-----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, Q8ZT/ZnFyk0JVgd4E7g6sh7hExQXxRAKaNemHyvanVPZuf9ACsz5g5dnsaCg153J No6Gfllg6Q5jtnQaC0iMvg== 0001081316-00-000009.txt : 20000331 0001081316-00-000009.hdr.sgml : 20000331 ACCESSION NUMBER: 0001081316-00-000009 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MIDAMERICAN ENERGY HOLDINGS CO /NEW/ CENTRAL INDEX KEY: 0001081316 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC, GAS & SANITARY SERVICES [4900] IRS NUMBER: 942213782 STATE OF INCORPORATION: IA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-14881 FILM NUMBER: 587517 BUSINESS ADDRESS: STREET 1: 666 GRAND AVE STREET 2: PO BOX 657 CITY: DES MOINES STATE: IA ZIP: 50309 BUSINESS PHONE: 5152424300 MAIL ADDRESS: STREET 1: 666 GRAND AVE STREET 2: PO BOX 657 CITY: DES MOINES STATE: IA ZIP: 50309 FORMER COMPANY: FORMER CONFORMED NAME: MID AMERICAN ENERGY HOLDINGS CO /NEW/ DATE OF NAME CHANGE: 19990308 10-K405 1 10-K405 MIDAMERICAN ENERGY HOLDINGS SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K Annual Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1999 Commission File No. 0-25551 MIDAMERICAN ENERGY HOLDINGS COMPANY (Exact name of registrant as specified in its charter) Iowa 94-2213782 ---- ---------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 666 Grand Avenue, Des Moines, IA 50309 -------------------------------- ----- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (515) 242-4300 -------------- Securities registered pursuant to Section 12(b) of the Act: N/A 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 require- ments 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] All of the shares of MidAmerican Energy Holdings Company are held by a limited group of private investors. As of March 30, 2000, 9,281,087 shares of common stock were outstanding. TABLE OF CONTENTS ----------------- PART I........................................................................4 Item 1. Business.............................................................4 General.......................................................................4 Berkshire Transaction.........................................................4 Strategy......................................................................4 The Global Energy Market...............................................6 The United States......................................................6 The United Kingdom.....................................................8 The Company's Distribution and Supply Business...............................10 MidAmerican Energy Company............................................10 Northern Electric.....................................................14 The Company's Power Generation Project Portfolio.............................15 Projects in Operation........................................................17 United States Power Generation........................................17 MidAmerican Energy Generation Facilities..............................17 CE Generation Geothermal Facilities...................................18 CE Generation Gas Facilities..........................................20 Other U.S. Geothermal Interests.......................................21 United Kingdom Power Generation.......................................21 The Philippines Power Generation......................................22 Projects in Construction.....................................................24 United States.........................................................24 Philippines...........................................................25 United Kingdom........................................................26 Projects in Development.......................................................26 United States.........................................................26 United Kingdom........................................................27 Producing Gas Field Operations and Fields in Development.....................27 Producing Fields......................................................27 Projects in Development...............................................27 Other ......................................................................29 HomeServices..........................................................29 Indonesia.............................................................29 Regulatory, Energy and Environmental Matters.................................30 United States.........................................................30 United Kingdom........................................................31 Employees....................................................................32 Item 2. Properties..........................................................32 Item 3. Legal Proceedings...................................................33 Item 4. Submission of Matters to a Vote of Security Holders.................33 PART II............................................................. ........34 Item 5. Market for Registrant's Common Equity and Related Stockholder's Matters...............................................34 Item 6. Selected Financial Data.............................................34 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...........................................34 Item 7A. Qualitative and Quantitative Disclosures About Market Risk..........34 Item 8. Financial Statements and Supplementary Data.........................34 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................................34 PART III.....................................................................35 Management...................................................................35 -2- Item 10. Directors, Executive and Other Officers of the Company and Significant Subsidiaries......................... ......35 Item 11. Executive Compensation..............................................40 Item 12. Security Ownership of Certain Beneficial Owners and Management......40 Item 13. Certain Relationships and Related Transactions......................40 PART IV......................................................................41 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....41 SIGNATURES..................................................................100 EXHIBIT INDEX...............................................................102 -3- PART I ITEM 1. BUSINESS General - ------- MidAmerican Energy Holdings Company (the "Company" or "MEHC"), is a United States based privately owned global energy company with publicly traded fixed income securities. Through its subsidiaries, the Company manages, owns interests in and has under contract approximately 9,700 megawatts ("MW") of diversified power generation facilities in operation, construction and development. In addition, through its subsidiaries, MidAmerican Energy Company ("MidAmerican Energy" or "MEC") and Northern Electric plc ("Northern"), the Company currently serves approximately 2.0 million electricity customers and 1.2 million natural gas customers worldwide. The Company's Senior unsecured obligations have received investment grade ratings of Baa3, BBB- and BBB- from Moody's Investor Services Inc. ("Moody's"), Standard & Poors Ratings Services (S&P) and Duff & Phelps Credit Rating Company (DCR). The Company's utility subsidiaries are also investment grade rated by Moody's, S&P and DCR: MidAmerican Energy (A3, A- and A+) and Northern (A3, A- and A). 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," "pence" or "p" are to the currency of the United Kingdom. The principal executive offices of the Company are located at 666 Grand Avenue, Des Moines, Iowa 50309 and its telephone number is (515) 242-4300. The Company was initially incorporated in 1971 under the laws of the State of Delaware. The Company was reincorporated in 1999 in Iowa. Berkshire Transaction - --------------------- On October 24, 1999, the Company entered into an Agreement and Plan of Merger with an investor group that included Berkshire Hathaway Inc., Walter Scott, Jr., and David L. Sokol (the "Investor Group"). The Investor Group closed on the acquisition on March 14, 2000. Pursuant to the acquisition, the Investor Group paid the Company's shareholders $35.05 in cash for each outstanding share of the Company's common stock and became the sole shareholders of the Company in a "going private" transaction. Strategy - -------- The Company's strategy remains focused on profit enhancement through operating efficiencies while maintaining quality and reliability of service and continued diversification of its assets by taking advantage of the investment opportuni- ties created by the continuing restructuring and privatization in energy sectors in the United States and throughout the world. In order to effectively execute its strategy, the Company has organized its operations into a functional structure. The functional alignment is believed to allow for greater effi- ciencies in operations and better coordination and asset utilization in devel- oping the Company's business. The Company's strategy is comprised of the following key elements: 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. The cost of production per kWh at the Imperial Valley Projects (as defined herein) has declined from 5.3 cents/kWh in 1994 to 2.6 cents/kWh in 1999. The Company has achieved these efficien- cies 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. -4- o Continued Diversification of Revenue Base and Fuel Sources. The Com- pany believes that it has a diversified revenue