executive's title and duties may in good faith be modified by the Chairman of the Board. (b) The Executive will act, without any compensation in addition to the compensation payable pursuant to this Agreement, as an officer or member of the board of directors of any subsidiary of the Company, if so appointed or elected. (c) During the Term of Employment, the Executive (i) will devote his entire time, attention and energies during normal business hours to the business of the Company and its subsidiaries and (ii) will not, without the written consent of the Chairman of the Board, perform any services for any other Person or engage in any other business or professional activity, whether or not performed or engaged in for profit. (d) Notwithstanding subsection 3(c), the Executive, without the consent of the Chairman of the Board, may (i) purchase securities issued by, or otherwise passively invest his personal or family assets in, any other company or business within the constraints imposed by the Policy of Business Conduct referred to below, and (ii) engage in governmental, political, educational or charitable activities, but only to the extent that those activities (A) are not inconsistent with any direction of the Chairman of the Board or any duties under this Agreement, and (B) do not interfere with the devotion by the Executive of his entire time, attention and energies during normal business hours to the business of the Company. Section 4. Compensation. (a) During the Term of Employment, the Company will pay the Executive a base salary at an annual rate of $160,000, in substantially equal periodic payments in accordance with the Company's practices for executive employees, as determined from time to time by the Chairman of the Board. (b) The Chairman of the Board will review the salary payable to the Executive at least annually beginning in the fourth fiscal quarter of 1998. The Chairman of the Board, in his discretion, may increase the salary of the Executive from time to time, but may not reduce the salary of the Executive below the amount set forth in subsection 4(a) above. (c) During the Term of Employment, the Executive shall be eligible for consideration for an annual incentive merit bonus, for the Executive's performance during the preceding fiscal year of the Company in an amount determined by the Chairman of the Board in his discretion, by reference to the accomplishment by the Executive of goals established by the Chairman of the Board for the related fiscal year. (d) The Company will reimburse the Executive, subject to compliance by the Executive with the Company's customary reimbursement practices, for all reasonable and necessary out-of- pocket expenses incurred by the Executive on behalf of the Company in the course of its business. (e) The Company may reduce any payments made to the Executive under this Agreement by any required federal, state or local government withholdings or deductions for taxes or similar charges, or otherwise pursuant to law, regulation or order. (f) Any base salary payable to the Executive for any period of employment of less than one year during the Term of Employment will be reduced to reflect the actual number of days of employment during the period except as provided in Sections 8(b) and 8(c). Section 5. Other Benefits. (a) During the Term of Employment, the Executive and his dependents may participate in and receive benefits under any employee benefit plan which the Company makes generally available to its employees and their families, including any pension, life insurance, medical benefits, dental benefits or disability plan, but only to the extent that the Executive or his dependents otherwise satisfies the standards established for participation in the plan. The terms of Executive's existing option agreement, as amended, remain unaffected hereby, except as set forth in Section 8(b) and 8(c) hereof. (b) The Executive may take up to three weeks of vacation during each full calendar year during the Term of Employment at a time mutually convenient to the Executive and the Company, without loss of compensation or other benefits under this Agreement. Section 6. Confidentiality and Post-Employment Restriction. (a) The Executive acknowledges that the Company and its Affiliates have confidential information and trade secrets, whether written or unwritten, with respect to carrying on their business, including sensitive marketing, bidding, technological and engineering information and data, names of past, present and prospective customers or partners of and vendors of suppliers to the Company and its Affiliates, working relationships with governmental agencies and officials, methods of pricing contracts and income and expenses associated therewith, the international business strategy and relative ranking of opportunities in various countries, negotiated prices and offers outstanding, credit terms and status of accounts and the terms of circumstances of any current or prospective business arrangements between the Company and its Affiliates and any third parties ("Confidential Information and Trade Secrets"). As used in this Agreement, the term Confidential Information and Trade Secrets does not include (i) information which becomes generally available to the public other than as a result of a disclosure by the Executive, (ii) information which becomes available to the Executive on a nonconfidential basis from a source other than the Company or its Affiliates, or (iii) information known to the Executive prior to any disclosure to him by the Company or its Affiliates. The Executive further acknowledges that the Executive possesses a high degree of knowledge of the independent energy industry and, in particular, has committed to a long- standing relationship with the Company and its Affiliates as an employee and officer, which has allowed, and will continue to allow, him access to the Company's Confidential Information and Trade Secrets. Accordingly, any employment by the Executive with another employer in the independent energy industry or participation by him as a substantial investor in any such industry may necessarily involve disclosure of the Company's Confidential Information and Trade Secrets. Consequently, the Executive agrees that, if he voluntarily resigns his employment with the Company for any reason other than (i) a breach of this Agreement by the Company, or (ii) for Good Reason, he shall not at any time during the two-year period after such resignation, directly or indirectly accept employment by or invest in (except as a passive investor in a public corporation or in a publicly issued partnership interest which, in either event, would not exceed an ownership interest of 2% of the outstanding equity or partnership interest) in any person, firm, corporation, partnership, joint venture or business which is primarily engaged in the production or marketing of st4eam or electrical energy or which otherwise directly competes with the business of the Company or its controlled Affiliates and, further, the Executive agrees that, to avoid the risk of disclosing or improperly using Confidential Information or Trade Secrets, he shall not directly, or indirectly, provide consulting or advisory services to any of such independent energy business. (b) Without the written consent of the Chairman of the Board, the Executive will not, during and for three years after the Term of Employment, (i) disclose any Confidential Information and Trade Secrets of the Company or any Affiliate of the Company to any Person (other than the Company, directors, officers or employees of the Company, its Affiliates or duly authorized agents, attorneys or other representatives thereof), or (ii) otherwise make use of any Confidential Information and Trade Secrets other than in connection with authorized dealings with or by the Company and its Affiliates. (c) For a period of three years after the Term of Employment, the Executive shall neither directly nor indirectly solicit, on behalf of another employer, the employment of, or hire or cause another employer to hire, any person who is then currently employed by the Company or an Affiliate thereof, or otherwise induce, on behalf of another employer, such person to leave the employment of the Company or an Affiliate thereof without the prior written approval of the Chairman of the Board. (d) The Executive will hold, on behalf of the Company and its Affiliates and as the property of the Company and its Affiliates, all memoranda, manuals, books, papers, letters, documents, computer discs, data and software and other similar property obtained during the course of his employment by the Company or its Affiliates and relating to the Company's or its Affiliates business, and will return such property to the Company or its Affiliates at any time upon demand by the Chairman of the Board and, in any event, within five calendar days after the end of the Term of Employment. (e) During the Term of Employment, Executive agrees to comply in all material respects with the Company's Policy of Business Conduct attached hereto as Exhibit A and to deliver with the execution of this Agreement and executed Certificate of Compliance with respect thereto. (f) If any of the provisions of, or covenants contained in, this Section 6 are hereafter construed to be invalid or unenforceable in any jurisdiction, the same shall not affect the remainder of the provisions or the enforceability thereof in any other jurisdiction, which shall be given full effect, without regard to the invalidity or unenforceability in such other jurisdiction. If any of the provisions of, or covenants contained in, this Section 6 are held to be unenforceable in any jurisdiction because of the duration or geographical scope thereof, the parties agree that the court making such determination shall have the power to reduce the duration or geographical scope of such provision or covenant and, in its reduced form, such provision or covenant shall be enforceable; provided, however, that the determination of such court shall not affect the enforceability of this Section 6 in any other jurisdictions. Section 7. Termination of Employment. (a) The employment of the Executive under this Agreement will terminate on the earliest of: (i) written notice by the Executive of his resignation other than for Good Reason; (ii) the day the Company gives to the Executive written notice of termination without Cause; (iii) the day the Company gives to the Executive written notice of termination for Cause; (iv) the Permanent Disability of the Executive; (v) the death of the Executive; or (vi) written notice by the Executive of his resignation for Good Reason. (b) If the employment of the Executive is terminated under this Agreement for any reason whatsoever, the obligations of the Executive under Section 6 will remain in full force and effect to the extent provided therein, and the termination will not abrogate any rights or remedies of the Company or the Executive with respect to any breach of the Agreement, except as expressly provided in Section 8. Section 8. Payment Upon Termination. (a) If the employment of the Executive is terminated pursuant to subsections (i) or (iii) of Section 7(a), the Company will pay to the Executive, within 30 calendar days, any base salary and reimbursable expenses pursuant to Section 4(a) and Section 4(d) which are accrued but unpaid through the Termination Date. (b) If the employment of the Executive is terminated pursuant to subsections (ii), (iv) or (v) of Section 7(a) prior to a Change in Control, the Company will pay the Executive, subject to the Executive's compliance in all material respects with his post-termination obligations under Section 6, (i) within 30 calendar days, any base salary and reimbursable expenses which are accrued and unpaid through such date, (ii) commencing one month after the month of his Termination Date, 24 monthly payments each equal to 1/24 of a sum equal to twice his annual base salary then in effect pursuant to Section 4 and (iii) commencing one month after the month of his Termination Date, 24 monthly payments each equal to 1/24 of a sum equal to twice the average of his prior three years incentive bonuses (with any such year in which no bonus was paid included in such three year average as a zero). In addition, in the event of any such termination, subject to the Executive's compliance in all material respects with his post-termination obligations under Section 6, the Company agrees that (x) the Company stock options previously granted to Executive will continue to vest according to their terms within such next 24 months (beginning with the month following the month in which the Termination Date occurs, after which time the unvested remainder will lapse) and such vested options may be exercised within the remaining term of such options as provided in the respective option agreements, and (y) the Company shall continue in effect for Executive, for a period of twelve months after the date of any such termination, the life insurance, medical benefits, dental benefits and disability plan available to the Executive and his dependents on the date of such termination, subject to such employee contributions and other terms and conditions as are applicable to active employees generally and subject to subsequent modification or termination of such plans to the extent such subsequent actions are also applicable to active employees generally; provided that such plan benefits shall terminate earlier on the date, if any, that comparable benefits are made available to the Executive by any new employer. (c) If the employment of the Executive is terminated on or after a Change in Control pursuant to subsections (ii), (iv), (v) or (vi) of Section 7(a), the Executive shall receive the same payments, additional option vesting and benefits continuation described in Section 8(b) hereof, except that the monthly payments described in clauses (ii) and (iii) of the first sentence of Section 8(b) shall be aggregated and paid to Executive in a single lump sum without any discount to reflect present value. (d) Sections 8(b) and 8(c) hereof notwithstanding, in the event that the payments due to the Executive under this Agreement, whether alone or together with payments due under any plan, program, or arrangement maintained by the Company (collectively, "Payments"), constitute and "excess parachute payment" (within the meaning of Section 280G(b)(1) of the Code), the Payments shall be reduced by the minimum possible amount so that their aggregate present value equals $1.00 less than three times the Executive's "base amount" (within the meaning of Section 280G(b)(3)(A) of the Code). The Company's independent auditors shall determine whether a reduction in Payments shall be required pursuant to this Section 8(d), and shall determine the optimal method and order for reduction of Payments so as to maximize the economic benefits accruing to the Executive in respect of the Payments. Section 9. Remedies. (a) The Company will be entitled, if it elects, to enjoin any breach or threatened breach of, or enforce the specific performance of, the obligations of the Executive under Sections 3 or 6, without showing any actual damage or that monetary damages would be inadequate. Any such equitable remedy will not be the sole and exclusive remedy for any such breach, and the Company may pursue other remedies for such a breach. (b) Any court proceeding to enforce this Agreement may be commenced in federal courts, or in the absence of federal jurisdiction the state courts, located in Omaha, Nebraska. The parties submit to the jurisdiction of such courts and waive any objection which they may have to pursuit of any such proceeding in any such court. (c) Except to the extent that the Company elects to seek injunctive relief in accordance with subsection 9(a), any controversy or claim arising out of or relating to this Agreement or the validity, interpretation, enforceability or breach of this Agreement will be submitted to arbitration in Omaha, Nebraska, in accordance with the then existing rules of the American Arbitration Association, and judgment upon the award rendered in any such arbitration may be entered in any court having jurisdiction. Section 10. Assignment. Neither the Company nor the Executive may sell, transfer or otherwise assign their rights, or delegate their obligations, under this Agreement, provided that the Company shall require any successor to all or substantially all of the business, stock or assets of the Company to expressly assume the Company's rights and obligations hereunder. Section 11. Unfunded Benefits. All compensation and other benefits payable to the Executive under this Agreement will be unfunded, and neither the Company nor any Affiliate of the Company will segregate any assets to satisfy any obligation of the Company under this Agreement. The obligations of the Company to the Executive are not the subject of any guarantee or other assurance of any Person other than the Company. Section 12. Severability. Should any provision, paragraph, clause or portion thereof of this Agreement be declared or be determined by any court or arbitrator of competent jurisdiction to be illegal, unenforceable or invalid, the validity or enforceability of the remaining parts, terms or provisions shall not be affected thereby and said illegal or invalid part, term or provisions shall be deemed not to be a part of this Agreement. Alternatively, the court or arbitrator having jurisdiction shall have the power to modify such illegal, unenforceable or invalid provision so that it will be valid and enforceable, and, in any case, the remaining provisions of this Agreement shall remain in full force and effect. Section 13. Miscellaneous. (a) This Agreement may be amended or modified only by a writing executed by the Executive and the Company. (b) This Agreement will be governed by and construed in accordance with the internal laws of the State of Nebraska. (c) This Agreement constitutes the entire agreement of the Company and the Executive with respect to the matters set forth in this Agreement and supersedes any and all other agreements between the Company and the Executive relating to those matters. (d) Any notice required to be given pursuant to this Agreement will be deemed given (i) when delivered in person or by courier or (ii) on the third calendar day after it is sent by facsimile, with written confirmation of receipt, if to the Company, to: Chairman of the Board, CalEnergy Company, Inc. at 302 South 36th Street, Suite 400, Omaha, Nebraska 68131, fax number (402) 231-1658, and, if to the Executive, at 302 South 36th Street, Suite 400, Omaha, Nebraska 68131, fax number (402) 231-1658 or to such other address as may be subsequently designated by the Company or the Executive in writing to the other party. (e) A waiver by a party of a breach of this Agreement will not constitute a waiver of any other breach, prior or subsequent, of this Agreement. IN WITNESS WHEREOF, the Company and the Executive have entered into this Agreement as of January 11, 1998. CALENERGY COMPANY, INC. By: /s/ David L. Sokol David L. Sokol Chairman of the Board EXECUTIVE: By: /s/ Craig M. Hammett Craig M. Hammett EXHIBIT A Defined Terms "Affiliate" means, with respect to a Person, (a) any Person directly or indirectly owning, controlling, or holding power to vote 10% or more of the outstanding voting securities of the Person; (b) any Person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled or held with power to vote by the Person; (c) any Person directly or indirectly controlling, controlled by or under common control with, the Person; and (d) any officer or director of the Person, or of any Person directly or indirectly controlling the Person, controlled by the Person or under common control with the Person. As used in this definition, "control" means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person. "Agreement" means this Employment Agreement dated as of January 11, 1998, by and between the Company and the Executive, as it may be amended from time to time in accordance with its terms. "Board" means the Board of Directors of the Company. "Cause" means any or all of the following: (a) the willful and continued failure by the Executive to perform substantially the services and duties contemplated by this Agreement (other than any such failure resulting from the Executive's incapacity due to disability); (b) the willful engaging by the Executive in gross misconduct which is injurious to the business or reputation of the Company in any material respect; (c) the gross negligence of the Executive in performing the services contemplated by this Agreement which is injurious to the business or reputation of the Company in any material respect; or (d) Executive's conviction of, or pleading guilty or no contest to, a felony involving moral turpitude. "Change in Control" means (i) approval by the Company's stockholders of (A) the dissolution of the Company, (B) a merger or consolidation of the Company where the Company is not the surviving corporation, except for a transaction the principal purpose of which is to change the state in which the Company is incorporated, (C) a reverse merger in which the Company survives as an entity but in which securities possessing more than 50 percent of the total combined voting power of the Company's securities are transferred to a person or persons different from those who hold such securities immediately prior to the merger or (D) the sale or other disposition of all or substantially all of the Company's assets; (ii) the direct or indirect acquisition by any Person or related group of Persons (other than an acquisition from or by the Company or by a Company-sponsored employee benefit plan or by a Person that directly or indirectly controls, is controlled by, or is under common control with, the Company) of beneficial ownership (within the meaning of Rule 13d-3 of the Securities Exchange Act of 1934, as amended) of securities possessing more than 50 percent of the total combined voting power of the Company's outstanding voting securities; or (iii) a change in the composition of the Board over a period of thirty- six (36) months of less such that a majority of the Board members cease, by reason of one or more contested elections for Board membership or by one or more actions by written consent of stockholders, to be comprised of individuals who either (A) have been Board members continuously since the beginning of such period or (B) have been elected or nominated for election as Board members during such period by at least a majority of the Board members described in clause (A) who were still in office at the time such election or nomination was approved by the Board. "Code" means the Internal Revenue Code of 1986, as amended. "Company" means CalEnergy Company, Inc., a Delaware corporation, and any successor or assign permitted under the Agreement. "Disability" means, with respect to the Executive, that the Executive has become physically or mentally incapacitated or disabled so that, in the reasonable judgment of majority of the Chairman of the Board, he is unable to perform his duties under this Agreement and such other services as he performed on behalf of the Company before incurring such incapacity or disability. "Good Reason" means any of the following events, but only if such event(s) occur on, after or in connection with a Change in Control: (i) the failure by the Company to pay to the Executive, for a material period of time and in a material amount, compensation due and payable by the Company under Section 4(a) of this Agreement; (ii) any reduction by the company of the title, office, duties or authority of the Executive in any material respect; or (iii) any relocation of the Executive's primary place of employment to a location more than 25 miles from Omaha, Nebraska. "Permanent Disability" means a Disability which has continued for at least six consecutive calendar months. "Person" means any natural person, general partnership, limited partnership, corporation, joint venture, trust, business trust, or other entity. "Term