base, distributed among its ownership of two operating electricity and gas utilities, its ownership of interests in diversified power generation facilities with 10,260 net MW in operation, under construction or in development and its ownership of producing gas fields (all as described in more detail below). In addition to the revenues of MidAmerican Energy, which are largely derived from the generation, transmission, distribution and sale of electricity and the distribution and sale of gas activities, and Northern, which are largely derived from their electricity distri- bution and gas supply activities, a portion of the Company's revenues are from its 50% equity ownership interest in CE Generation, throug long-term contracts between project subsidiaries and four large U.S. utility companies, and the Company's subsidiaries' long-term contracts with the Government of the Philippines (sovereign ratings of Ba1/BB+). The Company intends to seek continued diversification of its revenu base and fuel sources through acquisitions and greenfield development. o Growth through International and Domestic Acquisitions. The Company intends to continue to opportunistically engage in international and domestic acquisitions of energy projects and companies that support it long term investment strategy. The Company further believes that the electricity and gas industry in the U.S. will progressively restructure over the next three to five years and will largely follow the deregulatory 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 pro- fitability in a price competitive market, the Company believes that opportunities will become available to acquire low cost and reliabl providers of energy services to gain market share in energy supply and provide additional services to competitors (such as utility line con- struction and maintenance services, metering, customer billing and information systems services). o Growth through Greenfield Development of Energy Projects. The Company has commenced construction of a 537 MW natural gas fired generation facility which will sell power on a partial contract and partial merchant basis. The facility is located near the Quad Cities in Illi- nois and Iowa on the border of two electric reliability districts, the Mid-Continent. Area Power Pool and the Mid-America Interconnection Network. In addition to developing domestic 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. With CalEnergy Gas (UK)Limited, the Company has expanded its development strategy to include integrated upstream natural gas opera- tions. 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. o Maintenance of Prudent Financial and Risk Management Practices. The Company has consistently maintained, and intends in the future to main- tain what it believes to be prudent financial and risk management practices. A primary objective of the Company is to structure project financings for development projects which can be rated investment grade by Moody's, DCR and S&P. The Company's senior unsecured obligations are rated Baa3, BBB- and BBB-. Its MidAmerican Energy subsidiary is rated A3, A+ and A-; Salton Sea Funding Corp. is rated Baa2/BBB; CE Genera- tion LLC is rated Baa3, BBB and BBB-; its Northern Electric subsidiary is rated A3, A and A-, and its CE Electric UK Funding Company subsidi- ary's senior notes are rated Baa1, A- and BBB+. The debt ratings reflected above have been published by Moody's, DCR (for all except Salton Sea Funding) and S&P, 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 fin- ancing structures utilized to date by the Company include as a funda- mental protection for the Company's other assets the requirement that (with certain minimal exceptions) the funds borrowed and other obliga- tions for the purpose of financing or operating a project are to be primarily or entirely under loan agreements, project agreements and related -5- documents which provide that the obligations and loans are to be performed or repaid solely by the project and from the project's revenues and that the security granted to secure the loan and other obligations be limited to the capital stock, assets, contracts and cash flow of the project or the project holding company. Under this type of structure, the lenders and other project contracting parties cannot seek recourse against the Company or its other subsidiaries or projects. The Company intends to continue to structure future project in a manner which minimizes the exposure of the Company's other assets through appropriate non-recourse project structures. 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 overed by insurance. The Company's international invest- ment 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 con- tracts and regulations; o "Take or Pay" contracts with utilities, governments or other parties with acceptable creditworthiness which provide for pri- marily US$-denominated payments and certain contractual protec- tions 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 is a global competitive market as many countries have initiated restructuring and privatization policies that encourage the development of independent power generation and independent distribution and supply of energy. The movement toward privatization in some developing countries has created new markets. The need for 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 intends to evaluate opportunities in these markets and to develop, construct and acquire power generation, distribution and supply and related energy projects meeting its strategic criteria both inside and outside the United States. In addition, as privatization, deregulation and restructuring initiatives are enacted in various countries and states, the Company will evaluate opportunities to acquire power generation, distribution and supply assets, as well as other energy related infrastructure assets. In pursuing its strategy, the Company presently intends to focus upon development and acquisition opportunities in countries possessing characteristics that meet the Company's general investment criteria. At the present time, the Company is active in the United States, the Philippines and the United Kingdom. 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 -6- 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, in which the Company has several power production facilities, 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. Approximately one-half of the states have enacted electric choice legislation and 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 impact 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. In that regard, in December 1999, the Federal Energy Regulatory Commission issued Order No. 2000 establishing, among other things, minimum characteristics and functions for Regional Transmission Organizations (RTOs). Public utilities not a member of an independent system operator at the time of the order are required to submit a plan by which its transmission facilities would be transferred to an RTO on a schedule that would allow the RTO to commence operating by December 15, 2001. MidAmerican Energy, which was not a member of an independent system operator, is presently analyzing the impact that the order may have on its operations. In Illinois, the electric retail business is opening up to competition and will be phased in between October 1999 and May 2002. In Iowa, legislation that would restructure the electric utility business is being considered by the legislature during its 2000 session. MidAmerican Energy is subject to comprehensive regulation by several utility regulatory agencies that significantly influences the operating environment and the recoverability of costs from utility customers. That regulatory environment has to date, in general, given MidAmerican Energy an exclusive right to serve electricity customers within its service territory and, in turn, the obligation to provide electric service to those customers. In Iowa, if MidAmerican Energy's annual electric jurisdictional return on common equity exceeds 12%, then an equal sharing between customers and shareholders of earnings above the 12% level begins; if it exceeds 14%, then two-thirds of MidAmerican Energy's share of those earnings will be used for accelerated recovery of certain regulatory assets. MidAmerican Energy is precluded from filing for increased rates prior to 2001 unless the return on common equity falls below 9%. Other parties are prohibited from filing for reduced rates prior to 2001 unless the return on common equity, after reflecting credits to customers, exceeds 14%. Prior to July 11, 1997, MidAmerican Energy was allowed to recover its energy costs from most of its electric utility customers through energy adjustment clauses. Beginning in July 1997, the Iowa energy adjustment clause was eliminated as part of the Iowa pricing plan approved by the Iowa Utilities Board. Accordingly, flucuations in energy costs now may affect MidAmerican Energy's earnings. -7- MidAmerican Energy provides gas service at retail pursuant to non- exclusive municipal franchises. The cost of gas is recovered from customers through a purchased gas adjustment clause. In connection with the March 1999 approval by the Iowa Utilities Board of the MidAmerican Merger and recent affirmation as part of the Investor Group's acquisition of the Company, MidAmerican Energy is required, among other things, to use all commercially reasonable efforts to maintain an investment grad credit rating for MidAmerican Energy and its long-term debt and to seek the approval of the Iowa Utilities Board of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below specified levels (42% and 39%, respectively, of total capitalization under certain circum- stances. MidAmerican Energy's common equity level at December 31, 1999 was above these levels. Statement of Financial Accounting Standards (SFAS) No. 71 sets forth accounting principles for operations that are regulated and meet certain criteria. For operations that meet the criteria, SFAS 71 allows, among other things, the deferral of costs that would otherwise be expensed when incurred. A possible consequence of the changes in the utility industry is the discon- tinued applicability f SFAS 71. The majority of MidAmerican Energy's electric and gas utility operations currently meet the criteria of SFAS 71, but its applicability is periodically reexamined. If utility operations no longer meet the criteria of SFAS 71, MidAmerican Energy would be required to write off the related regulatory assets and liabilities from its balance sheet and thus, a material adjustment to earnings in that period could result. The United Kingdom The electricity industry in the United Kingdom has seen the privatization of electric supply and distribution, and gradual phase-in of competition in supply, since 1990. The Electricity Act of 1989 established an industry structure that permitted this phased-in competition to occur. Since that time, in England and Wales, electricity is produced by generators, the largest of which are National Power, PowerGen, Eastern Electricity 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. The majority of customers are supplied with electricity by their local REC, although there are other suppliers holding second tier supply licenses, including generators and RECs, who can compete to supply customers in that REC's authorized area. During the fourth quarter of 1998, the market for supplying electricity began to be opened to competition through a phased-in program. This program, which proceeded by geographic areas, was completed in 1999. Virtually all electricity generated in England and Wales is sold by generators and bought by suppliers through the Pool described below. 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 each month in the previous July to December period. The distribution price control formula also reflects an inflation factor ("Xd") which was established by the Regulator (and continues to be set) at 3%. 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 -8- from year to year. It is a control on revenue which operates independently of the REC's costs. During the lifetime of the price control additional cost savings therefore contribute directly to profit. In connection with the scheduled distribution price control review concluded by the Regulator in 1999, Northern's allowable distribution revenue is to be reduced by 24% with effect from April 1, 2000. As part of the review, the Xd factor was not modified and therefore remains at 3%. 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 in 2005. The formula may be further reviewed at other times in the discretion of the Regulator, including in the next several years in connection with certain government proposed regulatory incentive initiatives. 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: public electricity supply ('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. The price of electricity supplied by a PES to most of its domestic customers within its authorized area is controlled by a formula. As part of the scheduled review of the formula carried out by the Regulator in 1999, Northern will be required to reduce its prices to most of its domestic customers within its authorized area by about 11% from April 1, 2000. 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 supply 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 supply market demand is substantially hedged through various types of agreements including CFDs. -9- Northern's supply business generally involves entering into fixed price contracts to supply electricity to its customers. Northern obtains the electricity to satisfy its obligations under such contracts primarily by purchases from the Pool. Because the price of electricity purchased from the Pool varies, Northern is exposed to risk arising from differences between the fixed price at which it sells and the fluctuating prices at which it purchases electricity, unless it can effectively hedge such exposure. In addition, the United Kingdom government has announced plans to reform the wholesale trading market for electricity by eliminating the Pool and creating a bilateral wholesale trading market. The announced date for elimination of the Pool and the introduction of the New Electricity Trading Arrangements ("NETA") is October 31, 2000. Elimination of the Pool will create risks of a mismatch between the prices at which Northern purchases electricity from wholesale suppliers and the price at which it has, or will, contract to sell electricity to its customers. Northern's ability to manage such risks at acceptable levels will depend, in part, on the specifics of the supply contracts that Northern enters into, Northern's ability to implement and manage an appropriate contracting and hedging strategy, and the development of an adequate market for hedging instruments. Under NETA, suppliers will need to buy physical electricity from generators equal to the forecast demand of customers. NETA will create additional risks and opportunities and in order to mitigate them, Northern is developing a new suite of information technology systems in coordination with industry leading software development companies. The UK government has recently introduced into Parliament legislation which, if enacted, will facilitate certain aspects of the reform of the wholesale electricity trading market described above, and reform UK utility law in connection with the licensing regime for electricity and gas utilities, electricity and gas regulatory institutions and procedures, and social, consumer and environmental protection related to utilities. The Company's Distribution and Supply Business - ---------------------------------------------- MidAmerican Energy Company MidAmerican Energy is the largest energy company headquartered in Iowa, with assets and 1999 revenues totaling $3.6 billion and $1.8 billion, respectively. MidAmerican Energy is primarily engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MidAmerican distributes electric energy at retail in Iowa, Illinois and South Dakota. It also distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 1999, MidAmerican Energy had 663,500 retail electric customers and 638,000 retail natural gas customers. In addition to retail sales, MidAmerican Energy delivers electricity to other utilities, marketers and municipalities that distribute it to end-use customers (sales for resale or off-system sales) and transports natural gas, for a fee, through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. MidAmerican Energy's regulated electric and gas operations are conducted under franchises, certificates, permits and licenses obtained from state and local authorities. The franchises, with various expiration dates, are typically for 25-year terms. MidAmerican Energy has a residential, agricultural, commercial and diversified industrial customer group, in which no single industry or customer accounted for more than 5% of its total 1999 electric operating revenues or 3% of its total 1999 gas operating margin. Among the primary industries served by MidAmerican Energy are those which are concerned with the manufacturing, processing and fabrication of primary metals, real estate, food products, farm and other non-electrical machinery, and cement and gypsum products. For the year ended December 31, 1999, MidAmerican Energy derived approximately 66% of its gross operating revenues from its regulated electric business, and 25% from its regulated gas business and 9% from its nonregulated business activities. For 1998 and 1997, the corresponding percentages were 69% electric, 25% gas and 6% nonregulated; and 65% electric and 31% gas and 4% nonregulated, respectively. -10- The electric utility industry continues to undergo regulatory change. Traditionally, prices charged by electric utility companies have been regulated by federal and state commissions and have been based on cost of service. In recent years, changes have been occurring that move the electric utility industry toward a more competitive, market-based pricing environment. These changes will have a significant impact on the way MidAmerican Energy does business. A substantial majority of MidAmerican Energy's business still operates in a rate-regulated environment and, accordingly, many decisions for obtaining and using resources are evaluated from an electric and gas regulated business perspective. MidAmerican Energy also manages its operations as four distinct business units: generation, transmission, energy distribution and retail. It is under this framework that MidAmerican Energy believes it can best prepare for, and succeed in, the energy business of the future. With these four business units, MidAmerican Energy is able to focus on the specific needs and anticipated risks and opportunities of its major businesses. Certain administrative functions are handled by a corporate services group that supports all of the business units. Although specific functions may be moved between business