of Employment" means the period of time beginning on January 11, 1998, and ending on the fifth anniversary of such date, unless earlier terminated pursuant to Section 7(a) or automatically extended pursuant to the following sentence. The Term of Employment will be automatically extended for one year on each anniversary of the date of this Agreement beginning on the fifth anniversary unless the Executive has given the Company, or the Company has given the Executive, a notice declining automatic extension at least 365 calendar days before the anniversary. "Termination Date" means the date of termination of employment of the Executive pursuant to Section 7 of this Agreement. EX-10.36 6 Exhibit 10.36 AMENDMENT NO. 1 TO THE EMPLOYMENT AGREEMENT BETWEEN CALENERGY COMPANY, INC. AND CRAIG M. HAMMETT This Amendment No. 1 (the "Amendment") to the Employment Agreement dated January 11, 1998 (the "Employment Agreement") by and between CalEnergy Company, Inc., a Delaware corporation (the "Company"), and Craig M. Hammett (the "Executive"), is entered into as of January 12, 1998. WHEREAS, the Company and the Executive are presently parties to the Employment Agreement; and WHEREAS, the Company and the Executive desire to amend the Employment Agreement as set forth herein; NOW, THEREFORE, the Employment Agreement is hereby amended as follows: (1) By adding the following sentences at the end of Section 4(c): "The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Chairman of the Board. The Executive's annual incentive merit bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as `Annual Bonus Compensation.'" (2) By adding the following sentence after the last sentence of Section 6(a): "The preceding sentence notwithstanding, if the Executive's resignation occurs upon or after a Change in Control, he shall not be precluded from accepting employment or providing services to Peter Kiewit Sons', Inc. or any affiliate thereof." (3) By deleting from the first sentence of Section 8(b) the language following the parenthetical "(iii)" and replacing it with the following: "commencing one month after the month of his Termination Date, 24 monthly payments each equal to 1/24 of a sum equal to two times the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the year in which the Executive's employment with the Company terminates (with any such year for which no bonus was payable included in such two year average as a zero)." (4) By deleting current Section 8(d) and inserting new Section 8(d), to read as follows: "(d) If the employment of the Executive is terminated pursuant to subsections (ii) or (vi) of Section 7(a), any Performance Accelerated Stock Options ("PASOs") held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date and shall otherwise remain exercisable for their term in accordance with the terms thereof." " (5) By inserting immediately following Section 8(d) a new Section 8(e) to read as follows: "(e) If the employment of the Executive is terminated for any reason after a Change in Control, then without further action by the Company, the Board of any committee thereof, the Executive may exercise any vested stock options (including any vested PASOs) held by the Executive pursuant to existing procedures approved by the Stock Option Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise." (6) By inserting immediately following Section 8 a new Section 8A, which shall read in its entirety as follows: "Section 8A. Certain Additional Payments by the Company. (a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment, distribution, waiver of Company rights, acceleration of vesting of any stock options or restricted stock, or any other payment or benefit in the nature of compensation to or for the benefit of the Executive, alone or in combination (whether such payment, distribution, waiver, acceleration or other benefit is made pursuant to the terms of this Agreement or any other agreement, plan or arrangement providing payments or benefits in the nature of compensation to or for the benefit of the Executive, but determined without regard to any additional payments required under this Section 8A) (a "Payment") would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Executive shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount such that after payment by the Executive of all taxes with respect to the Gross-Up Payment (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. (b) Subject to the provisions of Section 8A(c), all determinations required to be made under this Section 8A, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by Deloitte and Touche LLP, or such other nationally recognized accounting firm then auditing the accounts of the Company (the "Accounting Firm") which shall provide detailed supporting calculations both to the Company and the Executive within 15 business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is unwilling or unable to its obligations pursuant to this Section 8A, the Executive shall appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to hereunder as the Accounting Firm). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any Gross-Up Payment, determined pursuant to this Section 8A, shall be paid by the Company to the Executive within five days of the receipt of the Accounting Firm's determination. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. The parties hereto acknowledge that, as a result of the potential uncertainty in the application of Section 4999 of the Code (or any successor provision) at the time of the initial determination by the Accounting Firm hereunder, it is possible that the Company will not have made Gross-Up Payments which should have been made consistent with the calculations required to be made hereunder (an "Underpayment"). In the event that the Company exhausts its remedies pursuant to Section 8A(c) and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive. (c) The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than 20 business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive shall not pay such claim prior to the expiration of the 30-day period following the date on which he gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall: (i) give the Company any information reasonably requested by the Company relating to such claim, (ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company, (iii) cooperate with the Company in good faith in order effectively to contest such claim, and (iv) permit the Company to participate in any proceedings relating to such claim; providing, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limiting the foregoing provisions of this Section 8A(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest and claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Executive to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Executive, on an interest-free basis, and shall indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. (d) If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 8A(c), the Executive becomes entitled to receive any refund with respect to such claim, the Executive shall (subject to the Company's complying with the requirements of Section 8A(c)) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 8A(c), a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid." Except as provided herein and to the extent necessary to give full effect to the provisions of this Amendment, the terms of the Employment Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have entered into this Amendment effective as of January 12,1998. CALENERGY COMPANY, INC. By:/s/ David L. Sokol Name: David L. Sokol Title: Chairman of the Board EXECUTIVE By:/s/ Craig M. Hammett Craig M. Hammett EX-10.38 7 Exhibit 10.38 AMENDMENT NO. 1 TO THE EMPLOYMENT AGREEMENT BETWEEN CALENERGY COMPANY, INC. AND STEVEN A. MCARTHUR This Amendment No. 1 (the "Amendment") to the Employment Agreement dated August 6, 1996 (the "Employment Agreement") by and between CalEnergy Company, Inc., a Delaware corporation (the "Company"), and Steven A. McArthur (the "Executive"), is entered into as of April 16, 1997. WHEREAS, the Company and the Executive are presently parties to the Employment Agreement; and WHEREAS, the Company and the Executive desire to amend the Employment Agreement as set forth herein; NOW, THEREFORE, the Employment Agreement is hereby amended as follows: (1) By adding the following sentences at the end of Section 4(c): "The Executive shall also be eligible to be paid other bonuses for each fiscal year as determined by the Chairman of the Board. The Executive's annual incentive merit bonus, together with all such other bonuses paid or payable for the fiscal year (including any amounts for which receipt is otherwise deferred pursuant to a plan or arrangement with the Company), is referred to herein as `Annual Bonus Compensation.'" (2) By adding the following sentence after the last sentence of Section 6(a): "The preceding sentence notwithstanding, if the Executive's resignation occurs upon or after a Change in Control, he shall not be precluded from accepting employment or providing services to Peter Kiewit Sons', Inc. or any affiliate thereof." (3) By deleting from the first sentence of Section 8(b) the language following the parenthetical "(iii)" and replacing it with the following: "commencing one month after the month of his Termination Date, 24 monthly payments each equal to 1/24 of a sum equal to two times the average Annual Bonus Compensation payable to the Executive in respect of the two fiscal years immediately preceding the year in which the Executive's employment with the Company terminates (with any such year for which no bonus was payable included in such two year average as a zero)." (4) By deleting current Section 8(d) and inserting new Section 8(d), to read as follows: "(d) If the employment of the Executive is terminated pursuant to subsections (ii) or (vi) of Section 7(a), all Performance Accelerated Stock Options ("PASOs") held by the Executive on the Termination Date will become vested and immediately exercisable on such Termination Date and shall otherwise remain exercisable for their term in accordance with the terms thereof." (5) By inserting immediately following Section 8(d) a new Section 8(e) to read as follows: "(e) If the employment of the Executive is terminated for any reason after a Change in Control, then without further action by the Company, the Board or any committee thereof, the Executive may exercise any vested stock options (including vested PASOs) held by the Executive pursuant to existing procedures approved by the Stock Option Committee for cashless exercise, by surrendering previously owned shares, electing to have the Company withhold shares otherwise deliverable upon exercise of such options, or by providing an irrevocable direction to a broker to sell shares and deliver all or a portion of the proceeds to the Company, in any case in an amount equal to the aggregate exercise price and any tax withholding obligation attendant to the exercise." (6) By inserting immediately following Section 8 a new Section 8A, which shall read in its entirety as follows: "Section 8A. Certain Additional Payments by the Company. (a) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any payment, distribution, waiver of Company rights, acceleration of vesting of any stock options or restricted stock, or any other payment or benefit in the nature of compensation to or for the benefit in the nature of compensation to or for the benefit of the Executive, alone or in combination (whether such payment, distribution, waiver, acceleration or other benefit is made pursuant to the terms of this Agreement or any other agreement, plan or arrangement providing payments or benefits in the nature of compensation to or for the benefit of the Executive, but determined without regard to any additional payments required under this Section 8A) (a "Payment") would be subject to the excise tax imposed by Section 4999 of the Code (or any successor provision) or any interest or penalties are incurred by the Executive with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the "Excise Tax"), then the Executive shall be entitled to receive an additional payment (a "Gross-Up Payment") in an amount such that after payment by the Executive of all taxes with respect to the Gross-Up Payment (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Executive retains an amount of the Gross- Up Payment equal to the Excise Tax imposed on the Payments. (b) Subject to the provisions of Section 8A(c), all determinations required to be made under this Section 8A, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by Deloitte and Touche LLP, or such other nationally recognized accounting firm then auditing the accounts of the Company (the "Accounting Firm") which shall provide detailed supporting calculations both to the Company and the Executive within 15 business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is requested by the Company. In the event that the Accounting Firm is unwilling or unable to perform its obligations pursuant to this Section 8A, the Executive shall appoint another nationally recognized accounting firm to make the determinations required hereunder (which accounting firm shall then be referred to hereunder as the Accounting Firm). All fees and expenses of the Accounting Firm shall be borne solely by the Company. Any Gross-Up Payment, determined pursuant to this Section 8A, shall be paid by the Company to the Executive within five days of the receipt of the Accounting Firm's determination. Any determination by the Accounting Firm shall be binding upon the Company and the Executive. The parties hereto acknowledge that, as a result of the potential uncertainty in the application of Section 4999 of the Code (or any successor provision) at the time of the initial determination by the Accounting Firm hereunder, it is possible that the Company will not have made Gross-Up Payments which should have been made consistent with the calculations required to be made hereunder (an "Underpayment"). In the event that the Company exhausts its remedies pursuant to Section 8A(c) and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be promptly paid by the Company to or for the benefit of the Executive. (c) The Executive shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than 20 business days after the Executive is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive shall not pay such claim prior to the expiration of the 30-day period following the date on which he gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such period that it desires to contest such claim, the Executive shall: (i) give the Company any information reasonably requested by the Company relating to such claim, (ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company, (iii) cooperate with the Company in good faith in order effectively to contest such claim, and (iv) permit the Company to participate in any proceedings relating to such claim; provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limiting the foregoing provisions of this Section 8A(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Executive to pay such claim and sue for a refund, the Company shall advance the amount of such payment to the Executive, on an interest-free basis, and shall indemnify and hold the Executive harmless, on an after- tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. (d) If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 8A(c), the Executive becomes entitled to receive any refund with respect to such claim, the Executive shall (subject to the Company's complying with the requirements of Section 8A(c)) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to Section 8A(c), a determination is made that the Executive shall not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid." Except as provided herein and to the extent necessary to give full effect to the provisions of this Amendment, the terms of the Employment Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the parties hereto have entered into this Amendment effective as of April 16, 1997. CALENERGY COMPANY, INC. By: /s/ David L. Sokol Name: David L. Sokol Title: Chairman of the Board EXECUTIVE /s/ Steven A. McArthur Steven A. McArthur EX-13 8 Exhibit 13 Financial Summary Over the last three years ended December 31, 1997, CalEnergy Company, Inc. ("CalEnergy" or the "Company") has experienced significant growth. Revenues have risen at a compound annual rate of 130% from approximately $186 million in 1994 to approximately $2,271 million in 1997 and net income available to common stockholders excluding non-recurring and extraordinary items has risen at a compound annual rate of 60% from approximately $33.8 million in 1994 to approximately $138.8 million in 1997. This significant growth has been achieved through: (i) acquisitions that complement and diversify the Company's existing business, broaden the geographic locations of its assets and enhance its competitive capabilities; (ii) enhancement of the financial and technical performance of existing and acquired projects; and (iii) development and construction of new plants. On September 11, 1997, the Company signed a definitive agreement with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary of Peter Kiewit Sons', Inc. ("PKS"), for the Company to purchase KDG's ownership interest in various project partnerships and CalEnergy common shares (the "KDG Acquisition"). Accordingly, common stock and options subject to redemption have been reclassified in the consolidated balance sheet. KDG's ownership interest in CalEnergy comprised 20,231,065 shares of common stock (assuming exercise by KDG of one million options to purchase CalEnergy shares), the 30% interest in Northern Electric plc ("Northern"), as well as the following minority project interests: Mahanagdong (45%), Casecnan (35%), Dieng (47%), Patuha (44%) and Bali (30%) and other interests in international development stage projects. CalEnergy paid approximately $1,159 million for the KDG Acquisition and final closing of the transaction occurred in January 1998. CalEnergy funded this acquisition with available cash and the net proceeds of the equity and senior note offerings completed in October 1997. On December 24, 1996, CE Electric plc ("CE Electric"), which in 1997 was 70% owned indirectly by the Company and 30% owned indirectly by PKS, acquired majority ownership of the outstanding ordinary share capital of Northern pursuant to a tender offer (the "Northern Tender Offer") commenced in the United Kingdom on November 5, 1996. As of March 18, 1997, CE Electric effectively owned 100% of Northern's ordinary shares. In the last three years, the Company has consummated three other significant acquisitions, in addition to the acquisition of Northern. In January 1995, the Company acquired Magma Power Company ("Magma"), a publicly-traded United States independent power producer with 228 megawatts ("MW") of aggregate net operating capacity and 154 MW of aggregate net ownership capacity, for approximately $958 million. In April 1996, the Company completed the buy-out for approximately $70 million of its partner's interests ("Partnership Interest") in four electric generating plants in Southern California, resulting in sole ownership of the Imperial Valley Project. In August 1996, the Company acquired Falcon Seaboard Resources, Inc. ("Falcon Seaboard") for approximately $226 million, thereby acquiring significant ownership in 520 MW of natural gas-fired electric production facilities located in New York, Texas and Pennsylvania and a related gas transmission pipeline. The Company has substantially completed constructing the Dieng Unit I, 55 net MW geothermal project in Indonesia, which is the first unit of 400 MW under contract at Dieng. In 1997, the Company financed and commenced construction of two other projects; the Dieng Unit II 80 MW project as well as the Patuha Unit I 80 MW project, which is the first unit of 400 MW under contract at Patuha. Additionally, the Company has conducted infrastructure construction and drilling activities for the 400 MW Bali project. Although the Company intends to enforce its contractual rights, the ultimate outcome of the current uncertain situation in Indonesia with respect to the possible abrogation by the Indonesian government of the Dieng, Patuha and Bali contracts adds significant risk to the completion of those projects and resulted in the Company recording an asset impairment charge in the fourth quarter of 1997. This $87 million charge includes all reasonably estimated asset valuation impairments associated with the Company's assets in Indonesia and gives effect to the political risk insurance on such investment. SELECTED Financial Data Dollars in Thousands, Except Per Share Amounts Year Ended December 31, 1997 1996(1) 1995(2) 1994 1993 Income Statement Data: Operating revenue $2,166,338 $518,934 $335,630 $154,562 $132,059 Total revenue 2,270,911 576,195 398,723 185,854 149,253 Expenses 2,074,051 435,791 301,672 130,018 87,995 Income before provision for income taxes 196,860(3) 140,404 97,051 55,836 61,258 Minority interest 45,993 6,122 3,005 --- --- Income before change in accounting principle and extraordinary item 51,823(3) 92,461 63,415 38,834 43,074 Cumulative effect of change in accounting principle --- --- --- --- 4,100 Extraordinary item (135,850) --- --- (2,007) --- Net income (loss) (84,027)(3) 92,461 63,415 36,827 47,174 Preferred dividends --- --- 1,080 5,010 4,630 Net income (loss) available to common stockholders (84,027)(3) 92,461 62,335 31,817 42,544 Income per share before change in accounting principle and extraordinary item 0.77(3) 1.69 1.32 1.02 1.08 Cumulative effect of change in accounting principle per share --- --- --- --- 0.12 Extraordinary item per share (2.02) --- --- (0.06) --- Net income (loss) per share (1.25)(3) 1.69 1.32 0.96 1.20 Balance Sheet Data: Total assets 7,487,626 5,630,156 2,654,038 1,131,145 715,984 Total liabilities 5,282,162 4,181,052 2,084,474 867,703 425,393 Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts 553,930 103,930 --- --- --- Preferred securities of subsidiary 56,181 136,065 --- --- --- Minority interest 134,454 299,252 --- --- --- Redeemable preferred stock --- --- --- 63,600 58,800 Stockholders' equity 765,326 880,790 543,532 179,991 211,503 1 Reflects the acquisitions of Northern, Falcon Seaboard and the Partnership Interest owned for a portion of the year. See Note 4 to the financial statements. 2 Reflects the acquisition of Magma owned for a portion of the year. 3 Includes the $87,000, $1.29 per share, non-recurring asset impairment charge. MANAGEMENT'S Discussion and Analysis of Financial Condition and Results of Operations Dollars, Pounds and Shares in Thousands, Except Per Share Amounts The following is management's discussion and analysis of certain significant factors which have affected the Company's financial condition and results of operations during the periods included in the accompanying statements of operations. The Company's actual results in the future could differ significantly from the Company's historical results. Acquisitions On December 24, 1996, CE Electric plc ("CE Electric"), which in 1997 was 70% owned indirectly by the Company and 30% owned indirectly by Peter Kiewit Sons', Inc. ("PKS"), acquired majority ownership of the outstanding ordinary share capital of Northern Electric plc ("Northern") pursuant to a tender offer (the "Northern Tender Offer") commenced in the United Kingdom on November 5, 1996. As of March 18, 1997, CE Electric effectively owned 100% of Northern's ordinary shares. In the last three years, the Company has consummated three other significant acquisitions, in addition to the acquisition of Northern. In January 1995, the Company acquired Magma Power Company ("Magma"), a publicly-traded United States independent power producer with 228 megawatts ("MW") of aggregate net operating capacity and 154 MW of aggregate net ownership capacity, for approximately $958,000. In April 1996, the Company completed the buy-out for approximately $70,000 of its partner's interests ("Partnership Interest") in four electric generating plants in Southern California, resulting in sole ownership of the Imperial Valley Project. In August 1996, the Company acquired Falcon Seaboard Resources, Inc. ("Falcon Seaboard") for approximately $226,000, thereby acquiring significant ownership in 520 MW of natural gas-fired electric production facilities located in New York, Texas and Pennsylvania and a related gas transmission pipeline. Power Generation Projects For purposes of consistency in financial presentation, plant capacity factors for Navy I, Navy II, and BLM plants (collectively the "Coso Project"), are based upon a nominal capacity amount of 80 net MW for each plant. Plant capacity factors for Vulcan, Hoch (Del Ranch), Elmore, Leathers plants (collectively the "Partnership Project"), are based on nominal capacity amounts of 34, 38, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II, Salton Sea III and Salton Sea IV plants (collectively the "Salton Sea Project"), are based on nominal capacity amounts of 10, 20, 49.8 and 39.6 net MW, respectively (the Partnership Project and the Salton Sea Project are collectively referred to as the "Imperial Valley Project"). Plant capacity factors for Saranac, Power Resources, NorCon and Yuma plants (collectively the "Gas Plants") are based on capacity amounts of 240, 200, 80 and 50 net MW, respectively. Each plant possesses an operating margin which allows for production in excess of the amount listed above. Utilization of this operating margin is based upon a variety of factors and can be expected to vary throughout the year under normal operating conditions. See Note 5 to the financial statements for a discussion of the Company's significant operating contracts. Results of Operations Three Years Ended December 31, 1997, 1996 and 1995 Operating revenues increased to $2,166,338 in the year ended December 31, 1997, from $518,934 in the year ended December 31, 1996, a 317.5% increase. This growth was primarily due to the acquisitions of Northern, Falcon Seaboard, and the Partnership Interest as well as the commencement of earnings at Salton Sea IV, Upper Mahiao and Malitbog. The increase in operating revenues in 1996 to $518,934 from $335,630 in 1995 was primarily due to the acquisitions of the Partnership Interest, Falcon Seaboard and Northern, the deemed completion and commencement of receipt of revenue from Upper Mahiao and Unit I of the Malitbog Project in the Philippines, the completion and commencement of commercial operation of Salton Sea IV and an increase in the Coso Project's electricity revenues. The following data represents the supply and distribution operations at Northern: 1997 1996 1995 Supply (GWh) 14,389 14,185 14,253 Distribution (GWh) 15,714 15,656 15,260 Gas Therms Supply (in thousands) 74.5 50.0 35.3 The increase in units supplied and distributed in 1997 from 1996 reflects increased activity in the local economy. The increase in therms supplied in 1997 from 1996 reflects the increased volume as the gas business in the U.K. begins to open up to competition as a result of regulatory changes. The following operating data represents the aggregate capacity and electricity production of the domestic geothermal projects: 1997 1996 1995 Overall capacity factor 101.4% 104.4% 104.8% kWh produced (in thousands) 4,507,500 4,502,200 4,296,010 Capacity NMW (average) 507.4 491.0* 467.8 * Weighted average for the commencement of operations at the Salton Sea IV in 1996. The capacity factor was 100.4% in the fourth quarter of 1997 compared to 102.6%, 99.6% and 103.1% for the third, second and first quarters of 1997, respectively. The capacity factor decreased in 1997 from 1996 due to marginally decreasing production at the Coso Project and a scheduled turbine overhaul at BLM in April 1997. The following operating data represents the aggregate capacity and electricity production of the Gas Plants: 1997 1996 1995 Overall capacity factor 84.3% 84.2% 88.8% kWh produced (in thousands) 4,211,030 4,216,800 4,433,900 Installed capacity NMW 570 570 570 The capacity factor of the Gas Plants reflects the effect of certain contractual curtailments. The capacity factors adjusted for these contractual curtailments are 95.7%, 93.2% and 96.8% for 1997, 1996 and 1995, respectively. Electric sale price per kWh for the Coso Project, Partnership Project and Salton Sea Project varies seasonally in accordance with the rate schedule referenced in the SO4 agreements and power purchase agreements. The Coso Project's, Partnership Project's and Salton Sea Project's average electricity prices per kWh received in 1997, 1996 and 1995 were comprised of (in cents): Coso Project Energy Capacity & Bonus Total Average fiscal 1997 12.56 1.91 14.47 Average fiscal 1996 12.61 1.82 14.43 Average fiscal 1995 11.81 1.82 13.63 Partnership Project Energy Capacity & Bonus Total Average fiscal 1997 10.96 2.18 13.14 Average fiscal 1996 10.02 2.12 12.14 Average fiscal 1995 11.14 2.10 13.24 Salton Sea Project Energy Capacity & Bonus Total Average fiscal 1997 8.66 1.97 10.63 Average fiscal 1996 8.84 2.29 11.13 Average fiscal 1995 9.50 2.33 11.83 Interest and other income increased in 1997 to $104,573 from $57,261 in 1996, an 82.6% increase. This increase was due primarily to interest earned by Northern, equity earnings from Saranac and Mahanagdong, and increased interest income on the proceeds of the equity and senior note offerings in October 1997. Interest and other income decreased in 1996 to $57,261 from $63,093 in 1995. Overall, the Company's expenses increased in 1997 due to the full year of operations of Northern, Falcon Seaboard, Partnership Interest, Salton Sea IV Project, Upper Mahiao Project and Unit I of the Malitbog Project and the deemed completion of Units II and III of the Malitbog Project in July 1997. Cost of sales increased to $1,055,195 in 1997 from $31,840 in 1996. This increase is a result of reflecting a full year of Northern's operations. Cost of sales represents Northern's costs of electricity and appliances during the period of the Company's controlling interest since December 24, 1996. Operating expense increased to $345,833 in 1997 from $132,655 in 1996, an increase of 160.7%. This increase is a result of the acquisitions of Northern, Falcon Seaboard and the Partnership Interest as well as the commencement of receipt of revenue at Salton Sea IV, Upper Mahiao and Malitbog. Operating expense increased to $132,655 in 1996 from $103,602 in 1995, an increase of 28.0%. The increase is a result of the Falcon Seaboard and the Partnership Interest acquisitions, and the commencement of operations of the Salton Sea IV Project. General and administration costs increased to $52,705 in 1997 from $21,451 in 1996, an increase of 145.7%. This increase is primarily a result of the addition of Northern. General and administration costs decreased to $21,451 in 1996 from $23,376 in 1995, a decrease of 8.2%. This decrease is a result of the Company's continued efforts to reduce costs and reflects the elimination of redundant functions subsequent to the acquisition of Magma. Depreciation and amortization increased to $276,041 in 1997 from $118,586 in 1996, an increase of 132.8%. This increase is a result of the acquisitions of Northern, Falcon Seaboard and the Partnership Interest as well as the commencement of the receipt of revenue at Salton Sea IV, Upper Mahiao and Malitbog. Depreciation and amortization increased in 1996 to $118,586 from $72,249 in 1995, a 64.1% increase. This increase is primarily due to the Magma, Partnership Interest and Falcon Seaboard acquisitions, and the commencement of the receipt of revenue at Salton Sea IV, Upper Mahiao and Malitbog. Loss on equity investment in the Casecnan Project reflects the Company's share of interest expense in excess of capitalized interest and interest income at the Casecnan Project, which is currently in construction. Interest expense, less amounts capitalized, increased in 1997 to $251,305 from $126,038 in 1996, a 99.4% increase, and increased to $126,038 in 1996 from $102,083 in 1995, a 23.5% increase. Higher interest expense is primarily due to a larger portfolio of facilities and their associated debt partially offset by the increase in capitalized interest on the Company's international and domestic projects. The non-recurring charge of $87,000 represents an asset valuation impairment under Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets", relating to CalEnergy's assets in Indonesia. The charge includes all reasonably estimated cash flows associated with the Company's assets in Indonesia and gives effect to the political risk insurance on such investments. The estimate assumes there will be no tax benefits associated with the asset valuation impairment. The provision for income taxes increased to $99,044 in 1997 from $41,821 in 1996 and $30,631 in 1995. After adjusting for the non- recurring charge for asset valuation impairment and the dividends on convertible preferred securities, the effective tax rate was 38.0%, 30.8%, and 31.6% in 1997, 1996, and 1995, respectively. The increase from 1996 to 1997 is due primarily to larger energy tax credits and depletion deductions in 1996. Minority interest increased to $45,993 in 1997 from $6,122 in 1996, an increase of 651.3%. Minority interest consists of dividends on convertible preferred securities of subsidiary trusts and the Company's partial ownership in Northern. This increase is a result of issuance of the $180,000 of Trust II Securities in February 1997 and $270,000 of Trust III Securities in August 1997 and a full year of operations from Northern. Minority interest in 1995 reflects the Company's partial ownership in Magma for the period from January 10, 1995 to February 24, 1995. Income before extraordinary item was $51,823 or $0.77 per common share in 1997 compared to $92,461 or $1.69 per common share in 1996 and $62,335 or $1.32 per common share in 1995. Excluding the $87,000, $1.29 per share, non-recurring charge, income before extraordinary item would have been $138,823 in 1997. On July 31, 1997, the Finance Act in the United Kingdom was passed by Parliament and included the introduction of a one time so-called "windfall tax" equal to 23% of the difference between the price paid for Northern upon privatization and the Labour government's assessed "value" of Northern as calculated by reference to a formula set forth in the July budget. This amounted to $135,850, net of minority interest, which was recorded as an extraordinary item. The first installment was paid on December 1, 1997 and the second installment is payable on December 1, 1998. Liquidity and Capital Resources Cash and short-term investments were $1,446,620 at December 31, 1997 as compared to $429,421 at December 31, 1996. In addition, the Company's share of joint venture cash and investments retained in project control accounts was $6,072 and $47,764 at December 31, 1997 and 1996, respectively. Distributions out of the project control accounts are made monthly to the Company for operation and maintenance and capital costs and semiannually to each Coso Project partner for profit sharing under a prescribed calculation subject to mutual agreement by the partners. In addition, the Company recorded separately restricted cash of $223,636 and $106,968 at December 31, 1997 and 1996, respectively. The restricted cash balances are comprised primarily of amounts deposited in restricted accounts from which the Company will fund construction of Dieng Unit II and Patuha Unit I; the Power Resources Project, the Upper Mahiao Project and the Malitbog Project cash reserves for the debt service reserve funds; and the Coso Project royalty payment. The Company repurchased 1,622 common shares during 1997 for the aggregate amount of $55,505. The Company repurchased 472 shares of common stock in 1996 at an aggregate amount of $12,008. As of December 31, 1997 the Company held 1,658 shares of treasury stock at a cost of $56,525 to provide shares for issuance under the Company's employee stock option and share purchase plan and other outstanding convertible securities. The repurchase plan minimizes the dilutive effect of the additional shares issued under these plans. On September 11, 1997, the Company signed a definitive agreement with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary of PKS, for the Company to purchase KDG's ownership interest in various project partnerships and CalEnergy common shares (the "KDG Acquisition"). KDG's ownership interest in CalEnergy comprised approximately 20,231 shares of common stock (assuming exercise by KDG of one million options to purchase CalEnergy shares), the 30% interest in Northern Electric, as well as the following minority project interests: Mahanagdong (45%), Casecnan (35%), Dieng (47%), Patuha (44%) and Bali (30%) and other interests in international development projects. CalEnergy paid $1,159,215 for the KDG Acquisition and final closing of the transaction occurred in January 1998. CalEnergy funded this acquisition with available cash and the proceeds of the equity and senior note offerings completed in October 1997. On December 15, 1997, CE Electric UK Funding Company, an indirect subsidiary of the Company (the "Funding Company"), issued $125,000 of 6.853% senior notes due 2004, and $237,000 of 6.995% senior notes due 2007 (collectively, the "CE Electric UK Funding Company Senior Notes"), and pound 200,000 of 7.25% Sterling Bonds due 2022. On November 26, 1997, the Company amended and increased its $100,000 revolving credit facility to $400,000. The facility is unsecured and is available to fund working capital requirements and finance future business expansion opportunities. On October 17, 1997, the Company completed the public offering of 17.1 million shares of its common stock ("Common Stock") at $37 7/8 per share (the "Public Offering"). In addition, 2 million shares of Common Stock were purchased from CalEnergy in a direct sale by a trust affiliated with Walter Scott, Jr., the Chairman and Chief Executive Officer of PKS (the "Direct Sale"), contemporaneously with the closing of the Public Offering. On October 28, 1997, the Company completed the sale of $350,000 aggregate principal amount of its 7.63% Senior Notes due 2007 (the "Senior Note Offering"). On August 12, 1997, a subsidiary of the Company completed a private placement (with certain shelf registration rights) of $225,000 aggregate amount of 6 1/2% Trust Convertible Preferred Securities (the "6 1/2% Trust Securities"). In addition, an option to purchase an additional 900 of the 6 1/2% Trust Securities, or $45,000 aggregate amount, was exercised by the initial purchasers to cover overallotments in connection with the placement. Each 6 1/2% Trust Security has a liquidation preference of fifty dollars and is convertible at any time at the option of the holder into 1.047 shares of Company Common Stock (equivalent to a conversion price of $47.75 per common share) subject to adjustments in certain circumstances. On August 5, 1997, the Company and certain affiliated capital funding trusts filed with the Securities and Exchange Commission a shelf registration statement covering up to $1,500,000 of common stock, preferred stock and debt securities which may be sold from time to time for various purposes. The Company completed the Public Offering and the Senior Note Offering under the shelf registration statement. On February 26, 1997, a subsidiary of the Company completed a private placement (with certain shelf registration rights) of $150,000 aggregate amount of 6 1/4% Trust Convertible Preferred Securities ("Trust Securities"). In addition, an option to purchase an additional 600 Trust Securities, or $30,000 aggregate amount, was exercised by the initial purchasers to cover over- allotments in connection with the placement. Each Trust Security has a liquidation preference of fifty dollars and is convertible at any time at the option of the holder into 1.1655 shares of Company Common Stock (equivalent to a conversion price of $42.90 per common share) subject to adjustments in certain circumstances. In November 1995, the Company closed the financing and commenced construction of the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project (the "Casecnan Project") located in the central part of the island of Luzon in the Republic of the Philippines. CE Casecnan Water and Energy Company, Inc., a Philippine Corporation ("CE Casecnan") which is approximately 70% indirectly owned by the Company (after the KDG Acquisition), is developing the Casecnan Project. CE Casecnan financed a portion of the costs of the Casecnan Project through the issuance of $125,000 of its 11.45% Senior Secured Series A Notes due 2005 and $171,500 of its 11.95% Senior Secured Series B Bonds due 2010 and $75,000 of its Secured Floating Rate Notes due 2002, pursuant to an indenture dated as of November 27, 1995, as amended to date. The Casecnan Project was being constructed pursuant to a fixed- price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As of May 7, 1997, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of each such company. On May 7, 1997, CE Casecnan entered into a new turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impressa Pizzarottie & C. Spa, working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Replacement Contractor"). In connection with the Hanbo Contract termination, CE Casecnan tendered a certificate of drawing to Korea First Bank ("KFB") on May 7, 1997, under the irrevocable standby letter of credit issued by KFB as security under the Hanbo Contract to pay for certain transition costs and other presently ascertainable damages under the Hanbo Contract. As a result of KFB's wrongful dishonor of the draw request, CE Casecnan filed an action in New York State Court. That Court granted CE Casecnan's request for a temporary restraining order requiring KFB to deposit $79,329, the amount of the requested draw, in an interest bearing account with an independent financial institution in the United States. KFB appealed this order, but the appellate court denied KFB's appeal and on May 19, 1997, KFB transferred funds in the amount of $79,329 to a segregated New York bank account pursuant to the Court order. On August 6, 1997, CE Casecnan announced that it had issued a notice to proceed to the Replacement Contractor. The Replacement Contractor has fully mobilized and commenced engineering, procurement and construction work on the Casecnan Project. On August 27, 1997, CE Casecnan announced that it had received a favorable summary judgment ruling in New York State Court against KFB. The judgment, which has been appealed by the bank, requires KFB to honor the $79,329 drawing by CE Casecnan on a $117,850 irrevocable standby letter of credit. On September 29, 1997, CE Casecnan tendered a second certificate of drawing for $10,828 to KFB and on December 30, 1997 CE Casecnan tendered a third certificate of drawing for $2,920 to KFB. KFB also wrongfully dishonored these draws, but pursuant to a stipulation agreed to deposit the draw amounts in an interest bearing account with the same independent financial institution in the United States pending resolution of the appeal regarding the first draw and agreed to expedite the appeal. The receipt of the letter of credit funds from KFB remains essential and CE Casecnan will continue to press KFB to honor its clear obligations under the letter of credit and to pursue Hanbo and KFB for any additional damages arising out of their actions to date. If KFB were to fail to honor its obligations under the Casecnan letter of credit, such action could have a material adverse effect on the Casecnan Project and CE Casecnan. On September 2, 1997, Hanbo and HECC filed a Request for Arbitration before the International Chamber of Commerce ("ICC"). The Request for Arbitration asserts various claims by Hanbo and HECC against CE Casecnan relating to the terminated Hanbo Contract and seeking damages. On October 10, 1997, CE Casecnan served its answer and defenses in response to the Request for Arbitration as well as counterclaims against Hanbo and HECC for breaches of the Hanbo Contract. The arbitration proceedings before the ICC are ongoing and CE Casecnan intends to pursue vigorously its claims against Hanbo, HECC and KFB in the proceedings described above. In June 1997, the Company's indirect special-purpose subsidiary, CE Indonesia Funding Corp., entered into a $400,000 revolving credit facility (which is nonrecourse to the Company) to finance the development and construction of the Company's geothermal power facilities in Indonesia. On September 20, 1997, a Presidential Decree (the "Decree") was issued in Indonesia, providing for government action to the effect that, in order to address certain recent fluctuations in the value of the Indonesian currency, the start-up dates for a number of private power projects would be: (i) continued according to their initial schedule (because construction was underway); (ii) postponed as to their start-up dates (because they are not yet in construction) until economic conditions have recovered; or (iii) reviewed with a view to being continued, postponed or rescheduled, depending on the status of those projects. In the Decree, Dieng Units 1, 2 and 3 are approved to continue according to their initial schedule; Patuha Unit 1 and Bali Units 1 and 2 are to receive further review to determine whether or not they should be continued in accordance with their initial schedule; and Bali Units 3 and 4, Patuha Units 2, 3 and 4 and Dieng Unit 4 are to be postponed for an unspecified period. In this regard, the Company notes that its contracts and government undertakings for the Dieng, Patuha and Bali projects do not by their terms permit such categorization or delays by the government and that the Company has obtained political risk insurance coverage for its Dieng and Patuha projects. Moreover, the Company intends to continue to take actions to attempt to require the Government of Indonesia to honor its contractual obligations; however, subsequent actions by the Government of Indonesia and continued economic problems in Indonesia have created further uncertainty as to whether the contracts for such projects will be abrogated by the Indonesian government and accordingly have created significant risks to the completion of these projects. As a result, the Company recorded a SFAS 121 asset valuation impairment charge of $87,000 in the fourth quarter of 1997. This charge includes all reasonably estimated asset valuation impairments associated with the Company's assets in Indonesia and gives effect to the political risk insurance on such investments. On December 2, 1994, a subsidiary of the Company, Himpurna California Energy Ltd. ("HCE") executed a joint operation contract (the "Dieng JOC") for the development of the geothermal steam field and geothermal power facilities at the Dieng geothermal field, located in Central Java (the "Dieng Project") with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara ("Pertamina"), the Indonesian national oil company, and executed a "take-or-pay" energy sales contract (the "Dieng ESC") with both Pertamina and P.T. PLN (Persero) ("PLN"), the Indonesian national electric utility. HCE was formed pursuant to a joint development agreement with P.T. Himpurna Enersindo Abadi ("P.T. HEA"), its Indonesian partner, which is a subsidiary of Himpurna, whereby the Company and P.T. HEA have agreed to work together on an exclusive basis to develop the Dieng Project (the "Dieng Joint Venture"). Subsequent to the January 1998 KDG acquisition, the Dieng Joint Venture is structured with subsidiaries of the Company holding an approximate 94% interest (including certain assignments of dividend rights representing an economic interest of 4%), and P.T. HEA holding a 6% interest in the Dieng Project. Financial closing and first disbursement of construction loan funds occurred on October 3, 1996. Construction of Dieng Unit I is expected to be completed in March 1998. Pursuant to the Dieng JOC and ESC, Pertamina has granted to HCE the geothermal field and the wells and other facilities presently located thereon and HCE may build, own