units as future circumstances warrant, the main focus of each business unit has been established. Presently, significant functions of the generation business unit include the production of electricity, the purchase of electricity and natural gas, and the sale of wholesale electricity and natural gas. The transmission business unit coordinates all activities related to MidAmerican Energy's electric transmission facilities, including monitoring access to and assuring the reliability of the transmission system. The energy distribution business unit distributes electricity and natural gas to end-users and conducts related activities. Retail includes marketing, customer service and related functions for core and complementary products and services. Total Electric Sales of MidAmerican Energy By Customer Class 1999 1998 1997 Residential 21.0% 22.2% 20.9% Small General Service 16.7 17.5 16.5 Large General Service 26.9 28.1 27.4 Other 4.5 4.4 4.4 Sales for Resale 30.9 27.8 30.8 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== ===== -11- Retail Electric Sales of MidAmerican Energy By State 1999 1998 1997 Iowa 88.9% 88.4% 88.6% Illinois 10.4 10.9 10.7 South Dakota 0.7 0.7 0.7 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== ===== In an Iowa pricing settlement approved in 1997 by the Iowa Utilities Board, MidAmerican Energy was given permission to negotiate individual contracts with its industrial and commercial electric customers. The negotiated electric contracts have differing terms and conditions as well as prices. The contracts range in length from five to ten years, and some have price renegotiation and early termination provisions exercisable by either party. The vast majority of the contracts are for terms of seven years or less, although some large customers have agreed to 10-year contracts. Prices are set as fixed prices; however, many contracts allow for potential price adjustments with respect to environmental costs, government imposed public purpose programs, tax changes, and transition costs. While the contract prices are fixed (except for the potential adjustment elements), the costs MidAmerican Energy incurs to fulfill these contracts will vary. On an aggregate basis, the annual revenues under these contracts are approximately $180 million. In addition, MidAmerican Energy is precluded by the 1997 settlement agreement from filing for an increase in its Iowa electric rates prior to 2001, unless its annual return on common equity falls below 9%. Likewise, the other parties to the agreement are prohibited from seeking a reduction in MidAmerican Energy's electric rates prior to 2001, unless the return on common equity, adjusted for the equal sharing between shareholders and customers of earnings above a 12% return on common equity, exceeds 14%. Under a restructuring law enacted in 1997, a similar sharing mechanism is in place for Illinois operations. Two-year average returns on common equity greater than a two year average benchmark will trigger an equal sharing of earnings on the excess. The benchmark is a calculation of average 30-year Treasury Bond rates plus 5.5% for 1998 and 1999 and 8.5% for 2000 through 2004. The initial calculation, due March 31, 2000, will be based on 1998 and 1999 results. In Illinois beginning October 1, 1999, larger non-residential customers and 33% of the remaining non-residential customers are allowed to select their provider of electric supply services. All other non-residential customers will have supplier choice starting December 31, 2000. Residential customers all receive the opportunity to select their electric supplier on May 1, 2002. Historical gas sales, excluding transportation throughput, by customer class as a percent of total gas sales and by state as a percent of total retail gas sales are shown below: -12- Total Regulated Gas Sales of MidAmerican Energy By Customer Class 1999 1998 1997 Residential 62.0% 59.9% 60.8% Small General Service 31.4 32.1 33.1 Large General Service 3.9 3.7 4.2 Sales for Resale and Other 2.7 4.3 1.9 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== ===== Retail Gas Sales of MidAmerican Energy By State 1999 1998 1997 Iowa 78.8% 79.0% 79.1% Illinois 10.3 10.2 10.4 South Dakota 10.1 10.1 9.8 Nebraska 0.8 0.7 0.7 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== ===== There are seasonal variations in MidAmerican Energy's electric and gas businesses which are principally related to the use of energy for air conditioning and heating. In 1999, 39% of MidAmerican Energy's electric revenues were reported in the months of June, July, August and September, and 55% of MidAmerican Energy's gas revenues were reported in the months of January, February, March and December. The annual hourly peak demand on MidAmerican Energy's electric system occurs principally as a result of air conditioning use during the cooling season. In July 1999, MidAmerican Energy recorded an hourly peak demand of 3,833 MW, which is 190 MW more than MidAmerican Energy's previous record hourly peak of 3,643 MW set in 1998. MidAmerican Energy's accredited net generating capability in the summer of 1999 was 4,466 MW. Accredited net generating capability represents the amount of generation available to meet the requirements on MidAmerican Energy's energy system, net of the effect of capacity purchases and sales and consists of Company-owned generation and generation under a long-term power purchase contract. The net generating capability at any time may be less due to regulatory restrictions, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling or modifications. MidAmerican Energy is interconnected with certain Iowa utilities and utilities in neighboring states and is involved in an electric power pooling agreement known as Mid-Continent Area Power Pool "MAPP"). MAPP is a voluntary association of electric utilities doing business in Iowa, Minnesota, Nebraska and North Dakota and portions of Illinois, Montana, South Dakota and Wisconsin and the Canadian provinces of Saskatchewan and Manitoba. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP facilitates operation of the transmission system, serves as a power and energy market clearing house and is responsible for the safety and reliability of the bulk electric system. Each MAPP participant is required to maintain for emergency purposes a net generating capability reserve of at least 15% above its system peak demand. If a participant's capability reserve falls below the 15% minimum, significant penalties could be contractually imposed by MAPP. MidAmerican Energy's reserve margin for 1999 was approximately 16.5%. -13- Northern Electric Northern Electric Distribution Limited ("Northern Distribution"), a subsidiary of Northern, receives electricity from the national grid transmission system and distributes electricity to each of its authorized area 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 electricity can only be delivered to them 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, 1999, Northern's electricity distribution network (excluding service connections to consumers) included approximately 17,000 kilometers of overhead lines and approximately 27,000 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. Under the terms of its PES license, Northern currently supplies approximately 1.5 million supply customers within its authorized area. In addition to competing for supply customers in its authorized area, Northern holds a second tier license to compete with the RECs and other suppliers to provide electricity to supply customers outside its authorized area. Northern is one of the largest suppliers to major users 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. Total Electric Sales of Northern By Customer Class 1999 1998 1997 Residential 27.5% 32.4% 34.0% Small General Service 12.7 16.2 16.7 Large General Service 58.1 49.9 47.7 Sales for Resale and Other 1.7 1.5 1.6 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== ===== Northern Supply also competes to supply gas inside and outside its authorized area. At December 31, 1999, Northern supplied gas to approximately 567,000 customers. Total Gas Sales of Northern By Customer Class 1999 1998 1997 Residential 70.0% 45.5% 14.5% Commercial 30.0 54.5 85.5 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== ===== -14- Northern Utility Services Limited ("Northern Utility") is an engineering company whose role is to adapt, maintain and restore the distribution network of Northern 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 approximately 19% 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 has ownership interests in generating facilities with an aggregate of (i) 9,468 net MW in projects in operation representing an aggregate net capacity owned of 5,195 net MW of electric generating capacity, (ii) 746 net MW in four projects under construction representing an aggregate net capacity of 672 net MW owned electric generating capacity and (iii) 46 net MW in three projects in advanced development stages with signed power sales agreements or under award representing an aggregate net capacity owned of 45 net MW of electric generating capacity. -15- 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.
Facility Net Political Net MW Commercial U.S. $ Power Risk Project (1) MW Owned (2) Fuel Location Operation Payments Purchaser (3) Insurance ----------- -------- --------- ----- -------- ----------- -------- ------------- --------- Projects in Operation - --------------------- Council Bluffs Energy 131 131 Coal Iowa 1954, 1958 Yes MEC No Center units 1 & 2 Council Bluffs Energy 675 534 Coal Iowa 1978 Yes MEC No Louisa Generation Station 700 616 Coal Iowa 1983 Yes MEC No Neal Generation Station Units 1 & 2 435 435 Coal Iowa 1964, 1972 Yes MEC No Neal Generation Station Station Unit 3 515 371 Coal Iowa 1975 Yes MEC No Neal Generation Station Unit 4 624 253 Coal Iowa 1979 Yes MEC No Ottumwa Generation Station 716 372 Coal Iowa 1981 Yes MEC No Quad-Cities Power Station 1,529 382 Nuclear Illinois 1972 Yes MEC No Riverside Generation Station 135 135 Coal Iowa 1925-61 Yes MEC No Combustion Turbines 789 789 Gas Iowa 1969-95 Yes MEC No Moline Water Power 3 3 Hydro Illinois 1970 Yes MEC No Imperial Valley 268 134 Geo California 1986-96 Yes Edison No Saranac 240 90 Gas New York 1994 Yes NYSEG No Power Resources 200 100 Gas Texas 1988 Yes TUEC No Yuma 50 25 Gas Arizona 1994 Yes SDG&E No Roosevelt Hot Springs 23 17 Geo Utah 1984 Yes UP&L No Desert Peak 10 10 Geo Nevada 1985 Yes N/A No Mahanagdong 165 149 Geo Philippines 1997 Yes PNOC-EDC Yes Malitbog 216 216 Geo Philippines 1996-97 Yes PNOC-EDC Yes Upper Mahiao 119 119 Geo Philippines 1996 Yes PNOC-EDC Yes Teesside Power Ltd 1,875 289 Gas England 1993 No Various No Viking 50 25 Gas England 1998 No Northern No ----- ----- Total Projects in Operation 9,468 5,195 ===== =====
- ---------- (1) The Company operates all such projects other than Teesside Power Limited, Quad Cities Power Station, Ottumwa Generation Station and Desert Peak. (2) 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. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions. (3) PNOC-Energy Development Corporation ("PNOC-EDC"); Government of the Philippines ("GOP") and Philippine National Irrigation Administration ("NIA") (NIA also purchases water from this facility). The Government of the Philippines undertaking supports PNOC-EDC's and NIA's respective obligations. Southern California Edison Company ("Edison"); San Diego Gas & Electric Company ("SDG& E"); Utah Power & Light Company ("UP&L); Bonneville Power Administration ("BPA"); New York State Electric & Gas Corporation ("NYSEG"); Texas Utilities Electric Company ("TUEC"); Northern Electric plc ("Northern"); Zinc Recovery Project ("Zinc") and MidAmerican Energy Company ("MEC"). -16-
Facility Net Political Net MW Commercial U.S. $ Power Risk Project (1) MW Owned (2) Fuel Location Operation Payments Purchaser (3) Insurance - ----------- -------- --------- ----- -------- ----------- -------- ------------- --------- Projects Under Construction - --------------------------- Casecnan 150 105 Hydro Philippines 2001 Yes NIA GOP Yes Salton Sea V 49 25 Geo California 2000 Yes Zinc/TBD No CE Turbo 10 5 Geo California 2000 Yes Zinc/TBD No Cordova 537 537 Gas Illinois 2001 Yes TBD No ------ ----- Total Projects Under Construction 746 672 ------ ----- Development Projects (4) - ------------------------ Telephone Flat 44 44 Geo California 2001 Yes BPA No Kirkheaton Wind Ltd. 2 1 Wind England 2000 No Northern No ------ ----- Total Development Projects 46 45 ------ ----- Total Power Generation Projects 10,260 5,912 ====== =====
(1) The Company operates all such projects other than Teesside Power Limited, Quad Cities Power Station, Ottumwa Generation Station and Desert Peak. (2) 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. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions. (3) PNOC-Energy Development Corporation ("PNOC-EDC"); Government of the Philippines ("GOP") and Philippine National Irrigation Administration ("NIA") (NIA also purchases water from this facility). The Government of the Philippines undertaking supports PNOC-EDC's and NIA's respective obligations. Southern California Edison Company ("Edison"); San Diego Gas & Electric Company ("SDG& E"); Utah Power & Light Company ("UP&L); Bonneville Power Administration ("BPA"); New York State Electric & Gas Corporation ("NYSEG"); Texas Utilities Electric Company ("TUEC"); Northern Electric plc ("Northern"); Zinc Recovery Project ("Zinc") and MidAmerican Energy Company ("MEC"). (4) Significant contingencies exist in respect of development projects, including without limitation, the need to obtain financing, permits and licenses, and the completion of construction. The Company is also pursuing a number of other power projects that are in more preliminary stages of development. PROJECTS IN OPERATION - --------------------- UNITED STATES POWER GENERATION MIDAMERICAN ENERGY GENERATION FACILITIES All of the coal-fired generating stations operated by MidAmerican Energy are fueled primarily by low-sulfur, western coal from the Powder River Basin and Hanna Basin mines. The use of low-sulfur western coal enables MidAmerican Energy to comply with the acid rain provisions of the Clean Air Act Amendments ("CAAA") without having to install additional costly emissions control equipment at its generating stations. MidAmerican Energy's coal supply portfolio includes multiple suppliers and mines under agreements of varying term and quantity flexibility. MidAmerican Energy regularly monitors the western coal market, looking for opportunities to improve its coal supply portfolio. MidAmerican Energy believes its sources of coal supply are and will continue to be satisfactory. -17- MidAmerican Energy uses both the Union Pacific Railroad ("UP") and the Burlington Northern and Santa Fe Railway ("BNSF") as originating carriers of its coal supply. Coal is delivered directly to MidAmerican Energy's Neal Energy Center by the UP and to Council Bluffs Energy Center ("CBEC") by the UP and the BNSF. Coal for MidAmerican Energy's Louisa and Riverside Energy Centers is delivered to an interchange point by the BNSF for transportation to its destination by the I&M Rail Link. Competitive rail access is available to CBEC and to interchange points for deliveries to Louisa and Riverside Energy Centers. MidAmerican Energy believes its coal transportation arrangements are adequate to meet its coal delivery needs. MidAmerican Energy uses natural gas and oil as fuel for peak demand electric generation, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy's needs. MidAmerican Energy is a 25% joint owner of Quad Cities Nuclear Power Station. MidAmerican Energy has been advised by Commonwealth Edison ("ComEd"), the joint owner and operator of Quad Cities Station, that the majority of its uranium concentrate and uranium conversion requirements for Quad Cities Station through 2001 can be met under existing supplies or commitments. ComEd foresees no problem in obtaining the remaining requirements now or obtaining future requirements. ComEd further advises that all enrichment requirements have been contracted through 2003. Commitments for fuel fabrication have been obtained at least through 2005. ComEd does not anticipate that it will have difficulty in contracting for uranium concentrates for conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station. CE Generation Geothermal Facilities CE Generation LLC ("CE Generation"), a 50% owned subsidiary of the Company, affiliates currently operate eight geothermal plants in the Imperial Valley in California (the "Imperial Valley Project"). Four of these Imperial Valley Project plants (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") consist of Salton Sea I, II, III and IV projects. (the "Salton Sea I Project" the "Salton Sea II Project, the "Salton Sea III Project and the "Salton Sea IV Project", respectively). Vulcan. The Vulcan Project sells electricity to Southern California Edison Company ("Edison") under a 30-year Standard Offer No. 4 Agreement ("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 expired on January 1, 1999. Thereafter, the energy payments are based on Edison's Avoided Cost of Energy. 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 expired on December 31, 1998. Thereafter, the energy payments are based on Edison's Avoided Cost of Energy. -18- 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 expired 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 that is currently $132.58 per kW-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 cents 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 1999. 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 expired on February 12, 1999, were levelized at a time period weighted average of 9.8 cents per kWh. Thereafter, the monthly energy payments are Edison's Avoided Cost of Energy. Salton Sea IV Project. 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 I PPA option (20 MW) and to the original Salton Sea IV SO4 Agreement ("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. CE Generation Gas Facilities CE Generation affiliates currently operate the Saranac, Power Resources and Yuma natural gas plants (the "Saranac Project", "Power Resources Project" and "Yuma Project", respectively) and previously operated the NorCon natural gas plant (the "NorCon Project"). (The Saranac Project, Power Resources Project, Yuma Project and NorCon Project are collectively referred to as the "Gas Plants"). -19- 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 ("Yuma PPA"). 