and operate power production units with an aggregate capacity of up to 400 MW. HCE will accept the field operation responsibility for developing and supplying the geothermal steam and fluids required to operate the plant. The Dieng JOC is structured as a build own operate transfer agreement and will expire (subject to extension by mutual agreement) on the date which is the later of (i) 42 years following effectiveness of the Dieng JOC and (ii) 30 years following the date of commencement of commercial generation of the final unit. Upon the expiration of the proposed Dieng JOC, all facilities will be transferred to Pertamina at no cost. HCE began well testing in the fourth quarter of 1995 and issued a notice to proceed for the construction and supply of an initial 55 net MW unit ("Dieng Unit I") in the first quarter of 1996. PT Kiewit/Holt Indonesia, a consortium including Kiewit Construction Group, Inc., a subsidiary of PKS ("KCG"), is constructing Dieng Unit I pursuant to a fixed price, date certain, turnkey construction contract ("Construction Contract"). Affiliates of KCG are providing the engineered supply with respect to Dieng Unit I pursuant to a fixed price, date certain, turnkey supply contract ("Supply Contract"). The Construction Contract and Supply Contract are sometimes referred to herein as the "Dieng EPC" and KCG and their affiliates party to the Construction Contract and Supply Contract are sometimes referred to herein, collectively, as the "Construction Consortium." The obligations of the Construction Consortium under the Construction and Supply Contracts are supported by a guaranty of KCG. KCG is the lead member of the Construction Consortium, with a 60% interest. HCE will be responsible for operating and managing the Dieng Project. In the fourth quarter of 1997, HCE issued a notice to proceed and closed the project financing for the construction and supply of the Dieng Unit II 80 net MW project. The same construction consortium as described above for Dieng Unit I has contracted to construct Dieng Unit II under similar terms. The Company has contributed the necessary equity for the completion of Dieng Unit II and the construction loan of $109,000 was arranged under the June 1997 CE Indonesia Funding Corp. facility. However, pending resolution of the current uncertainties associated with Indonesia, construction activities on this project have been significantly reduced. Patuha Power, Ltd. ("Patuha Power") is developing a geothermal power plant in the Patuha geothermal field in Java, Indonesia (the "Patuha Project"). On December 2, 1994, Patuha Power executed both a joint operation contract and an energy sales contract, each of which contains terms substantially similar to those described above for the Dieng Project. Patuha Power began well testing and exploration in the fourth quarter of 1995 and in the third quarter of 1997, issued a notice to proceed for the construction and supply of the Patuha Unit I 80 net MW project. The same construction consortium as described above for Dieng Unit I has contracted to construct Patuha Unit I under similar terms. The Company has contributed the necessary equity for the completion of Patuha Unit I and the construction loan of $150,000 was arranged under the June 1997 CE Indonesia Funding Corp. facility. However, pending resolution of the current uncertainties associated with Indonesia, construction activities on this project have been significantly reduced. The Company and PT Panutan Group, an Indonesian consortium of energy, oil, gas and mining companies, have formed a joint venture to pursue the development of geothermal resources in Bali (the "Bali Project"). The PT Panutan Group is entitled to contribute up to 40% of the total equity and obtain up to 40% of the net profit of the Bali Project. The project company developing the Bali Project, Bali Energy Ltd. ("Bali Energy"), has executed both a joint operation contract and an energy sales contract with terms similar to those at Dieng and Patuha. However, pending resolution of the current uncertainties associated with Indonesia, infrastructure construction and drilling activities on this project have been significantly reduced. The Company developed and owns the rights to a proprietary process for the extraction of minerals from elements in solution in the geothermal brine and fluids utilized at its Imperial Valley plants (the "Salton Sea Extraction Project") as well as the production of power to be used in the extraction process. The initial phase of the project would require delivery of 49 net MW of power. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Project. Zinc is primarily used in galvanizing steel for use in the automobile industry. The Company intends to sequentially develop manganese, silver, gold, lead, boron, lithium and other products as it further develops the extraction technology. The Company is also investigating producing silica from the solids precipitated out of the geothermal power process. Silica is used as a filler for such products as paint, plastics and high temperature cement. If successfully developed, the mineral extraction process will provide an environmentally responsible and low cost minerals recovery methodology. Subsidiaries of Magma, a subsidiary of the Company, sought new long-term final SO4 power purchase agreements in the Salton Sea area through the bidding process adopted by the California Public Utilities Commission ("CPUC") under its 1992 Biennial Resource Plan Update ("BRPU"). In its BRPU, the CPUC cited the need for an additional 9,600 MW of power production through 1999 among California's three investor-owned utilities, Southern California Edison Company ("Edison"), San Diego Gas and Electric ("SDG&E") and Pacific Gas and Electric Company. Of this amount, 275 MW was set aside for bidding by independent power producers (such as Magma) utilizing renewable resources. Pursuant to an order of the CPUC dated June 22, 1994 (confirmed on December 21, 1994), Magma was awarded 163 net MW for sale to Edison and SDG&E, with in- service dates in 1997 and 1998. On February 23, 1995 the Federal Energy Regulatory Commission ("FERC") issued an order finding that the CPUC's BRPU program violated the Public Utilities Regulatory Policies Act ("PURPA") and FERC's implementing regulations and recommended negotiated settlements. In response, the CPUC issued an Assigned Commissioners Ruling encouraging settlements between the final winning bidders and the utilities. The utilities are expected to continue to challenge the BRPU and, in light of the regulatory uncertainty, there can be no assurance that power sales contracts will be executed or that any such projects will be completed. In light of these developments, the Company agreed to execute an agreement with Edison on March 16, 1995, providing that in certain circumstances it would withdraw its Edison BRPU bid in consideration for the payment of certain sums. In December 1996, the Company entered into a confidential cash buyout agreement with SDG&E. These agreements are subject to CPUC approval. Within the United Kingdom there was continued investment to extend and improve the electricity distribution network. Expenditures in the year were approximately $102,000 although customers directly contributed approximately $33,000 to the additional costs incurred in expanding the system to meet their specific requirements. The Company is actively seeking to develop, construct, own and operate new energy projects, both domestically and internationally, the completion of any of which is subject to substantial risk. Development can require the Company to expend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses in preparation for competitive bids which the Company may not win or before it can be determined whether a project is feasible, economically attractive or capable of being financed. Successful development and construction is contingent upon, among other things, negotiation on terms satisfactory to the Company of engineering, construction, fuel supply and power sales contracts with other project participants, receipt of required governmental permits and consents and timely implementation of construction. There can be no assurance that development efforts on any particular project, or the Company's development efforts generally, will be successful. The Company believes that the international independent power market holds the majority of new opportunities for financially attractive private power generation development in the next several years. The financing, construction and development of projects outside the United States entail significant political and financial risks (including, without limitation, uncertainties associated with first time privatization efforts in the countries involved, currency exchange rate fluctuations, currency repatriation restrictions, political instability, civil unrest and expropriation) and other structuring issues that have the potential to cause substantial delays or material impairment of value to the project being developed, which the Company may not be fully capable of insuring against. The uncertainty of the legal environment in certain foreign countries in which the Company may develop or acquire projects could make it more difficult for the Company to enforce its rights under agreements relating to such projects. In addition, the laws and regulations of certain countries may limit the ability of the Company to hold a majority interest in some of the projects that it may develop or acquire. The Company's international projects may, in certain cases, be terminated by a government. Projects in operation, construction and development are subject to a number of uncertainties, more specifically described in the Company's Form 8-K dated March 6, 1998, filed with the Securities and Exchange Commission and incorporated herein by reference. Inflation has not had a substantial impact on the Company's operating revenues and costs; energy payments for electricity for the Coso Project, Partnership Project, Salton Sea II Project and Salton Sea III Project will continue to be based upon scheduled rates and are not adjusted for inflation through the initial ten year period after the dates of firm operation under each power purchase agreement. The Company has commenced, for all of its information systems, a year 2000 date conversion project to address all necessary code changes, testing and implementation. The "Year 2000 Computer Problem" creates risk for the Company from unforeseen problems in its own computer systems and from third parties with whom the Company deals on financial transactions worldwide. Such failures of the Company's and/or third parties' computer systems could have a material impact on the Company's ability to conduct its business, and especially to process and account for the transfer of funds electronically. Management believes that the year 2000 implementation costs and related potential effect should not have a material financial impact on the Company. CONSOLIDATED BALANCE SHEETS As of December 31, 1997 and 1996 Dollars and Shares in Thousands, Except Per Share Amounts ASSETS 1997 1996 Cash and cash equivalents (Note 3) $ 1,445,338 $ 424,500 Joint venture cash and investments 6,072 47,764 Restricted cash 223,636 106,968 Short-term investments 1,282 4,921 Accounts receivable 376,745 342,307 Properties, plants, contracts and equipment, net 3,528,910 3,225,496 Excess of cost over fair value of net assets acquired, net 1,312,788 790,920 Equity investments 238,025 238,856 Deferred charges and other assets 354,830 448,424 Total assets $ 7,487,626 $ 5,630,156 LIABILITIES AND STOCKHOLDERS' EQUITY Liabilities: Accounts payable $ 173,610 $ 218,164 Other accrued liabilities 1,106,641 668,612 Parent company debt 1,303,845 1,146,685 Subsidiary and project debt 2,189,007 1,678,392 Deferred income taxes 509,059 469,199 Total liabilities 5,282,162 4,181,052 Deferred income 40,837 29,067 Commitments and contingencies (Notes 3, 18, 19 and 20) Company - obligated mandatorily redeemable convertible preferred securities of subsidiary trusts 553,930 103,930 Preferred securities of subsidiary 56,181 136,065 Minority interest 134,454 299,252 Common stock and options subject to redemption 654,736 --- Stockholders' equity: Preferred stock - authorized 2,000 shares, no par value --- --- Common stock - par value $.0675 per share, authorized 180,000 shares, issued 82,980 and 63,747 shares, outstanding 81,322 and 63,448 shares, respectively 5,602 4,303 Additional paid in capital 1,261,081 563,567 Retained earnings 213,493 297,520 Cumulative effect of foreign currency translation adjustment (3,589) 29,658 Common stock and options subject to redemption (654,736) --- Treasury stock - 1,658 and 299 common shares at cost (56,525) (8,787) Unearned compensation - restricted stock --- (5,471) Total stockholders' equity 765,326 880,790 Total liabilities and stockholders' equity $ 7,487,626 $ 5,630,156 The accompanying notes are an integral part of these financial statements. CONSOLIDATED STATEMENTS OF OPERATIONS For the Three Years Ended December 31, 1997 Dollars and Shares in Thousands, Except Per Share Amounts 1997 1996 1995 Revenue: Operating revenue $2,166,338 $ 518,934 $ 335,630 Interest and other income 104,573 57,261 63,093 Total revenues 2,270,911 576,195 398,723 Costs and expenses: Cost of sales 1,055,195 31,840 --- Operating expense 345,833 132,655 103,602 General and administration 52,705 21,451 23,376 Depreciation and amortization 276,041 118,586 72,249 Loss on equity investment in Casecnan 5,972 5,221 362 Interest expense 296,364 165,900 134,637 Less interest capitalized (45,059) (39,862) (32,554) Non-recurring charge - asset valuation impairment 87,000 --- --- Total costs and expenses 2,074,051 435,791 301,672 Income before provision for income taxes 196,860 140,404 97,051 Provision for income taxes 99,044 41,821 30,631 Income before minority interest 97,816 98,583 66,420 Minority interest 45,993 6,122 3,005 Income before extraordinary item 51,823 92,461 63,415 Extraordinary item, net of minority interest of $58,222 (135,850) --- --- Net income (loss) (84,027) 92,461 63,415 Preferred dividends --- --- 1,080 Net income (loss) available to common stockholders $ (84,027) $ 92,461 $ 62,335 Income per share before extraordinary item $ 0.77 $ 1.69 $ 1.32 Extraordinary item $ (2.02) $ --- $ --- Net income (loss) per share $ (1.25) $ 1.69 $ 1.32 Income per share before extraordinary item - diluted $ 0.75 $ 1.54 $ 1.22 Extraordinary item - diluted $ (1.97) $ --- $ --- Net income (loss) per share - diluted $ (1.22) $ 1.54 $ 1.22 The accompanying notes are an integral part of these financial statements. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY For the Three Years Ended December 31, 1997 Dollars and Shares in Thousands
Common Stock Outstanding Additional Foreign & Options Common Common Paid-In Retained Currency Subject to Treasury Unearned Shares Stock Capital Earnings Adjust. Redemption Stock Compensation Total Balance December 31, 1994 31,849 $2,407 $100,421 $142,937 $ --- $ --- $(65,774) $ --- $179,991 Equity offering 18,170 1,004 240,825 --- --- --- 56,801 --- 298,630 Restricted stock 500 --- 848 --- --- --- 8,652 (9,500) --- Exercise of stock options and other equity transactions 176 10 446 --- --- --- 563 2,494 3,513 Purchase of treasury stock (102) --- --- --- --- --- (1,590) --- (1,590) Preferred stock dividends, Series C, including cash distribution of $43 --- --- --- (1,293) --- --- --- --- (1,293) Tax benefit from stock plan --- --- 866 --- --- --- --- --- 866 Net income before preferred dividends --- --- --- 63,415 --- --- --- --- 63,415 Balance December 31, 1995 50,593 3,421 343,406 205,059 --- --- (1,348) (7,006) 543,532 Exercise of stock options and other equity transactions 5,263 337 53,030 --- --- --- 4,569 1,535 59,471 Purchase of treasury stock (472) --- --- --- --- --- (12,008) --- (12,008) Conversion of debt 8,064 545 164,912 --- --- --- --- --- 165,457 Tax benefit from stock plan --- --- 2,219 --- --- --- --- --- 2,219 Foreign currency translation adjustment --- --- --- --- 29,658 --- --- --- 29,658 Net income --- --- --- 92,461 --- --- --- --- 92,461 Balance December 31, 1996 63,448 4,303 563,567 297,520 29,658 --- (8,787) (5,471) 880,790 Equity offering 19,100 1,289 697,315 --- --- --- --- --- 698,604 Exercise of stock options and other equity transactions 396 10 (2,757) --- --- --- 7,767 5,471 10,491 Purchase of treasury stock (1,622) --- --- --- --- --- (55,505) --- (55,505) Common stock and options subject to redemption --- --- --- --- --- (654,736) --- --- (654,736) Tax benefit from stock plan --- --- 2,956 --- --- --- --- --- 2,956 Foreign currency translation adjustment --- --- --- --- (33,247) --- --- --- (33,247) Net loss --- --- --- (84,027) --- --- --- --- (84,027) Balance December 31, 1997 81,322 $5,602 $1,261,081 $213,493$(3,589)$(654,736) $(56,525)$ ---$ 765,326
The accompanying notes are an integral part of these financial statements. CONSOLIDATED STATEMENTS OF CASH FLOWS For the Three Years Ended December 31, 1997 Dollars in Thousands 1997 1996 1995 Cash flows from operating activities: Net income (loss) $ (84,027) $ 92,461 $ 63,415 Adjustments to reconcile net cash flow from operating activities: Non-recurring charge-asset valuation impairment 87,000 --- --- Depreciation and amortization 239,234 109,447 65,244 Amortization of excess of cost over fair value of net assets acquired 36,807 9,139 7,005 Amortization of original issue discount 2,160 50,194 45,409 Amortization of deferred financing costs 26,161 9,677 8,979 Amortization of unearned compensation 5,471 1,535 2,494 Provision for deferred income taxes 55,584 12,252 13,983 Loss (income) on equity investments (16,068) (910) 362 Income (loss) applicable to minority interest (35,387) 1,431 3,005 Changes in other items: Accounts receivable (34,146) (13,936) 213 Accounts payable, accrued liabilities and deferred income 29,799 2,093 12,103 Net cash flows from operating activities 312,588 273,383 222,212 Cash flows from investing activities: Purchase of Northern, Falcon Seaboard, Partnership Interest and Magma, net of cash acquired (632,014) (474,443) (907,614) Distributions from equity investments 23,960 8,222 --- Capital expenditures relating to operating projects (194,224) (24,821) (27,120) Philippine construction (27,334) (167,160) (289,655) Indonesian and other development (155,963) (81,068) (8,973) Salton Sea IV construction --- (63,772) (62,430) Pacific Northwest, Nevada, and Utah exploration costs (3,128) (4,885) (10,445) Decrease in short-term investments 2,880 33,998 80,565 Decrease (increase) in restricted cash (116,668) 63,175 (17,452) Other 60,390 (2,910) 11,514 Investment in Casecnan --- --- (61,177) Net cash flows from investing activities (1,042,101) (713,664) (1,292,787) Cash flows from financing activities: Proceeds from sale of common and treasury stock and exercise of stock options 703,624 54,935 299,649 Proceeds from convertible preferred securities of subsidiary trusts 450,000 103,930 --- Proceeds from issuance of parent company debt 350,000 324,136 200,000 Repayment of parent company debt (100,000) --- --- Net proceeds from revolver (95,000) 95,000 --- Proceeds from subsidiary and project debt 795,658 428,134 654,695 Repayments of subsidiary and project debt (271,618) (210,892) (176,664) Deferred charges relating to debt financing (48,395) (36,010) (34,733) Purchase of treasury stock (55,505) (12,008) (1,590) Other 13,142 10,756 (29,169) Net cash flows from financing activities 1,741,906 757,981 912,188 Effect of exchange rate changes (33,247) 4,860 --- Net increase (decrease) in cash and investments 979,146 322,560 (158,387) Cash and cash equivalents at beginning of year 472,264 149,704 308,091 Cash and cash equivalents at end of year $ 1,451,410 $ 472,264 $ 149,704 Supplemental Disclosures: Interest paid (net of amounts capitalized)$ 316,060 $ 92,829 $ 50,840 Income taxes paid $ 44,483 $ 23,211 $ 14,812 The accompanying notes are an integral part of these financial statements. NOTES Consolidated Financial Statements For the Three Years Ended December 31, 1997 Dollars, Pounds and Shares in Thousands, Except Per Share Amounts 1. Business CalEnergy Company, Inc. (the "Company") is a United States-based global power company which generates, distributes and supplies electricity to utilities, government entities, retail customers and other customers located throughout the world. The Company was founded in 1971 and through its subsidiaries is primarily engaged in the development, ownership and operation of environmentally responsible independent power production facilities worldwide utilizing geothermal, natural gas, hydroelectric and other energy sources. In addition, the Company is engaged in the distribution and supply of electricity to approximately 1.5 million customers primarily in northeast England as well as the generation and supply of electricity (together with other related business activities) throughout England and Wales. The Company is also active in supplying gas and has applications for over 400,000 customers in those areas of England, Wales and Scotland where retail gas competition has been introduced. The Company has organized several partnerships and joint ventures (herein referred to as the "Coso Joint Ventures") in order to develop geothermal energy at the China Lake Naval Air Weapons Station, Coso Hot Springs, China Lake, California. Collectively, the projects undertaken by these Coso Joint Ventures are referred to as the Coso Project. In 1992, the Company entered into the natural gas-fired electrical generation market through the purchase of a development opportunity in Yuma, Arizona which commenced commercial operation in May 1994. In 1993, the Company started developing a number of international power project opportunities where private power generating programs have been initiated, including the Philippines and Indonesia. In 1995, the Company acquired Magma Power Company ("Magma"). Magma's operating assets included four projects referred to as the Partnership Project in which Magma had a 50% interest, and three projects referred to as the Salton Sea Project of which Magma owned 100%. A fourth project included in the Salton Sea Project was constructed after the acquisition of Magma and commenced operations in June 1996. In addition, in April 1996, the Company acquired the remaining 50% interest in the Partnership Project. In August 1996, the Company acquired Falcon Seaboard Resources, Inc. ("Falcon Seaboard") which includes significant interests in three operating gas- fired cogeneration facilities and a related natural gas pipeline. On December 24, 1996, CE Electric UK plc ("CE Electric"), which in 1997 was 70% owned indirectly by the Company and 30% owned indirectly by Peter Kiewit Sons', Inc. ("PKS"), acquired majority ownership of the outstanding ordinary share capital of Northern Electric plc ("Northern") pursuant to a tender offer ("Tender Offer"). As of March 18, 1997, CE Electric effectively owned 100% of Northern ordinary shares. Northern is one of the twelve regional electricity companies ("RECs") which came into existence as a result of the restructuring and subsequent privatization of the electricity industry in the United Kingdom in 1990. Northern is primarily engaged in the distribution and supply of electricity. Northern was granted a Public Electricity Supply ("PES") license under the Electricity Act to supply electricity in Northern's Authorized Area ("Authorized Area"). Northern's Authorized Area covers approximately 14,400 square kilometers with a population of approximately 3.2 million people and includes the counties of Northumberland, Tyne and Wear, Durham, Cleveland and North Yorkshire. Northern supplies electricity outside its Authorized Area pursuant to second tier licenses. Northern also is involved in non- regulated activities, including the supply of gas within England, Wales and Scotland, the generation of electricity, electrical appliance retailing and gas exploration and production. 