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 Yuma PPA. The power is wheeled to SDG&E over transmission lines constructed and owned by Arizona Public Service Company ("APS"). The Yuma Project commenced commercial operation in May 1994. The project entity, Yuma Cogeneration Associates ("YCA"), 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 qualifying facility ("QF") and as PURPA. However, if the industrial entity terminates the agreement, YCA 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 YCA and Southwest Gas Corporation. Saranac Project. The Saranac Project is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York, which began commercial operation in June 1994. The Saranac Project has entered into a 15-year power purchase agreement (the "Saranac PPA") with New York State Electric & Gas ("NYSEG"). The Saranac Project 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. The Saranac Project has a 15-year natural gas supply contract (the "Saranac Gas Supply Agreement") with Shell Canada Limited ("Shell Canada") to supply 100% of the Saranac Project'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 the Saranac Project. 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 indirectly owned by subsidiaries of CE Generation, Tomen Corporation ("Tomen") and General Electric Capital Corporation ("GECC"). 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 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. -20- The Saranac Partnership and other parties have filed motions to dismiss and oral arguments on those motions were heard on March 2, 1998 and again on March 3, 1999. The Saranac Partnership believes that NYSEG's claims are without merit for the same reasons described in the FERC's orders. Power Resources Project. The Power Resources Project 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. The Power Resources Project began commercial operation in June 1988. The Power Resources Project is a QF and the project entity, Power Resources Ltd. ("Power Resources"), 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 "CE Texas Gas Supply Agreement") with CE Texas Gas L.P. ("CE Texas Gas") for Power Resources' fuel requirements through December 2003. In June 1995, CE Texas Gas and Louis Dreyfus Natural Gas Corp. ("Dreyfus") executed an eight-year natural gas supply agreement (the "CE Texas Gas-Dreyfus Gas Supply Agreement"), with which CE Texas Gas will fulfill its supply commitment to Power Resources from October 1995 to the end of the term of the Power Resources PPA. Each of the Power Resources PPA, the Power Resources Steam Purchase Agreement and the CE Texas Gas Gas Supply Agreement contains rates that are fixed for the respective contract terms. Revenues escalate at a higher rate than fuel costs. NorCon Project. The NorCon Project is an 80 net MW natural gas-fired cogeneration facility located in North East, Pennsylvania which began commercial operation in December 1992. The NorCon Project had a 25-year power purchase agreement (the "NorCon PPA") with Niagara Mohawk Power Corporation ("NIMO"). On December 2, 1999, the NorCon Project was transferred to GECC and the NorCon PPA was terminated. The Company no longer retains an interest in the NorCon Project. Other U.S. Geothermal Interests Roosevelt Hot Springs. A subsidiary of 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. A subsidiary of the Company is the owner of a 10 net MW geothermal plant at Sparks, Nevada. In 1998, the Company executed an agreement pursuant to which the Desert Peak Project is leased to a third party power producer and the Company receives rental payments. United Kingdom Power Generation 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) and its operation and ownership of Viking (described herein). Northern Generation also owns and operates a 5 MW diesel power generating plant located in Northallerton, England. 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. Northern owns 50% of this 50MW gas fired mid merit power plant located on Teesside. The plant is currently in the commissioning stage, however due to combustor issues it is unlikely to pass the performance criteria required for handover until 2001. NEGL is being held financially whole by the turnkey contractor (Rolls Royce) until the plant is fit for purpose at which time the plant will be operated by NEGL. The plant will be used as part of -21- Northern's strategy to hedge the purchases and sales of electricity and gas, together with obtaining the benefits of avoided charges together with sales premiums. The Philippines Power Generation Upper Mahiao. The Upper Mahiao facility is a 119 net MW geothermal power project owned and operated by CE Cebu Geothermal Power Company, Inc. ("CE Cebu"), a Philippine corporation that is 100% indirectly owned by the Company. The Upper Mahiao facility has been in commercial operation since June 17, 1996. Upon completion of the transmission line, the construction loan was converted to a term loan in May 1998. Export-Import Bank of the United States ("Ex-Im Bank") and United Coconut Planters Bank of the Philippines are providing the term loans. Under the terms of an energy conversion agreement, executed on September 6, 1993 (the "Upper Mahiao ECA"), CE Cebu owns and operates the Upper Mahiao Project during the ten-year cooperation period, which commenced in June, 1996 after which ownership will be transferred to PNOC-Energy Development Corporaiton ("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 (e.g., war, nationalization, etc.). In addition, PNOC-EDC must continue to make Capacity Fee payments if there is a force majeure event 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 of which 100% of the common stock is indirectly owned by the Company. Another industrial company owns an approximate 10% preferred equity interest in the project. The Mahanagdong Project has been in commercial operation since July 25, 1997, although its output was constrained until early 1998 because the required full transmission line was not completed until that time. The Mahanagdong Project sells 100% of its capacity on a similar basis as described above for the Upper Mahiao Project to PNOC-EDC, which in turn sells the power to NPC for distribution to the island of Luzon. During -22- the period of constrained operation, PNOC-EDC was required to, and paid all capacity fees under the take or pay provisions of the contract. Upon completion of the transmission line, the construction loan was converted to a term loan in June 1998. The project financing term loan is being provided by OPIC and Ex-Im Bank. 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 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 put into commercial operation on July 25, 1996 (for Unit I) and July 25, 1997 (for Units II and III), although as with the Upper Mahiao and Mahanagdong projects, operation was constrained due to a lack of the necessary transmission line. VGPC is selling 100% of its capacity on substantially the same basis as described above for the Upper Mahiao Project to PNOC-EDC, which sells the power to NPC. Upon completion of the transmission line, the construction loan was converted to a term loan in April 1998. A consortium of international banks and OPIC are providing the term loan facilities. 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 thenet 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. -23- Projects in Construction - ------------------------ United States Zinc Recovery Project. 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 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. CalEnergy Minerals LLC ("Minerals LLC"), an indirect wholly-owned subsidiary of the Company, is constructing the Zinc Recovery Project which will recover zinc from the geothermal brine (the "Zinc Recovery Project"). Four facilities will be installed near Imperial Valley Project sites to extract a zinc chloride solution from the brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tonnes per year and is scheduled to commence commercial operation in mid-2000. In September 1999, Minerals LLC entered into a sales agreement whereby all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The initial term of the agreement expires in December 2005. The Zinc Recovery Project is being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procurement and construction contract (the "Zinc Recovery Project EPC Contract"). Kvaerner is a wholly-owned indirect subsidiary of Kvaerner ASA, an internationally recognized engineering and construction firm experienced in the metals, mining and processing industries. The payment obligations of Kvaerner, including payment of liquidated damages of up to 20% of the contract price for certain delays or failures to meet performance guarantees, are secured by a letter of credit issued by Union Europeenne de CIC (or another financial institution rated "A" or better by S&P or "A2" or better by Moody's and otherwise acceptable to Minerals LLC) in an initial aggregate amount equal to $29.6 million. The Zinc Recovery Project is scheduled to commence initial operations in mid-2000. Salton Sea V. Salton Sea Power LLC, an indirect wholly owned subsidiary of CE Generation, is constructing the Salton Sea V Project. The Salton Sea V Project is a 49 net MW geothermal power plant which will sell approximately one-third of its net output to the Zinc Recovery Project. The remainder will be sold through the California Power Exchange ("PX") or other market transactions. The Salton Sea V Project is being constructed pursuant to a date certain, fixed price, turnkey engineering, procurement and construction contract (the "Salton Sea V EPC Contract") by Stone & Webster Engineering Corporation ("SWEC"). The Salton Sea V Project is schedule to commence commercial operation in mid-2000. CE Turbo. CE Turbo LLC, an indirect wholly-owned subsidiary of CE Generation, is constructing the CE Turbo Project. The CE Turbo Project will have a capacity of 10 net MW. The net output of the CE Turbo Project will be sold to the Zinc Recovery Project or sold through the PX or other market transactions. In addition to the CE Turbo Project, the Partnership Projects are constructing an upgrade to the geothermal brine processing facilities at the Vulcan and Del Ranch Projects to incorporate the pH Modification Process, which has reduced operating costs at the Imperial Valley Project. The CE Turbo Project and the brine facilities construction are being constructed by SWEC pursuant to a date certain, fixed price, turnkey engineering, procurement and construction contract (the "Region 2 Upgrade EPC Contract"). The CE Turbo Project is scheduled to commence initial operations in mid-2000 and the Region 2 Brine Facilities Construction is scheduled to be completed in mid-2000. Cordova. Cordova Energy Company LLC ("Cordova Energy"), a wholly owned subsidiary of the Company, financed and commenced construction of a 537 MW gas fired combined cycle merchant power plant to be located northeast of the Quad Cities in Cordova, Illinois. The Cordova Project is being constructed by SWEC pursuant to a date certain, fixed price, turnkey engineering, procurement and construction contract. Cordova is scheduled to commence commercial operation in mid-2001. -24- Philippines 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 Taan (Denip) Rivers that will divert water into a tunnel of approximately 23 kilometers. The tunnel will transfer the water from the Casecnan and Taan (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 expected to be at least 70% indirectly owned 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 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. CE Casecnan entered into a fixed price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Casecnan Construction Contract"). The work under the Casecnan Construction Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. On November 20, 1999, the Casecnan Construction Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. Accordingly, the Casecnan Project is now expected to become operational by the second quarter of 2001. -25- Under the Project Agreement, if NIA has completed certain work on its irrigation system, CE Casecnan is liable to pay NIA $5,000 per day for each day of delay in completion of the Casecnan Project beyond July 27, 2000, increasing to $13,500 per day for each day of delay in completion beyond November 27, 2000. CE Casecnan's ability to make payments on any of its existing and future obligations is dependent on NIA's and the Republic of the Philippines' performance of their obligations under the Project Agreement and the Performance Undertaking, respectively. No shareholders, partners or affiliates of CE Casecnan, including the Company, and no directors, officers or employees of the Company will guarantee or be in any way liable for payment of CE Casecnan's obligations. As a result, payment of CE Casecnan's obligations depends upon the availability of sufficient revenues from CE Casecnan's business after the payment of operating expenses. NIA's payments of obligations under the Project Agreement are substantially denominated in United States dollars and are expected to be CE Casecnan's sole source of operating revenues. Because of CE Casecnan's dependence on NIA, any material failure of NIA to fulfill its obligations under the Project Agreement and any material failure of the Republic of the Philippines to fulfill its obligations under the Performance Undertaking would significantly impair the ability of CE Casecnan to meet its existing and future obligations. United Kingdom Northern Generation owns 75% of a 1.8 MW wind farm currently under construction near Kirkheaton, Northumberland. The project is being built by Nordex Gmbh of Germany, and has a total cost of approximately 1.5 million pounds sterling. The project is scheduled for commercial operation in the second quarter of 2000. 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 Company's Report on Form 8-K dated March 26, 1999, incorporated herein by reference. United States Salton Sea Minerals Extraction. In addition to zinc recovery, 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 for the other products, 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. The Company is developing a 48 net MW geothermal project at Telephone Flat in Northern California where the Company has two successful production wells (the "Telephone Flat Project"). Under an amended contract arrangement with the Bonneville Power Administration ("BPA"), BPA will purchase 30 MW from the project and has an option to purchase an additional 100 MW. The completion of the project and BPA's purchase obligation are subject to obtaining a final environmental impact statement. United Kingdom The Company, through Northern Generation, is pursuing a number of project opportunities including several small embedded combined heat and power and peaking facilities, (totaling up to 80 MW) to provide electricity to suppliers on a local basis across Southern England. In addition, a larger 100 MW combined heat and power project is under development in Southern England with an industrial host. This project is processing through the later stages of government review and approval. -26- The gas moratorium in the U.K. has significantly adversely impacted the ability to develop gas-fired plants in the U.K. Producing Gas Field Operations and Fields in Development - -------------------------------------------------------- CalEnergy Gas (UK) Limited. CalEnergy 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, the EP389 (Gingin) concession in the Perth Basin in Australia and the Yolla discovery in the Bass Basin of Australia. PRODUCING GAS FIELDS SHARE OF CURRENT LOCATION REMAINING % WORKING RESERVES INTEREST BCF(1) Windermere 8.7 20.000% U.K. Offshore (North Sea) Victor 8.6 5.000% U.K. Offshore (North Sea) Schooner 7.4 2.070% U.K. Offshore (North Sea) Johnston 32.9 22.113% U.K. Offshore (North Sea) Anglia 82.7 67.198% U.K. Offshore (North Sea) FIELDS IN DEVELOPMENT Size Km2 Pila Area Concession 13,000(2) 100.000% N.W. Poland (Polish Trough) EP389 (Gingin) 2,960 40.789% S.W. Australia Onshore (Perth Basin) Yolla Discovery 550 20.000 S.E. Australia Offshore (Bass Basin) - --------------------------- (1) Gas reserves in Billion cubic feet (or "Bcf") as of December 31, 1999. 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) Subject to 25% relinquishment of the original area after every 2 years during the 8 year contract term based on work program results. Producing Fields Windermere Field. 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 8.7 bcf net to CE Gas. The field is produced by an unmanned platform that 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 that commenced production in April 1997 and currently has average net production of 6.52 MM scfd (million standard cubic feet per day). Gas is sold to N.V. Nederlandse Gasunie. Victor Field. 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 remaining reserves of 8.6 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 -27- 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 production of 4.7 MM scfd and sells its gas to British Gas Trading Limited. CE Gas holds a 5% working interest in this field. Schooner Field. The Schooner Field is located in the Northern part of the Southern North Sea and has remaining net reserves of 7.4 bcf. The field is produced by an unmanned platform which is tied back through an 18 mile 16" flowline to the Murdoch platform. Production is achieved from seven wells. 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 production of 2.47 MMscfd. The CE Gas share of the gas is sold to Northern. Johnston Field. The Johnston gas field is located in the Northern part of the Southern North Sea approximately 56 miles north east of Scarborough on the U.K. coast and has remaining reserves of 32.9 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. The current average net production rate is 11.7 MMscfd. Gas is sold to TXU Europe Upstream Limited. CE Gas has a 22.113% working interest in this field following the outcome of an equity redefinition process during 1999. CE Gas previously had an 18.264% working interest in the field. Anglia Field. During 1999, CE Gas acquired a 67.198% interest in the Anglia Field from Ranger Oil (U.K.) Ltd. and Ranger Oil (PC) Ltd. Following the acquisition, CE Gas took over the role of operator of the field. The Anglia Field is located in the central part of the Southern North Sea, approximately 65 miles east of the Theddlethorpe terminal on the U.K. coast, and has remaining reserves of 82.7 Bcf net to CE Gas. Anglia is produced via an unmanned platform which has six production wells, and a further two subsea production wells are tied back to the platform via an 8" pipeline. The gas is exported via a 12" pipeline to the LOGGS platform and then onwards to the Theddlethorpe shore terminal. The Anglia Field has been on production since October 1992 and currently has an average production of 31.5 MM/scfd net to CE Gas. CE Gas sells the gas to National Power and Northern. Projects in Development Pila Concession. Following the execution of a Mining Usufruct Agreement in 1997 with the Polish government, CE Gas was awarded an eight year exploration and exploitation agreement in April 1998 providing it with the exclusive right (a 100% working interest) to explore and 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 program (now completed) and drilling work program within the concession over that period, subject to relinquishment of up to 25% of the concession area after every two years. Only developed areas can 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. EP389 (Gingin) Concession. In August 1997, CE Gas signed an earn-in agreement with Empire Oil of Australia, the permit holder for various concession areas in the Perth Basin in Western Australia. Under the agreement, CE Gas has now earned a 40.789% working interest in the main concession area and a 33% working interest in four ancillary concession areas. Given the advantages of the location of the Gingin concession, in close proximity to an industrial area and electric residential load center, the Company believes that the Gingin concession 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 in Western Australia. 