2. Summary of Significant Accounting Policies The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and its proportionate share of the partnerships and joint ventures in which it has an undivided interest in the assets and is proportionally liable for its share of liabilities. Other investments and corporate joint ventures where the Company has the ability to exercise significant influence are accounted for under the equity method of accounting. Investments, where the Company's ability to influence is limited, are accounted for under the cost method of accounting. All significant inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company's proportionate share of results of operations of entities acquired as of the date of each acquisition. Cash Equivalents, Investments and Restricted Cash The Company considers all investment instruments purchased with an original maturity of three months or less to be cash equivalents. Restricted cash is not considered a cash equivalent. Investments other than restricted cash are primarily commercial paper and money market securities. The restricted cash balance includes such securities and mortgage backed securities, and is mainly composed of amounts deposited in restricted accounts from which the Company will source its equity contributions and debt service reserve requirements relating to the projects. These funds are restricted by their respective project debt agreements to be used only for the related project. At December 31, 1997, all of the Company's investments are classified as held-to-maturity and are accounted for at their amortized cost basis. The carrying amount of the investments approximates the fair value based on quoted market prices as provided by the financial institution which holds the investments. Properties, Plants, Contracts, Equipment and Depreciation The cost of major additions and betterments are capitalized, while replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are expensed. Depreciation of the operating power plant costs, net of salvage value, is computed on the straight line method over the estimated useful lives, between 10 and 30 years. Depreciation of furniture, fixtures and equipment which are recorded at cost, is computed on the straight line method over the estimated useful lives of the related assets, which range from three to ten years. The Northern, Falcon Seaboard, Partnership Interest and Magma acquisitions by the Company have been accounted for as purchase business combinations. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring the respective companies equal to their fair values at the date of the acquisition and include the following: Property and equipment of Northern is depreciated using a systematic method, which approximates the straight line method over the estimated useful lives of the related assets which range from 3-40 years. Power sales agreements are amortized separately over (1) the remaining portion of the scheduled price periods of the power sales agreements and (2) for the Partnership Interest and Magma acquisitions the 20 year avoided cost periods of the power sales agreements using the straight line method. Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development consent, are depleted using the unit of production method. Depletion is calculated based on hydrocarbon reserves of properties in the evaluated pool estimated to be commercially recoverable and include anticipated future development costs in respect of those reserves. Expenditures on major information technology systems are capitalized and depreciated on a straight line basis over the useful life of the developed systems which range from 3-10 years. Well, Resource Development and Exploration Costs The Company follows the full cost method of accounting for costs incurred in connection with the exploration and development of geothermal and natural gas resources. All such costs, which include dry hole costs and the cost of drilling and equipping production wells and directly attributable administrative and interest costs, are capitalized and amortized over their estimated useful lives when production commences. The estimated useful lives of production wells are ten to twenty years depending on the characteristics of the underlying resource; exploration costs and development costs, other than production wells, are generally amortized over the weighted average remaining term of the Company's power and steam purchase contracts. Excess of Cost over Fair Value Total acquisition costs in excess of the fair values assigned to the net assets acquired are amortized over a 40 year period for the Northern and Magma acquisitions and a 25 year period for the Falcon Seaboard acquisition, both using the straight line method. Impairment of Long-Lived Assets The Company reviews long-lived assets and certain identifiable intangibles for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized whenever evidence exists that the carrying value is not recoverable. Deferred Well and Rework Costs Well rework costs are deferred and amortized over the estimated period between reworks. These deferred costs, net of accumulated amortization, are $5,421 and $8,371 at December 31, 1997 and 1996, respectively, and are included in other assets. Revenue Recognition Revenues are recorded based upon service rendered and electricity and steam delivered, distributed or supplied to the end of the month. Where there is an overrecovery of supply or distribution business revenues against the maximum regulated amount, revenues are deferred equivalent to the overrecovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an underrecovery, no anticipation of any potential future recovery is made. Capitalization of Interest and Deferred Financing Costs Prior to the commencement of operations, interest is capitalized on the costs of the plants and geothermal resource development to the extent incurred. Capitalized interest and other deferred charges are amortized over the lives of the related assets. Deferred financing costs are amortized over the term of the related financing using the effective interest method. Deferred Income Taxes The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax bases of assets and liabilities using estimated tax rates in effect for the year in which the differences are expected to reverse. The Company intends to repatriate earnings of foreign subsidiaries in the foreseeable future. As a result, deferred income taxes are provided for retained earnings of international subsidiaries and corporate joint ventures which are intended to be remitted. Fair Values of Financial Instruments The following methods and assumptions were used by the Company in estimating fair values of financial instruments as discussed herein. Fair values have been estimated based on quoted market prices for debt issues listed on exchanges. Fair values of financial instruments that are not actively traded are based on market prices of similar instruments and/or valuation techniques using market assumptions. The Company assumes that the carrying amount of short-term financial instruments approximates their fair value. For these purposes, short- term is defined as any item that matures, reprices, or represents a cash transaction between willing parties within six months or less of the measurement date. Pensions Northern contributes to the Electricity Supply Pension Scheme and contributions to the scheme are charged to the income statement. The capital cost of ex gratia and supplementary pensions are normally charged to the income statement in the period in which they are granted. Variations in pension cost, which are identified as a result of actuarial valuations/reviews, are amortized over the average expected remaining working lives of employees in proportion to their expected payroll costs. Differences between the amounts funded and the amounts charged to the profit and loss account are treated as either provisions or prepayments in the balance sheet. Net Income per Common Share In February 1997, the Financial Accounting Standards Board ("FASB") adopted Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings per Share." SFAS 128 replaced primary and fully diluted earnings per share with basic and diluted earnings per share, respectively. Basic and diluted earnings per common share are based on the weighted average number of common shares outstanding during the period. Diluted earnings per common share also assumes the conversion of the convertible preferred securities of subsidiary trusts, when dilutive, and the exercise of all dilutive stock options outstanding at their option prices, with the option exercise proceeds and tax benefits used to repurchase shares of common stock at the average market price using the treasury stock method. A reconciliation of basic earnings per share before extraordinary item to diluted earnings per share before extraordinary item follows: 1997 1996 1995 Per-Share Per-Share Per-Share Income Shares Amount Income Shares Amount Income Shares Amount Basic earnings per share before extraordinary item $ 51,823 67,268 $0.77 $ 92,461 54,739 $1.69 $62,335 47,249 $1.32 Effect of dilutive securities Stock options --- 1,418 --- 1,881 --- 1,688 Convertible preferred securities of subsidiary trusts(1) --- --- 2,840 2,517 --- --- Convertible debt --- --- 4,968 5,935 6,038 7,258 Diluted earnings per share before extraordinary item $ 51,823 68,686 $0.75 $100,269 65,072 $1.54 $68,373 56,195 $1.22 (1) The convertible preferred securities of subsidiary trusts were antidilutive in 1997. Reclassification Certain amounts in the fiscal 1996 and 1995 financial statements and supporting footnote disclosures have been reclassified to conform to the fiscal 1997 presentation. Such reclassification did not impact previously reported net income or retained earnings. 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. New Accounting Pronouncements In June 1997, the FASB adopted SFAS No. 130, "Reporting Comprehensive Income", and No. 131, "Disclosures about Segments of an Enterprise and Related Information". SFAS 130 establishes standards for reporting and display of comprehensive income and its components in a full set of general purpose financial statements. SFAS 131 redefines how operating segments are determined and requires disclosure of certain financial and descriptive information about a company's operating segments. Both statements will be effective for the Company beginning January 1, 1998. The Company has not yet determined the impact of these statements on current disclosures. 3. KDG Acquisition On September 11, 1997, the Company signed a definitive agreement with Kiewit Diversified Group ("KDG"), a wholly owned subsidiary of PKS, for the Company to purchase KDG's ownership interest in various project partnerships and CalEnergy common shares (the "KDG Acquisition"). Accordingly, common stock and options subject to redemption have been reclassified in the consolidated balance sheet. KDG's ownership interest in CalEnergy comprised approximately 20,231 shares of common stock (assuming exercise by KDG of one million options to purchase CalEnergy shares), the 30% interest in Northern Electric, as well as the following minority project interests: Mahanagdong (45%), Casecnan (35%), Dieng (47%), Patuha (44%) and Bali (30%) and other interests in international development stage projects. CalEnergy paid $1,159,215 for the KDG Acquisition and final closing of the transaction occurred in January 1998. CalEnergy funded this acquisition with available cash and the net proceeds of the equity offering and the debt offering completed in October 1997. 4. Acquisitions Northern On December 24, 1996, CE Electric UK plc ("CE Electric"), which in 1997 was 70% owned indirectly by the Company and 30% owned indirectly by PKS, acquired majority ownership of the outstanding ordinary share capital of Northern Electric plc ("Northern") pursuant to a tender offer (the "Northern Tender Offer") commenced in the United Kingdom on November 5, 1996. As of March 18, 1997, CE Electric effectively acquired the remaining ordinary shares and owned 100% of Northern's ordinary shares. The Company and PKS contributed to CE Electric approximately $410,000 and $176,000 respectively, of the approximately $1,200,000 required to acquire all of Northern's ordinary and preference shares in connection with the Tender Offer. The Company obtained such funds from cash on hand, short-term borrowings, and borrowings of approximately $100,000 under a Credit Agreement entered into with Credit Suisse on October 28, 1996 (the "CalEnergy Credit Facility"). The Company has repaid the entire CalEnergy Credit Facility through the use of proceeds of the Trust Securities offering. The remaining funds necessary to consummate the Tender Offer were provided from a pound 560,000 Term Loan and Revolving Facility Agreement, dated October 28, 1996 (the "U.K. Credit Facility"). CE Electric has repaid the entire U.K. Credit Facility through the use of proceeds of the senior note and sterling bond offerings of CE Electric UK Funding Company. The Northern acquisition has been accounted for as a purchase business combination. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring Northern, equal to their fair values at the date of the acquisition. Minority interest was recorded at historical cost. In 1993, Northern entered into a contract relating to the purchase of 400 MW of capacity from a 15.4% owned related party, Teesside Power Limited ("Teesside"), for a period of 15 years beginning April 1, 1993. The contract sets escalating purchase prices at predetermined levels. Currently the escalating contract prices exceed those paid by the Company to the electricity pool (the "Pool") which is operated by the National Grid Group. However, under current price cap regulation expected to expire in 1998 the Company is able to recover these costs. For the period after the price cap regulation ends, the Company has established a liability for the estimated loss as a result of this contract. Northern utilizes contracts for differences ("CFDs") to mitigate its exposure to volatility in the prices of electricity purchased through the Pool. Such contracts allow the Company to effectively convert the majority of its anticipated Pool purchases from market to fixed prices. As of December 31, 1997, CFDs were in place to hedge a portion of electricity purchases of approximately 55,000 GWh through the year 2008. Falcon Seaboard On August 7, 1996 the Company completed the acquisition of Falcon Seaboard for a cash price of $229,500 including acquisition costs. Through the acquisition, the Company indirectly acquired significant ownership interests in three operating gas-fired cogeneration facilities and a related natural-gas pipeline. The plants are located in Texas, Pennsylvania and New York and total 520 MW in capacity. The Falcon Seaboard acquisition has been accounted for as a purchase business combination. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring Falcon Seaboard, equal to their fair values at the date of the acquisition. Edison Mission Energy's Partnership Interest On April 17, 1996 the Company completed the acquisition of Edison Mission Energy's Partnership Interests in four geothermal operating facilities in California for a cash purchase price of $71,000 including acquisition costs. The four projects, Vulcan, Hoch (Del Ranch), Leathers and Elmore, are located in the Imperial Valley of California. Prior to this transaction, the Company was a 50% owner of these facilities. The Partnership Interest acquisition has been accounted for as a purchase business combination. All identifiable assets acquired and liabilities assumed were assigned a portion of the cost of acquiring the Partnership Interest, equal to their fair values at the date of the acquisition. Unaudited pro forma combined revenue, income and basic earnings per share before extraordinary item of the Company, Northern, Falcon Seaboard, and the Partnership Interest for the twelve months ended December 31, 1997 and 1996, as if the acquisitions had occurred at the beginning of 1996 after giving effect to certain pro forma adjustments related to the acquisitions were $2,270,911, $52,430, and $0.78 compared to $2,162,381, $64,811 and $1.18, respectively. Excluding the $87,000, $1.29 per share, non-recurring charge, pro forma income before extraordinary item would have been $139,430 in 1997. 5.Properties, Plants, Contracts and Equipment Properties, plants, contracts and equipment comprise the following at December 31: 1997 1996 Operating project costs: Distribution system $1,237,743 $928,575 Power plants 1,464,885 1,277,663 Wells and resource development 395,314 377,731 Power sales agreements 227,535 227,535 Other assets 254,973 176,483 Total operating assets 3,580,450 2,987,987 Less accumulated depreciation and amortization (497,832) (271,216) Net operating assets 3,082,618 2,716,771 Mineral and gas reserves, net 297,048 270,851 Construction in progress: Malitbog --- 152,411 Indonesia 140,172 81,875 Other development 9,072 3,588 Total $ 3,528,910 $ 3,225,496 Coso Project Operating Facilities The Coso Project operating facilities comprise the Company's proportionate share of the assets of three of its Coso Joint Ventures: Coso Finance Partners ("Navy I Joint Venture"), Coso Energy Developers ("BLM Joint Venture"), and Coso Power Developers ("Navy II Joint Venture"). The Navy I power plant is located on land owned by and leased from the U.S. Navy to December 2009, with a 10 year extension at the option of the Navy. Under terms of the Navy I Joint Venture, current profits and losses are allocated 46.4% to the Company. The BLM power plant is situated on lands leased from the U.S. Bureau of Land Management under a geothermal lease agreement that extends until October 31, 2035. The lease may be extended to 2075 at the option of the BLM. Under the terms of the BLM Joint Venture agreement, the Company's share of profits and losses is 48%. Under terms of the Navy II Joint Venture, all profits, losses and capital contributions for Navy II are divided equally by the two partners. The amount of royalties paid by Navy I to the U.S. Navy to develop geothermal energy for Navy I, Unit 1 on the lands owned by the Navy comprises (i) a fee payable during the term of the contract based on the difference between the amounts paid by the Navy to Edison for specified quantities of electricity and the price as determined under the contract (which currently approximates 73% of that paid by the Navy to Edison), and (ii) $25,000 payable in December 2009, of which the Company's share is $11,600. The $25,000 payment is secured by funds placed on deposit monthly, which funds, plus accrued interest, will aggregate $25,000. The monthly deposit is currently $50. As of December 31, 1997, the balance of funds deposited approximated $6,337, which amount is included in restricted cash. Units 2 and 3 of Navy I and the Navy II power plants are on Navy lands, for which the Navy receives a royalty based on electric sales revenue at the initial rate of 4% escalating to 22% by the end of the contract in December 2019. The BLM is paid a royalty of 10% of the value of steam produced by the geothermal resource supplying the BLM Plant. The Coso Joint Ventures had royalty expense included in operating expenses of $13,458, $13,412 and $13,623 in the years ended December 31, 1997, 1996 and 1995, respectively. Imperial Valley Project Operating Facilities The Company currently operates eight geothermal power plants in the Imperial Valley in California. The Partnership Project consists of the Vulcan, Hoch (Del Ranch), Elmore, and Leathers Partnerships. The remaining four plants which comprise the Salton Sea Project are indirect wholly owned subsidiaries of the Company. These geothermal power plants consist of Salton Sea I, Salton Sea II, Salton Sea III and Salton Sea IV. The Partnership Project and the Salton Sea Project are collectively referred to as the Imperial Valley Project. The Imperial Valley Project commencement dates and nominal capacities are as follows: Imperial Valley Commencement Nominal Plants Date Capacity Vulcan February 10, 1986 34 MW Hoch (Del Ranch) January 2, 1989 38 MW Elmore January 1, 1989 38 MW Leathers January 1, 1990 38 MW Salton Sea I July 1, 1987 10 MW Salton Sea II April 5, 1990 20 MW Salton Sea III February 13, 1989 49.8 MW Salton Sea IV May 24, 1996 39.6 MW The Partnership Project pays royalties based on both energy revenues and total electricity revenues. Hoch (Del Ranch) and Leathers pay royalties of approximately 5% of energy revenues and 1% of total electricity revenue. Elmore pays royalties of approximately 5% of energy revenues. Vulcan pays royalties of 4.167% of energy revenues. The Salton Sea Project's weighted average royalty expense in 1997 was approximately 6.1%. The royalties are paid to numerous recipients based on varying percentages of electrical revenue or steam production multiplied by published indices. The Imperial Valley Projects had royalty expense included in operating expenses of $14,343, $10,228 and $10,398 in the years ended December 31, 1997, 1996 and 1995, respectively. Significant Customers and Contracts All of the Company's sales of electricity from the Coso Project and Imperial Valley Project, which comprise approximately 20% of 1997 operating revenue, are to Southern California Edison Company ("Edison") and are under long-term power purchase contracts. The Coso Project and the Partnership Project sell all electricity generated by the respective plants pursuant to seven long-term SO4 Agreements between the projects and Edison. These SO4 Agreements provide for capacity payments, capacity bonus payments and energy payments. Edison makes fixed annual capacity and capacity bonus payments to the projects to the extent that capacity factors exceed certain benchmarks. The price for capacity and capacity bonus payments is fixed for the life of the SO4 Agreements. Energy is sold at increasing scheduled rates for the first ten years after firm operation and thereafter at Edison's Avoided Cost of Energy. The scheduled energy price periods of the Coso Project SO4 Agreements extended until at least August 1997 for each of the units operated by the Navy I Partnership and extend until at least March 1999 and January 2000 for each of the units operated by the BLM and Navy II Partnerships, respectively. The Company's share of aggregate annual capacity payments is approximately $17,000 and its share of aggregate bonus payments is approximately $3,000. The scheduled energy price periods of the Partnership Project SO4 Agreements extended until February 1996 for the Vulcan Partnership and extend until December 1998, December 1998, and December 1999 for each of the Hoch (Del Ranch), Elmore and Leathers Partnerships, respectively. The annual capacity payments are approximately $24,500 and the bonus payments are approximately $4,400 in aggregate for the four plants. Excluding Navy I and Vulcan, which are receiving Edison's Avoided Cost of Energy, the Company's SO4 Agreements provide for energy rates ranging from 12.8 cents per kWh in 1997 to 15.6 cents per kWh in 1999. The weighted average energy rate for all of the Company's SO4 Agreements was 12.0 cents per kWh in 1997. Salton Sea I sells electricity to Edison pursuant to a 30-year negotiated power purchase agreement, as amended (the "Salton Sea I PPA"), which provides for capacity and energy payments. The energy payment is calculated using a Base Price which is subject to quarterly adjustments based on a basket of indices. The time period weighted average energy payment for Salton Sea I was 5.3 cents per kWh during 1997. As the Salton Sea I PPA is not an SO4 Agreement, the energy payments do not revert to Edison's Avoided Cost of Energy. The capacity payment is approximately $1,100 per annum. Salton Sea II and Salton Sea III sell electricity to Edison pursuant to 30-year modified SO4 Agreements that provide for capacity payments, capacity bonus payments and energy payments. The price for contract capacity and contract capacity bonus payments is fixed for the life of the modified SO4 Agreements. The energy payments for the first ten year period, which period expires in April 2000 and February 1999 are levelized at a time period weighted average of 10.6 cents per kWh and 9.8 cents per kWh for Salton Sea II and Salton Sea III, respectively. Thereafter, the monthly energy payments will be Edison's Avoided Cost of Energy. For Salton Sea II only, Edison is entitled to receive, at no cost, 5% of all energy delivered in excess of 80% of contract capacity through September 30, 2004. The annual capacity and bonus payments for Salton Sea II and Salton Sea III are approximately $3,300 and $9,700, respectively. The Salton Sea IV Project sells electricity to Edison pursuant to a modified SO4 agreement which provides for contract capacity payments on 34 MW of capacity at two different rates based on the respective contract capacities deemed attributable to the original Salton Sea PPA option (20 MW) and to the original Fish Lake PPA (14 MW). The capacity payment price for the 20 MW portion adjusts quarterly based upon specified indices and the capacity payment price for the 14 MW portion is a fixed levelized rate. The energy payment (for deliveries up to a rate of 39.6 MW) is at a fixed price for 55.6% of the total energy delivered by Salton Sea IV and is based on an energy payment schedule for 44.4% of the total energy delivered by Salton Sea IV. The contract has a 30-year term but Edison is not required to purchase the 20 MW of capacity and energy originally attributable to the Salton Sea I PPA option after September 30, 2017, the original termination date of the Salton Sea I PPA. For the year ended December 31, 1997, and 1996 Edison's average Avoided Cost of Energy was 3.3 cents and 2.5 cents, respectively, per kWh which is substantially below the contract energy prices earned for the year ended December 31, 1997. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year. The Company cannot predict the likely level of Avoided Cost of Energy prices under the SO4 Agreements and the modified SO4 Agreements at the expiration of the scheduled payment periods. The revenues generated by each of the projects operating under SO4 Agreements could decline significantly after the expiration of the respective scheduled payment periods. Philippine Projects The Upper Mahiao Project was deemed complete in June 1996 and began receiving capacity payments pursuant to the Upper Mahiao Energy Conversion Agreement ("ECA"), in July of 1996. The project is structured as a ten year build-own-operate-transfer project ("BOOT"), in which the Company's subsidiary CE Cebu Geothermal Power Company, Inc. ("CE Cebu"), the project company, is responsible for providing operations and maintenance during the ten year BOOT period. The electricity generated by the Upper Mahiao geothermal power plant is sold to PNOC-Energy Development Corporation ("PNOC-EDC"), which is also responsible for supplying the facility with the geothermal steam. After the ten year cooperation period, and the recovery by the Company of its capital investment plus incremental return, the plant will be transferred to PNOC-EDC at no cost. PNOC-EDC is obligated to pay for electric capacity that is nominated each year by CE Cebu, irrespective of whether PNOC-EDC is willing or able to accept delivery of such capacity. PNOC-EDC pays to CE Cebu a fee (the "Capacity Fee") based on the plant capacity nominated to PNOC- EDC in any year (which, at the plant's design capacity, is approximately 95% of total contract revenues) and a fee (the "Energy Fee") based on the electricity actually delivered to PNOC-EDC (approximately 5% of total contract revenues). Payments under the Upper Mahiao ECA are denominated in U.S. Dollars, or computed in U.S. dollars and paid in Philippine pesos at the then-current exchange rate, except for the Energy Fee. Significant portions of the Capacity Fee and Energy Fee are indexed to U.S. and Philippine inflation rates, respectively. PNOC-EDC's payment requirements, and its other obligations under the Upper Mahiao ECA are supported by the Government of the Philippines through a performance undertaking. Unit I of the Malitbog Project (the "Malitbog Project") was deemed complete in July 1996 and Units II and III in July 1997 at which times such units commenced receiving capacity payments under the Malitbog ECA. The Malitbog Project is owned and operated by Visayas Geothermal Power Company ("VGPC"), a Philippine general partnership that is wholly owned, indirectly, by the Company. Under its contract, VGPC is to sell 100% of its output on substantially the same basis as described above for the Upper Mahiao Project to PNOC-EDC, which will in turn sell the power to the National Power Corporation of the Philippines ("NPC"). However, VGPC receives 100% of its revenues from such sales in the form of capacity payments. As with the Upper Mahiao Project, the Malitbog Project is structured as a ten year BOOT, in which the Company is responsible for providing operations and maintenance for the ten year BOOT period. After a ten year cooperation period, and the recovery by the Company of its capital investment plus incremental return, the plant will be transferred to PNOC-EDC at no cost. The Mahanagdong Project (the "Mahanagdong Project") was deemed complete in July 1997 and accordingly, the Mahanagdong Project began receiving capacity payments pursuant to the Mahanagdong ECA in August of 1997. The Mahanagdong Project is owned and operated by CE Luzon Geothermal Power Company, Inc., a Philippine corporation, that is expected to be indirectly owned by the Company (after the KDG Acquisition) subject to a minority partner participation. The electricity generated by the Mahanagdong Project will be sold to PNOC- EDC on a "take or pay" basis, which is also responsible for supplying the facility with the geothermal steam. The terms of the Mahanagdong ECA are substantially similar to those of the Upper Mahiao ECA. All of PNOC-EDC's obligations under the Mahanagdong ECA are supported by the Government of the Philippines through a performance undertaking. The capacity fees are expected to be approximately 97% of total revenues at the design capacity levels and the energy fees are expected to be approximately 3% of such total revenues. Gas Projects The Saranac Project sells electricity to New York State Electric & Gas pursuant to a 15 year negotiated power purchase agreement (the "Saranac PPA"), which provides for capacity and energy payments. Capacity payments, which in 1997 total 2.2 cents per kWh, are received for electricity produced during "peak hours" as defined in the Saranac PPA and escalate at approximately 4.1% annually for the remaining term of the contract. Energy payments, which average 6.6 cents per kWh in 1997, escalate at approximately 4.4% annually for the remaining term of the Saranac PPA. The Saranac PPA expires in June of 2009. The Power Resources Project sells electricity to Texas Utilities Electric Company ("TUEC") pursuant to a 15 year negotiated power purchase agreement (the "Power Resources PPA"), which provides for capacity and energy payments. Capacity payments and energy payments, which in 1997 are $3,032 per month and 2.96 cents per kWh, respectively, escalate at 3.5% annually for the remaining term of the Power Resources PPA. The Power Resources PPA expires in September 2003. The NorCon Project sells electricity to Niagara Mohawk Power Corporation ("Niagara") pursuant to a 25 year negotiated power purchase agreement (the "NorCon PPA") which provides for energy payments calculated pursuant to an adjusting formula based on Niagara's ongoing Tariff Avoided Cost and the contractual Long-Run Avoided Cost. The NorCon PPA term extends through December 2017. The Company and Niagara are currently engaged in discussions regarding a potential restructuring or buyout and termination of the NorCon PPA. The Yuma Project sells electricity to SDG&E under an existing 30-year power purchase contract. The energy is sold at SDG&E's Avoided Cost of Energy and the capacity is sold to SDG&E at a fixed price for the life of the power purchase contract. The contract term extends through May 2024. Nevada and Utah Properties Roosevelt Hot Springs. The Company operates and owns an approximately 70% interest in a geothermal steam field which supplies geothermal steam to a 23 net MW power plant owned by Utah Power & Light Company ("UP&L") located on the Roosevelt Hot Springs property under a 30-year steam sales contract. The Company obtained approximately $20,317 cash under a pre-sale agreement with UP&L whereby UP&L paid in advance for the steam produced by the steam field. The Company must make certain penalty payments to UP&L if the steam produced does not meet certain quantity and quality requirements. Desert Peak. The Company is the owner and operator of a geothermal plant at Desert Peak, Nevada that is currently selling electricity to Sierra Pacific Power Company ("Sierra") at Sierra's Avoided Cost. Subsequent to year end, an indirect subsidiary of the Company entered into a lease agreement whereby they will lease the facility to another power producer and receive rental payments. Salton Sea Minerals Extraction The Company developed and owns the rights to a proprietary process for the extraction of minerals from elements in solution in the geothermal brine and fluids utilized at its Imperial Valley plants (the "Salton Sea Extraction Project") as well as the production of power to be used in the extraction process. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Project. The Company is also investigating producing silica from the solids precipitated out of the geothermal power process. Telephone Flat Under a Bonneville Power Administration ("BPA") geothermal pilot program, the Company has been developing a 30 net MW geothermal project which was originally located in the Newberry Known Geothermal Resource Area in Deschutes County, Oregon (the "Telephone Flat Project"). Pursuant to an amended power sales contract the project has been relocated to Telephone Flat and BPA has agreed to purchase 30 MW from the project with an option to purchase up to an additional 100 MW. The movement of the project to this alternative location and BPA's purchase obligation are subject to obtaining a final environmental impact statement relating to the new site location. Completion of this project is subject to a number of significant uncertainties and cannot be assured. 6. Equity Investments At December 31, 1997, the Company had an indirect ownership of approximately 35% in the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project located on the island of Luzon in the Philippines. The Company is expected to indirectly own approximately 70% of the Casecnan Project after the KDG Acquisition. The Company had an indirect ownership of 50% in the Mahanagdong Project, subject to a minority partner participation. The Company will indirectly own 100% of the Mahanagdong Project after the KDG Acquisition. The Company has an approximate 45% economic interest in Saranac Power Partners, L.P. and a 20% economic interest in NorCon Power Partners, L.P. as part of the Falcon Seaboard acquisition. Summary financial information for these equity investments follows: Casecnan Saranac NorCon Mahanagdong As of and for the year ended December 31, 1997: Assets $ 482,527 $ 315,671 $ 118,415 $ 294,250 Liabilities 384,369 211,299 115,487 197,575 Net income (loss) (11,267) 43,097 4,072 14,996 As of and for the year ended December 31, 1996: Assets 492,166 325,174 125,956 240,222 Liabilities 380,737 213,326 121,223 168,512 Net income (loss) (11,207) 40,005 (53) N/A 7. Parent Company Debt Parent company debt comprises the following at December 31: 1997 1996 Senior discount notes $ 529,640 $ 527,535 9.5% senior notes 224,205 224,150 7.63% senior notes 350,000 --- Limited recourse senior secured notes* 200,000 200,000 CalEnergy credit facility --- 100,000 Revolving credit facility --- 95,000 $ 1,303,845 $ 1,146,685 * The amount of recourse obligation to the parent was $0 at December 31, 1997. Senior Discount Notes In March 1994, the Company issued $400,000 of 10 1/4% Senior Discount Notes which accrete to an aggregate principal amount of $529,640 at maturity in 2004. The original issue discount was amortized from the issue date through January 15, 1997, during which time no cash interest was paid on the Senior Discount Notes. Cash interest on the Senior Discount Notes is payable semiannually on January 15 and July 15 of each year, commencing July 15, 1997. The Senior Discount Notes are redeemable at any time on or after January 15, 1999 initially at a redemption price of 105.125% declining to 100% on January 15, 2002 plus accrued interest to the date of redemption. The Senior Discount Notes are unsecured senior obligations of the Company. The Senior Discount Notes prohibit payment of cash dividends unless certain financial ratios are met and unless the dividends do not exceed 50% of the Company's accumulated adjusted consolidated net income as defined, subsequent to April 1, 1994, plus the proceeds of any stock issuance. 9.5% Senior Notes On September 20, 1996, the Company issued $225,000 of 9.5% Senior Notes (the "9.5% Senior Notes") due 2006. Interest on the 9.5% Senior Notes is payable semiannually on March 15 and September 15 of each year, commencing March 15, 1997. The 9.5% Senior Notes are redeemable at any time on or after September 15, 2001 initially at a redemption price of 104.75% declining to 100% on September 15, 2004 plus accrued interest to the date of redemption. The 9.5% Senior Notes are unsecured senior obligations of the Company. 7.63% Senior Notes On October 28, 1997, the Company issued $350,000 of 7.63% Senior Notes (the "7.63% Senior Notes") due 2007. Interest on the 7.63% Senior Notes will be payable semiannually on April 15 and October 15 of each year, commencing April 15, 1998. The 7.63% Senior Notes are unsecured senior obligations of the Company. Limited Recourse Senior Secured Notes On July 21, 1995, the Company issued $200,000 of 9 7/8% Limited Recourse Senior Secured Notes Due 2003 (the "Notes"). Interest on the Notes is payable on June 30 and December 30 of each year, commencing December 1995. The Notes are secured by an assignment and pledge of 100% of the outstanding capital stock of Magma and are recourse only to such Magma capital stock, the Company's interest in a secured Magma note and general assets of the Company equal to the Restricted Payment Recourse Amount, as defined in the Note Indenture ("Note Indenture"), which was $0 at December 31, 1997. At any time or from time to time on or prior to June 30, 1998, the Company may, at its option, use all or a portion of the net cash proceeds of a Company equity offering (as defined in the Note Indenture) and shall at any time use all of the net cash proceeds of any Magma equity offering (as defined in the Note Indenture) to redeem up to an aggregate of 35% of the principal amount of the Notes originally issued at a redemption price equal to 109.875% of the principal amount thereof plus accrued interest to the redemption date. On or after June 30, 2000, the Notes are redeemable at the option of the Company, in whole or in part, initially at a redemption price of 104.9375% declining to 100% on June 30, 2002 and thereafter, plus accrued interest to the date of redemption. CalEnergy Credit Facility On October 28, 1996, the Company obtained a $100,000 credit facility (the "CalEnergy Credit Facility") of which the Company had drawn $100,000 as of December 31, 1996. The Company has repaid the entire balance of the CalEnergy Credit Facility. Revolving Credit Facility On July 8, 1996, the Company obtained a $100,000 three year revolving credit facility. On November 26, 1997, the credit facility was amended and increased to $400,000 and extended to November 2000. The facility is unsecured and is available to fund working capital requirements and finance future business expansion opportunities. Annual Repayments of Parent Company Debt There are no annual repayments of the parent company debt due for the next five years. 8. Subsidiary and Project Debt: Project loans held by subsidiaries and projects which are non recourse to the Company comprise the following at December 31: 1997 1996 Salton Sea Notes and Bonds $ 448,754$ 538,982 Northern eurobonds 427,732 439,192 U.K. credit facility --- 128,423 CE Electric UK Funding Company Senior Notes 357,331 --- CE Electric UK Funding Company Sterling Bonds 322,534 --- Power Resources project debt 103,334 114,571 Coso Funding Corp. project loans 106,616 148,346 Construction loans 416,744 300,951 Other 5,962 7,927 $2,189,007 $1,678,392 Each of the Company's direct or indirect subsidiaries is organized as a legal entity separate and apart from the Company and its other subsidiaries. Pursuant to separate project financing agreements, the assets of each subsidiary are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any such subsidiary will be available to satisfy the obligations of the Company or any of its other such subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing arrangements of such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to the Company or affiliates thereof. "Subsidiaries" means all of CalEnergy's direct or indirect subsidiaries (1) owning interests in the Coso, Imperial Valley, Saranac, NorCon, Power Resources, Mahanagdong, Malitbog, Upper Mahiao, Casecnan, Dieng and Patuha projects or (2) owning interests in the subsidiaries that own interests in the foregoing projects. Salton Sea Notes and Bonds The Salton Sea Funding Corporation, a wholly owned subsidiary of the Company, (the "Funding Corporation") debt securities are as follows: Final Maturity December 31, December 31, Senior Secured Series Date Rate 1997 1996 July 21, 1995 A Notes May 30, 2000 6.69% $ 97,354 $161,732 July 21, 1995 B Bonds May 30, 2005 7.37% 133,000 133,000 July 21, 1995 C Bonds May 30, 2010 7.84% 109,250 109,250 June 20, 1996 D Notes May 30, 2000 7.02% 44,150 70,000 June 20, 1996 E Bonds May 30, 2011 8.30% 65,000 65,000 $448,754 $538,982 Principal and interest payments are made in semi-annual installments. The Salton Sea Notes and Bonds are secured by the Company's four existing Salton Sea plants as well as an assignment of the right to receive various royalties payable to Magma in connection with its Imperial Valley properties and distributions from the Partnership Project. The Salton Sea Notes and Bonds are nonrecourse to the Company. Pursuant to a depository agreement, Funding Corporation established a debt service reserve fund in the form of a letter of credit in the amount of $70,430 from which scheduled interest and principal payments can be made. Northern Eurobonds The Northern debt includes a debenture due in 1999, which bears a fixed interest rate of 12.661%. The debt also includes bearer bonds repayable in 2005 and 2020, bearing fixed interest rates of 8.625% and 8.875%, respectively. The balance at December 31, 1997 and 1996 consists of the following: 1997 1996 Debenture due 1999 $ 97,530 $ 99,924 Bearer bonds due 2005 165,236 171,130 Bearer bonds due 2020 164,966 168,138 $ 427,732 $ 439,192 U.K. Credit Facility On October 28, 1996, CE Holdings, an indirect subsidiary of the Company, obtained a pound 560,000 five year term loan and revolving credit facility (the "U.K. Credit Facility"). The Company did not guarantee, nor was it otherwise subject to recourse for, amounts borrowed under the U.K. Credit Facility. The agreement placed restrictions on distributions from CE Electric to any of its shareholders based on certain financial ratios. CE Electric has repaid the entire U.K. Credit Facility through the use of proceeds from the senior note and sterling bond offerings of CE Electric UK Funding Company described below. CE Electric UK Funding Company Senior Notes and Sterling Bonds On December 15, 1997, CE Electric UK Funding Company, an indirect subsidiary of the Company (the "Funding Company"), issued $125,000 of 6.853% senior notes due 2004, and $237,000 of 6.995% senior notes due 2007 (collectively, the "CE Electric UK Funding Company Senior Notes"), and pound 200,000 of 7.25% Sterling Bonds due 2022. The CE Electric UK Funding Company Senior Notes and Sterling Bonds prohibit distributions to any of its shareholders unless certain financial ratios are met by the Funding Company. Power Resources Project Financing Debt Power Resources, an indirect wholly-owned subsidiary, has project financing debt consisting of a term loan payable to a consortium of banks with interest and principal due quarterly through October 2003. The debt carries fixed interest rates of 10.385% and 10.625%. Coso Funding Corp. Project Loans The Coso Funding Corp. project loans are from Coso Funding Corp., a single-purpose corporation formed to issue notes for its own account and act as an agent on behalf of the Coso Project. The Coso Funding Corp. project loans carry a fixed interest rate with weighted average interest rates of 8.65% and 8.46% at December 31, 1997 and 1996, respectively. The loans have scheduled repayments through December 2001. The Coso Project has established irrevocable letters of credit of $67,850 as a debt service reserve fund. Annual Repayments of Subsidiary and Project Debt The annual repayments of the subsidiary and project debt, excluding construction loans, for the years beginning January 1, 1998 and thereafter are as follows: CE Electric UK Salton Sea Funding Company Coso Notes and Northern Senior Notes and Power Funding Bonds Eurobonds Sterling Bonds Resources Corp. Other Total 1998 $ 106,938 $ --- $ --- $ 12,805 $ 38,912 $1,544 $160,199 1999 57,836 97,530 --- 14,268 31,717 1,297 202,648 2000 25,072 --- --- 16,087 4,080 1,051 46,290 2001 22,376 --- --- 18,119 31,907 838 73,240 2002 24,298 --- --- 20,312 --- 1,232 45,842 There- after 212,234 330,202 679,865 21,743 --- --- 1,244,044 $448,754 $427,732 $679,865 $103,334 $106,616 $5,962$1,772,263 Construction Loans The Company's allocable share of non-recourse project construction loans comprise the following at December 31: 1997 1996 Upper Mahiao $ 150,628 $150,628 Malitbog 176,657 137,881 CE Indonesia Funding Corp. 89,459 12,442 $ 416,744 $ 300,951 The Upper Mahiao and Malitbog construction loans are scheduled to be replaced by non-recourse term project financing upon completion of construction and commencement of commercial operations. Upper Mahiao Construction Loan Draws on the construction loan for the Upper Mahiao geothermal power project at December 31, 1997 totaled $150,628. A consortium of international banks provided the construction financing with variable interest rates based on LIBOR or "Prime" with interest payments due every quarter and at LIBOR maturity. The weighted average interest rate at December 31, 1997 and 1996 is approximately 8.43% and 8.01%, respectively. The Export-Import Bank of the U.S. ("Ex-Im Bank") is providing political risk insurance to commercial banks on the construction loan. The construction loan is expected to be converted to a term loan promptly after NPC completes the full capacity transmission line, which is currently expected in 1998. The largest portion of the term loan for the project will also be provided by Ex- Im Bank. The term financing for the Ex-Im Bank loan will be at a fixed interest rate of 5.95%. Malitbog Construction Loan Draws on the construction loan for the Malitbog geothermal power project at December 31, 1997 totaled $176,657. International banks and the Overseas Private Investment Corporation ("OPIC") have provided the construction and term loan facilities at variable interest rates (weighted average of 8.48% and 8.15% at December 31, 1997 and 1996, respectively). The international bank portion of the debt will be insured by OPIC against political risks and the Company's equity contribution to Visayas Geothermal Power Company ("VGPC") is covered by political risk insurance from the Multilateral Investment Guarantee Agency and OPIC. The construction loan is expected to be converted to a term loan promptly after NPC completes the full capacity transmission line, which is currently expected in 1998. CE Indonesia Funding Corp. In June 1997, the Company's indirect special-purpose subsidiary, CE Indonesia Funding Corp., entered into a $400,000 revolving credit facility (which is nonrecourse to the Company) to finance the development and construction of the Company's geothermal power facilities in Indonesia. This credit facility was used in part to replace the original project financing for Himpurna California Energy's Dieng Unit I. At December 31, 1997, the Company's share of the credit facility relating to Dieng Unit I was $50,481 and carried a variable interest rate (weighted average of 7.44% at December 31, 1997). On November 18, 1997, Himpurna California Energy announced the funding of the Dieng Unit II project pursuant to the CE Indonesia Funding Corp. facility arranged in June 1997. At December 31, 1997, the Company's share of the credit facility relating to Dieng Unit II was $11,211 and carried a variable interest rate (weighted average of 7.48% at December 31, 1997). On September 2, 1997, Patuha Power announced the funding of the Patuha Unit I project pursuant to the CE Indonesia Funding Corp. facility arranged in June 1997. At December 31, 1997, the Company's share of the credit facility relating to Patuha was $27,767 and carried a variable interest rate (weighted average of 7.44% at December 31, 1997). 9. Income Taxes Provision for income taxes is comprised of the following at December 31: 1997 1996 1995 Currently payable: State $ 5,084$ 7,520 $5,510 Federal 33,114 19,873 11,138 Foreign 5,262 2,176 --- 43,460 29,569 16,648 Deferred: State (264) 1,619 921 Federal 14,579 9,209 13,062 Foreign 41,269 1,424 --- 55,584 12,252 13,983 Total $ 99,044 $41,821 $30,631 A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows: 1997 1996 1995 Federal statutory rate 35.00% 35.00% 35.00% Percentage depletion in excess of cost depletion (3.77) (6.12) (7.38) Investment and energy tax credits (.64) (8.34) (1.80) State taxes, net of federal tax effect 1.59 4.38 4.09 Goodwill amortization 2.06 2.51 2.53 Non-deductible expense 1.33 .84 1.10 Lease investment --- --- (2.18) Dividends on convertible preferred securities of subsidiary trusts* (4.12) (1.17) --- Tax effect of foreign income 2.64 2.54 --- Asset valuation impairment 15.47 --- --- Other .75 .15 .20 Effective tax rate 50.31% 29.79% 31.56% * Dividends on convertible preferred securities of subsidiary trusts are included in minority interest. Deferred tax liabilities (assets) are comprised of the following at December 31: 1997 1996 Depreciation and amortization, net $ 802,215 $ 725,366 Pensions 19,441 22,883 Unremitted foreign earnings 10,781 2,857 Other 3,324 3,262 835,761 754,368 Deferred contract costs (193,996) (128,745) Deferred income (12,690) (9,298) Energy and investment tax credits (42,049) (55,931) Advance corporation tax --- (20,205) Alternative minimum tax credits (39,402) (50,819) Accruals not currently deductible for tax purposes (31,561) (13,372) Other (7,004) (6,799) (326,702) (285,169) Net deferred taxes $509,059 $469,199 The Company has unused investment and geothermal energy tax credit carryforwards of approximately $42,049 expiring between 2004 and 2012. The Company also has approximately $39,402 of alternative minimum tax credit carryforwards which have no expiration date. 10. Company-Obligated Mandatorily Redeemable Convertible Preferred Securities of Subsidiary Trusts The Company has organized special purpose Delaware business trusts ("Trust I", "Trust II" and "Trust III" or collectively, the "Trusts") pursuant to their respective amended and restated declarations of trusts (collectively, the "Declarations"). On April 12, 1996, February 26, 1997 and August 12, 1997, the Company, through these Trusts, issued Company-obligated mandatorily redeemable convertible preferred securities (collectively, the "Trust Securities") as follows: Issuer Issue Date Rate Amount Conversion Rate CalEnergy Capital Trust I April 12,1996 6.25% $103,930 1.6728 CalEnergy Capital Trust II February 26,1997 6.25% $180,000 1.1655 CalEnergy Capital Trust III August 12, 1997 6.50% $270,000 1.047 The Company owns all of the common securities of the Trusts. The Trust Securities have a liquidation preference of fifty dollars each and represent undivided beneficial ownership interests in each of the Trusts. The assets of the Trusts consist solely of the Company's Convertible Subordinated Debentures due March 10, 2016, February 25, 2012 and September 1, 2027, respectively, in outstanding aggregate principal amounts of $103,930, $180,000 and $270,000, respectively (collectively, the "Junior Debentures") issued pursuant to their respective indentures. The indentures include agreements by the Company to pay expenses and obligations incurred by the Trusts. Each Trust Security with a par value of $50 is convertible at the option of the holder at any time into shares of CalEnergy Common Stock based on the conversion rate and subject to customary anti-dilution adjustments. Until converted into the Company's Common Stock, the Trust Securities will have no voting rights with respect to the Company and, except under certain limited circumstances, will have no voting rights with respect to the Trusts. Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory redemption provisions, all as described in the Junior Debenture indentures. Pursuant to Preferred Securities Guarantee Agreements (collectively, the "Guarantees"), between the Company and a preferred guarantee trustee, the Company has agreed irrevocably to pay to the holders of the Trust Securities, to the extent that the Trustee has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the Trust Securities. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and Guarantees constitute full and unconditional guarantees by the Company of the Trusts' obligations under the Trust Securities. 11.Preferred Stock On December 1, 1988, the Company distributed a dividend of one preferred share purchase right ("right") for each outstanding share of common stock. The rights are not exercisable until ten days after a person or group acquires or has the right to acquire, beneficial ownership of 20% or more of the Company's common stock or announces a tender or exchange offer for 30% or more of the Company's common stock. Each right entitles the holder to purchase one one-hundredth of a share of Series A junior preferred stock for $52. The rights may be redeemed by the Board of Directors up to ten days after an event triggering the distribution of certificates for the rights. The rights will expire, unless previously redeemed or exercised, on November 30, 1998. The rights are automatically attached to, and trade with, each share of common stock. 12.Stock Options and Restricted Stock The Company has issued various stock options. As of December 31, 1997, a total of 6,949 shares are reserved for stock options, of which 6,780 shares have been granted and remain outstanding at prices of $3.74 to $40.81 per share. The Company has stock option plans under which shares were reserved for grant as incentive or non-qualified stock options, as determined by the Board of Directors. The plans allow options to be granted at 85% of their fair market value at the date of grant. Generally, options are issued at 100% of fair market value at the date of grant. Options granted under the 1996 Plan become exercisable over a period of two to five years and expire if not exercised within ten years from the date of grant or, in some instances, a lesser term. Prior to the 1996 Plan, the Company granted 256 options at fair market value at date of grant which had terms of ten years and were exercisable at date of grant. In addition, the Company had issued approximately 138 options to consultants on terms similar to those issued under the 1996 Plan. The non-1996 plan options are primarily options granted to Kiewit. The Company granted 500 shares of restricted common stock with an aggregate market value of $9,500 in exchange for the relinquishment of 500 stock options which were canceled by the Company. The shares have all rights of a shareholder, subject to certain restrictions on transferability and risk of forfeiture. Unearned compensation equivalent to the market value of the shares at the date of issuance was charged to stockholders' equity. Such unearned compensation was amortized over the vesting period of which 125 shares were immediately vested and the remaining 375 shares vested through January 1, 1998. Accordingly, $5,471, $1,535 and $2,494 of unearned compensation was charged to general and administrative expense in 1997, 1996 and 1995, respectively. Transactions in Stock Options Options Outstanding Shares Available for Grant Under Option Price Weighted Avg 1996 Option Plan Shares Per Shares Option Price Total Balance December 31, 1994 86 9,601 $3.00 - $19.00 $12.84 $123,277 Options granted (396) 396 15.81 - 19.00 18.15 7,188 Options terminated 571 (571)14.88 - 19.00 18.69 (10,673) Options exercised --- (135) 3.00 - 15.94 3.41 (460) Balance December 31,1995 261 9,291 3.00 - 19.00 12.84 119,332 Options granted (1,157) 1,157 25.06 - 30.38 28.17 32,590 Options terminated 468 (468) 3.00 - 19.00 17.96 (8,406) Options exercised --- (5,203) 3.00 - 21.68 11.13 (57,931) Additional shares reserved under 1996 Option Plan 739 --- --- --- --- Balance December 31, 1996 311 4,777 3.00 - 30.38 17.928 5,585 Options granted (2,307) 2,513 29.06 - 40.81 34.80 87,457 Options terminated 165 (165) 3.00 - 29.06 20.04 (3,307) Options exercised --- (345) 3.74 - 29.06 13.28 (4,583) Additional shares reserved under 1996 Option Plan 2,000 --- --- --- --- Balance December 31, 1997 169 6,780 $3.74 -$40.81 $24.36 $165,152 Options exercisable at: December 31, 1995 8,229 $3.00 -$19.00 $12.26 $100,886 December 31, 1996 3,071 $3.00 -$30.38 $14.25 $ 43,770 December 31, 1997 3,665 $3.74 -$40.19 $18.12 $ 66,425 The following table summarizes information about stock options outstanding and exercisable as of December 31, 1997: Options Outstanding Options Exercisable Weighted Weighted Weighted Range of Number Average Average Remaining Number Average Exercise Outstanding Exercise Contractual Life Exercisable Exercise Prices Price Price $3.74 $11.99 1,161 $ 11.22 3 years 1,161 $ 11.22 12.00 21.99 2,020 16.90 6 years 1,739 16.82 22.00 31.99 1,092 28.10 8 years 311 28.25 32.00 40.81 2,507 34.83 9 years 454 34.12 6,780 $ 24.36 7 years 3,665 $ 18.12 The Company applies the intrinsic value based method of accounting for its stock-based employee compensation plans. If the fair value based method had been applied for 1997, non-cash compensation expense and the effect on net income available to common stockholders and earnings per share would have been approximately $3,600, or $0.05 per share. If the fair value based method had been applied for 1996 and 1995, non- cash compensation expense and the effect on net income available to common stockholders and earnings per share would have been immaterial. The fair value for stock options was estimated using the Black-Scholes option pricing model with assumptions for the risk-free interest rate of 5.50% in 1997 and 6.00% in 1996 and 1995, expected volatility of 25% in 1997 and 22% in 1996 and 1995, expected life of approximately 3.7 years in 1997 and 4.5 years in 1996 and 1995, and no expected dividends. The weighted average fair value of options granted during 1997, 1996 and 1995 was $9.55, $8.62 and $5.72 per option, respectively. 13.Common Stock Sales & Related Options On October 17, 1997, the Company completed the public offering of 17,100 shares of its common stock ("Common Stock") at $37 7/8 per share (the "Public Offering"). In addition, 2,000 shares of Common Stock were purchased from CalEnergy in a direct sale by a trust affiliated with Walter Scott, Jr., the Chairman and Chief Executive Officer of PKS (the "Direct Sale"), contemporaneously with the closing of the Public Offering. Proceeds from the Public Offering and the Direct Sale were approximately $699,920. Simultaneous with the acquisition of the remaining equity interest of Magma on February 24, 1995, the Company completed a public offering (the "Offering") of 18,170 shares of common stock, which amount included a direct sale by the Company to Kiewit of 1,500 shares and the exercise of underwriter over-allotment options for 1,500 shares, at a price of $17.00 per share. The Company received proceeds of $300,388 from the Offering. 14.Asset Valuation Impairment Charge The non-recurring charge of $87,000 represents an asset valuation impairment charge under Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to CalEnergy's assets in Indonesia. Moreover, the Company intends to continue to take actions to attempt to require the Government of Indonesia to honor its contractual obligations; however, the ultimate outcome of the current uncertain situation in Indonesia with respect to the possible abrogation by the Indonesian government of the Dieng, Patuha and Bali contracts adds significant risk to the completion of those projects. Consequently, the charge of $87,000 represents the amount by which the carrying amount of such assets exceed the fair value of the assets determined by discounting the expected future net cash flows of the Indonesia projects, assuming proceeds from political risk insurance and no tax benefits. 15. Extraordinary Item On July 31, 1997, the Finance Act in the United Kingdom was passed by Parliament and included the introduction of a one time so-called "windfall tax" equal to 23% of the difference between the price paid for Northern upon privatization and the Labour government's assessed "value" of Northern as calculated by reference to a formula set forth in the July budget. This amounted to $135,850, net of minority interest of $58,222, which was recorded as an extraordinary item. The first installment was paid December 1, 1997 and the second installment is payable on December 1, 1998. 16.Fair Value of Financial Instruments The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Although management uses its best judgment in estimating the fair value of these financial instruments, there are inherent limitations in any estimation technique. Therefore, the fair value estimates presented herein are not necessarily indicative of the amounts which the Company could realize in a current transaction. The methods and assumptions used to estimate fair value are as follows: Debt instruments - The fair value of all debt issues listed on exchanges has been estimated based on the quoted market prices. Other financial instruments - All other financial instruments of a material nature fall into the definition of short-term and fair value is estimated as the carrying amount. The carrying amounts in the table below are included under the indicated captions in Notes 7, 8 and 10. 1997 1996 Estimated Estimated Carrying Fair Carrying Fair Value Value Value Value Senior discount notes $529,640 $569,148 $527,535 $556,971 9.5% Senior notes 224,205 243,615 224,150 229,866 7.63% Senior notes 350,000 352,857 --- --- Limited recourse senior secured notes 200,000 217,829 200,000 212,560 CalEnergy credit facility --- --- 100,000 100,000 Revolving line of credit --- --- 95,000 95,000 Salton Sea notes and bonds 448,754 463,720 538,982 531,807 Northern eurobonds 427,732 482,064 439,192 445,830 Construction loans 416,744 416,744 300,951 300,951 Coso Funding Corp. project loans 106,616 112,932 148,346 153,650 CE Electric UK Funding Company Senior Notes 357,331 357,331 --- --- CE Electric UK Funding Company Sterling Bonds322,534 333,257 --- --- Power Resources project debt 103,334 103,334 114,571 114,571 U.K. credit facility --- --- 128,423 128,423 Other 5,962 5,962 7,927 7,927 Convertible preferred securities of subsidiary trusts 553,930 514,373 103,930 128,354 17. Interest Rate Swap Agreements On December 15, 1997, CE Electric UK Funding Company entered into certain interest rate swap agreements for the CE Electric UK Funding Company Senior Notes with two large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. For the $125,000 of 6.853% senior notes, the agreements extend until December 30, 2004 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.744%. For the $237,000 of 6.995% senior notes, the agreements extend until December 30, 2007 and convert the U.S. dollar interest rate to a fixed Sterling rate of 7.737%. The estimated fair value of these swap agreements is approximately $4,929 based on quotes from the counter party to these instruments and represents the estimated amount that the Company would expect to pay to terminate these agreements. It is the Company's intention to hold the swap agreements to their intended maturity. 18. Regulatory Matters Northern is subject to price cap regulation. Price control formulas for the supply and distribution businesses are enforced by the Office of Electricity Regulation ("OFFER"). In the distribution business the current price control is expected to last until 2000. The formula was reviewed with effect from April 1, 1995 and April 1, 1996 which resulted in one-time reductions in allowed income per unit distributed of about 17% and 13% respectively, with continuing real reductions in each of the subsequent three years 1997/98 to 1999/2000. The current formula requires that each year regulated distribution income per unit is increased or decreased by RPI-Xd where RPI reflects the average of the twelve month inflation rates recorded for the previous July to December period and Xd is set at 3%. The formula also takes account of the changes in system electrical losses, the number of customers connected and the voltage at which customers receive the units of electricity distributed. In the supply business the current formula applies only to customers with demands below 100kW. Under the current formula the purchase cost of electricity and the cost of transmission, distribution and the fossil fuel levy are passed through to customers in full. That part of the formula governing Northern's own supply business costs requires that this element of the permitted income falls by 2% per annum in real terms. The current formula is due to be replaced from April 1, 1998 with a new formula which will require Northern to reduce prices to those customers protected by the new price control from the level prevailing at August 1, 1997 by about 4.2% (minus inflation) with effect from April 1, 1998 and a further 3% (minus inflation) with effect from April 1, 1999. The market for electricity supplied to customers with demands over 1MW was opened to competition in 1990. In 1994 this limit was reduced to 0.1MW. In 1998, liberalization of the entire market is due to commence in stages with complete liberalization achieved by June 1999. 19. Pension Commitments Northern participates in the Electricity Supply Pension Scheme, which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees throughout the Electricity Supply Industry in the United Kingdom. The actuarial computation for December 31, 1997 and 1996 assumed interest rates of 6.75% and 7.75%, respectively, an expected return on plan assets of 7.25% and 8.25%, respectively, and annual compensation increases of 4.75% and 5.75%, respectively, over the remaining service lives of employees covered under the plan. Amounts funded to the pension are primarily invested in equity and fixed income securities. Northern's funding policy for the plan is to contribute annually at a rate that is intended to remain a level percentage of compensation for the covered employees. The following table details the funded status and the amount recognized in the balance sheet of the Company as of December 31, 1997 and 1996. Actuarial present value of benefit obligations: 1997 1996 Vested benefits $ 847,694 $ 797,932 Nonvested benefits --- --- Accumulated benefit obligation 847,694 797,932 Effect of future increase in compensation 40,898 58,218 Projected benefit obligation 888,592 856,150 Fair value of plan assets 1,012,601 919,163 Assets in excess of projected benefit obligation 124,009 63,013 Unrecognized net gain 61,265 --- Prepaid pension asset $ 62,744 $ 63,013 Net periodic pension cost for 1997 included the following components (the components for the period from the acquisition date of Northern to December 31, 1996 are not meaningful): Service cost - benefits earned during the period$ 12,600 Interest cost on projected benefit obligation 62,300 Actual return on plan assets (71,300) Net periodic pension cost $ 3,600 20. Commitments and Contingencies Casecnan In November 1995, the Company closed the financing and commenced construction of the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project (the "Casecnan Project") located in the central part of the island of Luzon in the Republic of the Philippines. CE Casecnan Water and Energy Company, Inc., a Philippine Corporation ("CE Casecnan") which is expected to be approximately 70% indirectly owned by the Company (after the KDG Acquisition), is developing the Casecnan Project. CE Casecnan financed a portion of the costs of the Casecnan Project through the issuance of $125,000 of its 11.45% Senior Secured Series A Notes due 2005 and $171,500 of its 11.95% Senior Secured Series B Bonds due 2010 and $75,000 of its Secured Floating Rate Notes due 2002, pursuant to an indenture dated as of November 27, 1995, as amended to date. The Casecnan Project was being constructed pursuant to a fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As of May 7, 1997, CE Casecnan terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of each such company. On May 7, 1997 CE Casecnan entered into a new turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impressa Pizzarottie & C. Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Replacement Contractor"). In connection with the Hanbo Contract termination, CE Casecnan tendered a certificate of drawing to Korea First Bank ("KFB") on May 7, 1997 under the irrevocable standby letter of credit issued by KFB as security under the Hanbo Contract to pay for certain transition costs and other presently ascertainable damages under the Hanbo Contract. As a result of KFB's wrongful dishonor of the draw request, CE Casecnan filed an action in New York State Court. That Court granted CE Casecnan's request for a temporary restraining order requiring KFB to deposit $79,329, the amount of the requested draw, in an interest bearing account with an independent financial institution in the United States. KFB appealed this order, but the appellate court denied KFB's appeal and on May 19, 1997, KFB transferred funds in the amount of $79,329 to a segregated New York bank account pursuant to the Court order. If KFB were to fail to honor its obligations under the Casecnan letter of credit, such action could have a material adverse effect on the Casecnan Project and CE Casecnan. On August 6, 1997, CE Casecnan announced that it had issued a notice to proceed to the Replacement Contractor. The Replacement Contractor was already on site and has fully mobilized and commenced engineering, procurement and construction work on the Casecnan Project. On August 27, 1997, CE Casecnan announced that it had received a favorable summary judgment ruling in New York State Court against KFB. The judgment, which has been appealed by the bank, requires KFB to honor the $79,329 drawing by CE Casecnan on the $117,850 irrevocable standby letter of credit. On September 29, 1997, CE Casecnan tendered a second certificate of drawing for $10,828 to KFB and on December 30, 1997, CE Casecnan tendered a third certificate of drawing for $2,920 to KFB. KFB also wrongfully dishonored these draws, but pursuant to a stipulation agreed to deposit the draw amounts in an interest bearing account with the same independent financial institution in the United States pending resolution of the appeal regarding the first draw and agreed to expedite the appeal. The receipt of the letter of credit funds from KFB remains essential and CE Casecnan will continue to press KFB to honor its clear obligations under the letter of credit and to pursue Hanbo and KFB for any additional damages arising out of their actions to date. If KFB were to fail to honor its obligations under the Casecnan letter of credit, such action could have a material adverse effect on the Casecnan Project and CE Casecnan. On September 2, 1997, Hanbo and HECC filed a Request for Arbitration before the International Chamber of Commerce ("ICC"). The Request for Arbitration asserts various claims by Hanbo and HECC against CE Casecnan relating to the terminated Hanbo Contract and seeking damages. On October 10, 1997, CE Casecnan served its answer and defenses in response to the Request for Arbitration as well as counterclaims against Hanbo and HECC for breaches of the Hanbo Contract. The arbitration proceedings before the ICC are ongoing and CE Casecnan intends to pursue vigorously its claims against Hanbo, HECC and KFB in the proceedings described above. Indonesia On September 20, 1997, a Presidential Decree (the "Decree") was issued in Indonesia, providing for government action to the effect that, in order to address certain recent fluctuations in the value of the Indonesian currency, the start-up dates for a number of private power projects would be: (i) continued according to their initial schedule (because construction was underway); (ii) postponed as to their start- up dates (because they are not yet in construction) until economic conditions have recovered; or (iii) reviewed with a view to being continued, postponed or rescheduled, depending on the status of those projects. In the Decree, Dieng Units 1, 2 and 3 are approved to continue according to their initial schedule; Patuha Unit 1 and Bali Units 1 and 2 are to receive further review to determine whether or not they should be continued in accordance with their initial schedule; and Bali Units 3 and 4, Patuha Units 2, 3 and 4 and Dieng Unit 4 are to be postponed for an unspecified period. In this regard, the Company notes that its contracts and government undertakings for the Dieng, Patuha and Bali projects do not by their terms permit such categorization or delays by the government and that the Company has obtained political risk insurance coverage for its Dieng and Patuha projects. Moreover, the Company intends to continue to take actions to attempt to require the Government of Indonesia to honor its contractual obligations; however, subsequent actions by the Government of Indonesia and continued economic problems in Indonesia have created further uncertainty as to whether the contracts for such projects will be abrogated by the Indonesian government and accordingly have created significant risks to the completion of these projects. As a result, the Company recorded a SFAS 121 asset valuation impairment charge of $87,000 in the fourth quarter of 1997. This charge includes all reasonably estimated asset valuation impairments associated with the Company's assets in Indonesia and gives effect to the political risk insurance on such investments. Edison On June 9, 1997, Edison filed a complaint alleging breach of the power purchase agreements ("SO4 Agreements") between Edison and the Coso Joint Ventures as a result of alleged improper venting of certain noncondensible gases at the Coso geothermal energy project. In the complaint Edison seeks unspecified damages, including the refund of certain amounts previously paid under the SO4 Agreements, and termination of the SO4 Agreements. In September 1997, the Coso Joint Ventures and the Company filed a cross-complaint against Edison and its affiliates, The Mission Group and Mission Power Engineering Company alleging, among other things, that Edison's lawsuit violates the 1993 settlement agreement which settled certain litigation arising from the construction of certain units at the Coso geothermal project by Edison affiliates. In addition, the Coso Joint Ventures filed a separate complaint against Edison alleging breach of the SO4 Agreements, unfair business practices, slander and various other tort and contract claims. The actions were effectively consolidated in December 1997. As a result of certain procedural actions by the parties and a November court order, Edison filed an amended complaint on December 16, 1997 and the Coso Joint Ventures amended their cross- complaint. The litigation is in its early procedural stages and the pleadings have not been settled. The Coso Joint Ventures believe that their claims and defenses are meritorious and that they will prevail if the matter is ultimately heard on its merits. The Coso Joint Ventures intend to vigorously defend this action and prosecute all available counterclaims against Edison. NYSEG On February 14, 1995, NYSEG filed with the FERC a Petition for a Declaratory Order, Complaint, and Request for Modification of Rates in Power Purchase Agreements Imposed Pursuant to the Public Utility Regulatory Policies Act of 1978 ("Petition") seeking FERC (i) to declare that the rates NYSEG pays under the Saranac PPA, which was approved by the New York Public Service Commission (the "PSC") were in excess of the level permitted under PURPA and (ii) to authorize the PSC to reform the Saranac PPA. On March 14, 1995, the Saranac Partnership intervened in opposition to the Petition asserting, inter alia, that the Saranac PPA fully complied with PURPA, that NYSEG's action was untimely and that the FERC lacked authority to modify the Saranac PPA. On March 15, 1995, the Company intervened also in opposition to the Petition and asserted similar arguments. On April 12, 1995, the FERC by a unanimous (5-0) decision issued an order denying the various forms of relief requested by NYSEG and finding that the rates required under the Saranac PPA were consistent with PURPA and the FERC's regulations. On May 11, 1995, NYSEG requested rehearing of the order and, by order issued July 19, 1995, the FERC unanimously (5-0) denied NYSEG's request. On June 14, 1995, NYSEG petitioned the United States Court of Appeals for the District of Columbia Circuit (the "Court of Appeals") for review of FERC's April 12, 1995 order. FERC moved to dismiss NYSEG's petition for review on July 28, 1995. On October 30, 1996, all parties filed final briefs and the Court of Appeals heard oral arguments on December 2, 1996. On July 11, 1997, the Court of Appeals dismissed NYSEG's appeal from FERC's denial of the petition on jurisdictional grounds. On August 7, 1997, NYSEG filed a complaint in the U.S. District Court for the Northern District of New York against the FERC, the PSC (and the Chairman, Deputy Chairman and the Commissioners of the PSC as individuals in their official capacity), the Saranac Partnership and Lockport Energy Associates, L.P. ("Lockport") concerning the power purchase agreements that NYSEG entered into with Saranac Partners and Lockport. NYSEG's suit asserts that the PSC and the FERC improperly implemented PURPA in authorizing the pricing terms that NYSEG, the Saranac Partnership and Lockport agreed to in those contracts. The action raises similar legal arguments to those rejected by the FERC in its April and July 1995 orders. NYSEG in addition asks for retroactive reformation of the contracts as of the date of commercial operation and seeks a refund of $281 million from the Saranac Partnership. Saranac and other parties have filed motions to dismiss and oral arguments on those motions were heard on March 2, 1998. Saranac believes that NYSEG's claims are without merit for the same reasons described in the FERC's orders. Leases Certain retail facilities, buildings and equipment are leased. The leases expire in periods ranging from one to 75 years and some provide for renewal options. At December 31, 1997, the Company's future minimum rental payments with respect to non-cancelable operating leases were as follows: 1998 $ 5,321 1999 4,970 2000 4,914 2001 4,742 2002 4,643 Thereafter 53,905 $ 78,495 21. Geographic Information The Company operates in one principal industry segment: the generation, distribution and supply of electricity to customers located throughout the world. Europe consists primarily of Northern. The Company's operations by geographic area are as follows: 1997 1996 1995 Revenue Americas $ 570,587$ 486,189 $ 386,833 Asia 102,960 33,282 --- Europe 1,566,442 39,191 --- Corporate/Other 30,922 17,533 11,890 $2,270,911 $ 576,195 $ 398,723 Operating income * Americas $ 301,589 $ 259,665 $ 209,872 Asia 61,131 16,766 --- Europe 191,299 6,163 --- Corporate/Other (12,882) (10,931) (10,376) $ 541,137 $ 271,663 $ 199,496 * Operating income excludes the loss on equity investment in Casecnan, net interest expense and the non-recurring charge. 1997 1996 Identifiable assets Americas $ 2,268,629 $ 2,364,448 Asia 835,616 649,053 Europe 2,937,686 2,384,789 Corporate/Other 1,445,695 231,866 $ 7,487,626 $ 5,630,156 22. QUARTERLY FINANCIAL DATA (UNAUDITED) Following is a summary of the Company's quarterly results of operations for the years ended December 31, 1997 and 1996. Three Months Ended * 1997: (1) March 31 June 30 September 30 December 31 Operating revenue $542,589 $505,922 $527,896 $589,931 Total revenue 565,976 524,994 551,893 628,048 Total costs and 506,104 460,184 467,900 639,863 expenses Income (loss) before 59,872 64,810 83,993 (11,815) income taxes 22,249 24,342 27,929 24,524 Provision for income taxes Income (loss) before 37,623 40,468 56,064 (36,339) minority interest 10,175 9,579 9,656 16,583 Minority interest Income (loss) before 27,448 30,889 46,408 (52,922) extraordinary item --- --- (135,850) --- Extraordinary item Net income (loss) attributable to 27,448 30,889 (89,442) (52,922) common stockholders Income (loss) per share before extraordinary item $ .43 $ .49 $ .73 $ (.67) Extraordinary item --- --- (2.14) --- Net income (loss) per share $ .43 $ .49 $ (1.41) $ (.67) Income (loss) per share before extraordinary item - $ .42 $ .46 $ .67 $ (.67) diluted --- --- (1.80) --- Extraordinary item - diluted Net income (loss) per share - diluted $ .42 $ .46 $ (1.13) $ (.67) Three Months Ended * 1996: (112) March 31 June 30 September 30 December 31 Operating revenue $ 75,944 $104,735 $165,487 $172,768 Total revenue 90,356 115,794 179,048 190,997 Total costs and 69,398 86,039 121,545 158,809 expenses Income before income 20,958 29,755 57,503 32,188 taxes 6,497 9,040 18,325 7,959 Provision for income taxes Income before minority 14,461 20,715 39,178 24,229 interest --- 1,443 1,624 3,055 Minority interest Net income attributable to common stockholders $14,461 $19,272 $37,554 $ 21,174 Net income per share $ .28 $ .37 $ .71 $ .34 Net income per share - diluted $ .27 $ .34 $ .61 $ .33 * The Company's operations are seasonal in nature. (1) Reflects acquisitions of Northern, Falcon Seaboard and the Partnership Interest. INDEPENDENT AUDITORS' REPORT Board of Directors and Shareholders CalEnergy Company, Inc. Omaha, Nebraska We have audited the accompanying consolidated balance sheets of CalEnergy Company, Inc. and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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 generally accepted auditing standards. 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, such consolidated financial statements present fairly, in all material respects, the financial position of CalEnergy Company, Inc. and subsidiaries at December 31, 1997 and 1996 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. Deloitte & Touche LLP Omaha, Nebraska February 12, 1998 EX-21 9 EXHIBIT 21 CALENERGY COMPANY, INC. SUBSIDIARIES AND JOINT VENTURES Corporations: COSO HOTSPRINGS INTERMOUNTAIN POWER, INC. Delaware CHINA LAKE OPERATING COMPANY Delaware COSO TECHNOLOGY CORPORATION Delaware COSO FUNDING CORP. Delaware CHINA LAKE GEOTHERMAL MANAGEMENT COMPANY Delaware CHINA LAKE PLANT SERVICES, INC. California COSO HOTSPRINGS OVERLAND POWER, INC. Delaware CE GEOTHERMAL, INC. Delaware WESTERN STATES GEOTHERMAL COMPANY Delaware INTERMOUNTAIN GEOTHERMAL COMPANY Delaware CE CIS-FSU, Inc. Delaware CALENERGY DEVELOPMENT CORPORATION Delaware CALIFORNIA ENERGY YUMA CORPORATION Utah ROSE VALLEY PROPERTIES, INC. Delaware CBE ENGINEERING CO. California CE EXPLORATION COMPANY Delaware CE NEWBERRY, INC. Delaware CE HUMBOLDT, INC. Delaware CALENERGY INTERNATIONAL SERVICES, INC. Delaware AMERICAN PACIFIC FINANCE COMPANY Delaware CALIFORNIA ENERGY GENERAL CORPORATION Delaware GILBERT/CBE INDONESIA L.L.C. Nebraska CE INTERNATIONAL INVESTMENTS, INC. Delaware CE MAHANAGDONG LTD. Bermuda CE LUZON GEOTHERMAL POWER COMPANY, INC. Philippines CE PHILIPPINES LTD. Bermuda ORMOC CEBU LTD. Bermuda CE CEBU GEOTHERMAL POWER COMPANY, INC. Philippines CE INDONESIA LTD. Bermuda HIMPURNA CALIFORNIA ENERGY LTD. Bermuda CE COLOMBIA LTD. Bermuda BALI ENERGY LTD. Bermuda CE CASECNAN LTD. Bermuda CE LATIN AMERICA LTD. Bermuda PATUHA POWER, LTD. Bermuda CE SINGAPORE LTD. Bermuda CALENERGY INTERNATIONAL LTD. Bermuda CE CASECNAN WATER AND ENERGY COMPANY, INC. Philippines CE BALI LTD. Bermuda CE IJEN LTD. Bermuda CE ASIA LTD. Bermuda CE OVERSEAS LTD. Bermuda MAGMA POWER COMPANY Nevada DESERT VALLEY COMPANY California VULCAN POWER COMPANY Nevada CALENERGY OPERATING CORPORATION Delaware SALTON SEA POWER COMPANY Nevada IMPERIAL MAGMA Nevada MAGMA LAND COMPANY I Nevada MAGMA GENERATING COMPANY II Nevada MAGMA GENERATING COMPANY I Nevada PEAK POWER CORPORATION California FISH LAKE POWER COMPANY Delaware CALIFORNIA ENERGY MANAGEMENT COMPANY Delaware SALTON SEA FUNDING CORPORATION Delaware SALTON SEA ROYALTY COMPANY Delaware TONGONAN POWER INVESTMENT, INC. Philippines MAGMA NETHERLANDS B.V. Netherlands NORMING INVESTMENTS B.V. Netherlands CALIFORNIA ENERGY RETAIL COMPANY, INC. Delaware CALENERGY IMPERIAL VALLEY COMPANY, INC. Delaware SLUPO I B.V. Netherlands BN GEOTHERMAL INC. Delaware CONEJO ENERGY COMPANY California NIGUEL ENERGY COMPANY California SAN FELIPE ENERGY COMPANY California BIOCLEAN FUELS INC. Delaware CE/FS HOLDING COMPANY, INC. Delaware CALENERGY BCF, INC. Delaware CE ALBERTA BIOCLEAN, INC. Delaware AMERICAN PACIFIC FINANCE COMPANY II Delaware FALCON SEABOARD RESOURCES, INC. Texas FALCON SEABOARD ENERGY CORPORATION Texas FALCON SEABOARD OIL COMPANY Texas FALCON SEABOARD PIPELINE CORPORATION Texas FALCON SEABOARD POWER CORPORATION Texas FALCON SEABOARD GAS COMPANY Texas POWER RESOURCES, INC. Texas BIG SPRING PIPELINE COMPANY Texas SECI HOLDINGS, INC. Delaware FALCON POWER OPERATING COMPANY Texas NORCON HOLDINGS, INC. Delaware SARANAC ENERGY COMPANY, INC. Delaware NORTHERN CONSOLIDATED POWER, INC. Delaware NORTH COUNTRY GAS PIPELINE CORPORATION New York CE POWER, INC. Delaware CE ELECTRIC, INC. Delaware CE ELECTRIC UK plc England/Wales NORTHERN ELECTRIC PLC England/Wales NORTHERN ELECTRIC GENERATION LIMITED England/Wales NORTHERN ELECTRIC (OVERSEAS HOLDINGS) LIMITED England/Wales NORTHERN ELECTRIC PROPERTIES LIMITED England/Wales NORTHERN ELECTRIC FINANCE PLC England/Wales NORTHERN TRACING AND COLLECTION SERVICES LIMITED England/Wales GAS UK LIMITED England/Wales CALENERGY GAS (HOLDINGS) LIMITED England/Wales NORTHERN ELECTRIC SHARE SCHEME TRUSTEE LIMITED England/Wales NORTHERN TRANSPORT FINANCE LIMITED England/Wales NORTHERN ELECTRIC RETAIL LIMITED England/Wales NORTHERN ELECTRIC DISTRIBUTION LIMITED England/Wales NORTHERN ELECTRIC SUPPLY LIMITED England/Wales NORTHERN METERING SERVICES LIMITED England/Wales NORTHERN UTILITY SERVICES LIMITED England/Wales NORTHERN ELECTRIC TELECOM LIMITED England/Wales NORTHERN ELECTRIC TRANSPORT LIMITED England/Wales NORTHERN INFORMATION SYSTEMS LIMITED England/Wales NORTHERN ELECTRIC TRAINING LIMITED England/Wales NORTHERN ELECTRIC GENERATION (TPL) LIMITED England/Wales NORTHERN ELECTRIC GENERATION (CPS) LIMITED England/Wales NORTHERN ELECTRIC GENERATION (NPL) LIMITED England/Wales NORTHERN ELECTRIC GENERATION (PEAKING) LIMITED England/Wales NORTHERN ELECTRIC INSURANCE SERVICES LIMITED Isle of Man CALENERGY GAS (UK) LIMITED England/Wales CE INDONESIA GEOTHERMAL, INC. Delaware CALENERGY MINERALS, INC. Delaware CE INDONESIA FUNDING CORP. Delaware CEABC CO. Delaware CEXYZ CO. Delaware CE ELECTRIC (NY), INC. New York NEPTUNE POWER LTD England/Wales CALENERGY GAS (POLSKA) SP. Z O.O. Poland CE (BERMUDA) FINANCING LTD. Bermuda CALENERGY GAS (PIPELINES) LIMITED England/Wales POLSKA POWER SP. Z O.O. Poland SALTON SEA POWER L.L.C. Delaware KIEWIT ENERGY COMPANY Delaware KIEWIT ENERGY PACIFIC HOLDINGS CORP. Delaware KIEWIT ENERGY U.K. INC. Delaware KIEWIT ENERGY INTERNATIONAL (BERMUDA) LTD. Bermuda CE SALTON SEA INC. Delaware AURORA I, L.L.C. Delaware CE AURORA I, INC. Delaware NORTHERN AURORA, INC. Delaware CALENERGY MINERALS LLC Delaware Joint Ventures/Partnerships: COSO ENERGY DEVELOPERS California COSO FINANCE PARTNERS California COSO POWER DEVELOPERS California COSO TRANSMISSION LINE PARTNERS California COSO FINANCE PARTNERS II California COSO LAND COMPANY California CHINA LAKE JOINT VENTURE California COSO GEOTHERMAL COMPANY California YUMA COGENERATION ASSOCIATES Utah GILBERT/CBE, L.P. Nebraska VULCAN/BN GEOTHERMAL POWER COMPANY Nevada LEATHERS, L.P. California ELMORE, L.P. California DEL RANCH, L.P. (HOCH) California SALTON SEA BRINE PROCESSING, L.P. California SALTON SEA POWER GENERATION L.P. California ALTO PEAK POWER COMPANY Philippines VISAYAS GEOTHERMAL POWER COMPANY Philippines SARANAC POWER PARTNERS, L.P. Delaware NORCON POWER PARTNERS, L.P. Delaware CE ELECTRIC UK HOLDINGS England/Wales VIKING POWER LTD England/Wales SEAL SANDS NETWORK LIMITED England/Wales CE ELECTRIC UK FUNDING COMPANY England/Wales EX-23 10 Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 33-41152, No. 33-52147 and No. 333-30395 on Form S- 8 and Registration Statement No. 33-51363 and No. 333-32821 on Form S-3 of CalEnergy Company, Inc. of our reports dated February 12, 1998, appearing in and incorporated by reference in the Annual Report on Form 10-K of CalEnergy Company, Inc. for the year ended December 31, 1997. DELOITTE & TOUCHE L.L.P. Omaha, Nebraska March 27, 1998 EX-24 11 Exhibit 24 POWER OF ATTORNEY The undersigned, a member of the Board of Directors of CalEnergy Company, Inc., a Delaware corporation (the "Company"), hereby constitutes and appoints Steven A. McArthur, Craig M. Hammett and Douglas L. Anderson and each of them, as his/her true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for and in his/her stead, in any and all capacities, to sign on his/her behalf the Company's Form 10-K Annual Report for the fiscal year ending December 31, 1997 and to execute any amendments thereto and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission and applicable stock exchanges, with the full power and authority to do and perform each and every act and thing necessary or advisable to all intents and purposes as he/she might or could do in person, hereby ratifying and confirming all that said attorney- in-fact and agent, or his/her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. POWER OF ATTORNEY Executed as of March 27, 1998 /s/ David L. Sokol /s/ David R. Morris DAVID L. SOKOL DAVID R. MORRIS /s/ Edgar D. Aronson /s/ Bernard W. Reznicek EDGAR D. ARONSON BERNARD W. REZNICEK /s/ Judith E. Ayres /s/ Walter Scott, Jr. JUDITH E. AYRES WALTER SCOTT, JR. /s/ Richard K. Davidson /s/ John R. Shiner RICHARD K. DAVIDSON JOHN R. SHINER /s/ David H. Dewhurst /s/ Sir Neville G. Trotter DAVID H. DEWHURST SIR NEVILLE G. TROTTER /s/ Richard R. Jaros /s/ David E. Wit RICHARD R. JAROS DAVID E. WIT /s/ Ben Holt BEN HOLT EX-27.1 12
5 1,000 12-MOS DEC-31-1997 DEC-31-1997 1,675,046 1,282 376,745 0 0 0 4,026,742 497,832 7,487,626 0 3,492,852 553,930 56,181 5,602 759,724 7,487,626 2,166,338 2,270,911 1,055,195 345,833 52,705 0 251,305 196,860 99,044 51,823 0 (135,850) 0 (84,027) (1.25) (1.22)
EX-27.2 13 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE. Restated Financial Data Schedule Exhibit 27.2 Item 601(c) of Regulation S-K Commercial and Industrial Companies Article 5 of Regulation S-X (dollars in thousands, except per share amounts)
Three Months Six Months Nine Months Ended Ended Ended December 31, December 31, March 31, June 30, September 30, Item Number Item Description 1995 1996 1996 1996 1996 5-02(1) cash and cash items 298,931 579,726 326,150 388,726 465,819 5-02(2) marketable securities 34,190 4,921 12,691 3,295 2,864 5-02(3)(a)(6)notes and accounts receivable-trade 57,909 342,307 47,527 79,771 109,453 5-02(4) allowances for doubtful accounts N/A N/A N/A N/A N/A 5-02(6) inventory N/A N/A N/A N/A N/A 5-02(9) total current assets N/A N/A N/A N/A N/A 5-02(13) property, plant and equipment 1,945,439 3,619,799 2,040,011 2,233,645 2,461,673 5-02(14) accumulated depreciation 164,184 271,216 179,917 205,021 237,903 5-02(18) total assets 2,654,038 5,712,907 2,721,400 2,975,127 3,548,442 5-02(21) total current liabilities N/A N/A N/A N/A N/A 5-02(22) bonds and mortgages and similar debt 1,763,424 2,901,580 1,793,305 1,922,725 2,247,255 5-02(28) preferred stock- mandatory redemption N/A 103,930 N/A 103,930 103,930 5-02(29) preferred stock-no mandatory redemption N/A 136,065 N/A N/A N/A 5-02(30) common stock 3,421 4,303 3,523 3,523 3,853 5-02(31) other stockholders' equity 540,111 876,487 565,705 584,413 717,959 5-02(32) total liabilities and stockholders'equity 2,654,038 5,712,907 2,721,400 2,975,127 3,548,442 5-03(b)(1)(a)net sales of tangible products 335,630 518,934 75,944 180,679 346,166 5-03(b)(1) total revenues 398,723 576,195 90,356 206,150 385,198 5-03(b)(2)(a)costs of tangible goods sold N/A 31,840 N/A N/A N/A 5-03(b)(2) total costs and expenses applicable to sales and revenues-operating expense 103,602 132,655 23,331 51,658 91,840 5-03(b)(3) other costs and expenses-general and administration 23,376 21,451 4,179 9,296 15,814 5-03(b)(5) provision for doubtful accounts and notes N/A N/A N/A N/A N/A 5-03(b)(8) interest and amortization of debt discount 102,083 126,038 22,873 47,996 85,062 5-03(b)(10) income before taxes and other items 97,051 135,713 20,958 49,270 108,216 5-03(b)(11) income tax expense 30,631 41,821 6,497 15,537 33,862 5-03(b)(14) income continuing operations 63,415 92,461 14,461 33,733 71,287 5-03(b)(19) net income 63,415 92,461 14,461 33,733 71,287 5-03(b)(20) earnings per share 1.32 1.69 .28 .65 1.37 5-03(b)(20) earnings per share diluted 1.22 1.54 .27 .60 1.22
EX-27.3 14 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE. Restated Financial Data Schedule Exhibit 27.3 Item 601(c) of Regulation S-K Commercial and Industrial Companies Article 5 of Regulation S-X (dollars in thousands, except per share amounts)
Three Months Six Months Nine Months Ended Ended Ended March 31, June 30, September 30, Item Number Item Description 1997 1997 1997 5-02(1) cash and cash items 457,729 494,953 840,435 5-02(2) marketable securities 6,742 5,958 1,481 5-02(3)(a)(1) notes and accounts receivable-trade 347,594 343,818 332,991 5-02(4) allowances for doubtful accounts N/A N/A N/A 5-02(6) inventory N/A N/A N/A 5-02(9) total current assets N/A N/A N/A 5-02(13) property plant and equipment 3,913,619 4,055,501 3,963,536 5-02(14) accumulated depreciation 332,179 388,874 445,547 5-02(18) total assets 6,138,050 6,275,061 6,385,039 5-02(21) total current liabilities N/A N/A N/A 5-02(22) bonds and mortgages and similar debt 3,228,619 3,230,356 3,141,738 5-02(28) preferred stock-mandatory redemption 283,930 283,930 553,930 5-02(29) preferred stock-no mandatory redemption 89,040 59,101 56,387 5-02(30) common stock 4,303 4,311 4,312 5-02(31) other stockholders' equity 872,061 913,601 146,062 5-02(32) total liabilities and stockholders' equity 6,138,050 6,275,061 6,385,039 5-03(b)(1)(a) net sales of tangible products 542,589 1,048,511 1,576,407 5-03(b)(1) total revenues 565,976 1,090,970 1,642,863 5-03(b)(2)(a) costs of tangible goods sold 277,382 518,930 758,011 5-03(b)(2) total costs and expenses applicable to sales and revenues-operating expense 83,611 160,491 243,004 5-03(b)(3) other costs and expenses- general and administration 13,487 25,492 37,560 5-03(b)(5) provision for doubtful accounts and notes N/A N/A N/A 5-03(b)(8) interest and amortization of debt discount 61,500 119,506 182,503 5-03(b)(10) income before taxes and other items 57,154 117,528 208,675 5-03(b)(11) income tax expense 22,249 46,591 74,520 5-03(b)(14) income continuing operations 27,448 58,337 104,745 5-03(b)(15) discontinued operations N/A N/A N/A 5-03(b)(17) extraordinary items N/A N/A (135,850) 5-03(b)(18) cumulative effect-changes in accounting principle N/A N/A N/A 5-03(b)(19) net income (loss) 27,448 58,337 (31,105) 5-03(b)(20) earnings per share .43 .92 (.49) 5-03(b)(20) earnings per share diluted .42 .88 (.30)
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