95% of all gas to SW Australia is currently supplied from the NW shelf (Dampier to Bunbury pipeline--1500km). The 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. -28- Yolla Gas Discovery. The Yolla gas field was discovered in 1985 and is located offshore, approximately 120 kilometers from the coast of Tasmania and 200 kilometers from the coast of Victoria in Australia. In 1998, CE Gas entered into an option agreement with Boral Energy Resources Limited and Premier Petroleum (Australia) Limited to earn interests in three permits in the Bass Basin located in the south east of Australia, including the Yolla gas discovery. A successful appraisal well was drilled in 1999. CE Gas' net remaining reserves are estimated at approximately 70 Bcf. The Yolla partners are currently reviewing the development options for the field. 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. Other - ----- HomeServices The Company owns approximately 65% of HomeServices.Com Inc. ("HomeServices"), the second largest residential real estate brokerage firm in the United States based on aggregate closed transaction sides in 1998 for its various brokerage firm operating subsidiaries. Closed transaction sides mean either the buy side or sell side of any closed home purchase and is the standard term used by industry participants and publications to rank real estate brokerage firms. In addition to providing traditional residential real estate brokerage services, HomeServices cross sells to its existing real estate customers preclosing services, such as mortgage origination and title services, including title insurance, title search, escrow and other closing administrative services, assists in securing other preclosing and postclosing services provided by third parties, such as home warranty, home inspection, home security, property and casualty insurance, home maintenance, repair and remodeling and is developing various related e-commerce services. HomeServices currently operates primarily under the Edina Realty, Iowa Realty, J.C. Nichols Residential, CBSHOME, Paul Semonin Realtors, Long Realty and Champion Realty brand names in the following twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota and South Dakota. HomeServices occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides for the year ended December 31, 1998. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Omaha, Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson, Arizona and Annapolis, Maryland. Indonesia On December 2, 1994, subsidiaries of the Company, Himpurna California Energy Ltd., ("HCE") and Patuha Power, Ltd. ("PPL", together with HCE, the "Indonesian Subsidiaries") executed separate joint operation contracts for the development of the geothermal steam field and geothermal power facilities located in Central Java in Indonesia with Perusahaan Pertambangam Minyak Dan Gas Cumi Negara ("Pertamina"), the Indonesian national oil company, and executed separate "take-or-pay" energy sales contracts with both Pertamina and P.T. PLN (Persero) ("PLN"), the Indonesian national electric utility. The Republic of Indonesia ("ROI") provided sovereign guarantees of the obligations under the "take-or-pay" contracts. HCE's Dieng Unit I was operationally and contractually completed in March 1998 when the "take-or-pay" obligations under its contract with PLN commenced. However, PLN defaulted on the contractually required and sovereign guaranteed "take-or-pay" payment obligations. The Indonesian Subsidiaries in 1998 initiated dispute resolution procedures under the ESCs and the sovereign guarantees with PLN and the Republic of Indonesia and subsequently commenced arbitration to resolve the dispute. The arbitration before an international arbitration panel was concluded in 1999 and found that the ROI had materially breached the contract obligations and sovereign guarantees and violated international law. The final arbitration awards directed the ROI to pay HCE $393.4 million and PPL $182.2 million. -29- When the ROI failed to pay the arbitration awards, the Company filed claims with OPIC, an agency of the U.S. Government, and Lloyds private market insurers pursuant to certain insurance that covered political risks relating to the projects. In 1999, the Company received payment of the claims filed with OPIC and Lloyds totaling $290 million and assigned the Indonesia Subsidiaries (including the arbitration award) to OPIC. 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 operating domestic power facilities partially owned through CE Generation 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. -30- CAAA was signed into law in November 1990. Essentially all utility generating units are subject to the provisions of the CAAA which address continuous emissions monitoring, permit requirement and fees and emissions of certain substances. MidAmerican Energy has five jointly owned and six wholly owned coal-fired generating units, which represent approximately 65% of MidAmerican Energy's electric generating capability. MidAmerican Energy's generating units meet all Title IV CAAA requirements through 2007. Title IV of the CAAA, which is also known as the Acid Rain Program, sets forth requirements for the emission of sulfur dioxide and nitrogen oxides at electric utility generating stations. State and federal environmental laws and regulations currently have, and future modifications may have, the effect of (i) increasing the lead time for the construction of new facilities, (ii) significantly increasing the total cost of new facilities, (iii) requiring modification of certain of the Company's existing facilities, (iv) increasing the risk of delay on construction projects, (v) increasing the Company's cost of waste disposal and (vi) possibly reducing the reliability of service provided by the Company and the amount of energy available from the Company's facilities. Any of such items could have a substantial impact on amounts required to be expended by the Company in the future. 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 of 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. The UK government has recently introduced into Parliament legislation which, if enacted, will facilitate certain aspects of the reform of the wholesale electricity trading market described above, and reform UK utility law in -31- connection with the licensing regime for electricity and gas utilities, electricity and gas regulatory institutions and procedures, and social, consumer and environmental protection related to utilities. Employees - --------- At December 31, 1999, the Company and its subsidiaries employed approximately 9,700 people. Neither the Gas Projects nor the Imperial Valley Project entities hire or retain any employees. All employees necessary to operate the Gas Projects and Imperial Valley Projects are provided by affiliates of the Company under certain administrative services and operation and maintenance agreements. International development activities in 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 Philippine affiliates currently maintain offices in Manila. Of Northern's employees, at December 31, 1999, approximately 75% 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. Of MidAmerican Energy's employees, approximately one half are represented by labor unions. MidAmerican Energy believes that its relations with its employees are good. As of December 31, 1999, HomeServices employed approximately 1,575 individuals and had approximately 6,350 sales associates, who are independent contractors and not employees. None of HomeServices' employees or sales associates is covered by a collective bargaining agreement. Management believes that HomeServices' relations with its employees and sales associates are good. ITEM 2. PROPERTIES Property. Northern owns the freehold of its principal executive offices in Newcastle upon Tyne, England. Northern has both network and non-network land and buildings. At December 31, 1999, Northern had freehold and leasehold interests in approximately 8,500 network properties, comprising principally sub-station sites. The recorded historical cost account net book value of total network land and buildings at December 31, 1999 was pounds sterling 25.9 million. Northern owns, directly or indirectly, the freehold or leasehold interests of such land and buildings. At December 31, 1999, Northern had freehold and leasehold interests in approximately 78 non-network properties comprising chiefly offices, retail outlets, depots, warehouses and workshops. The recorded historical cost account net book value of total non-network land and buildings at December 31, 1999 was 17.5 million pounds sterling. MidAmerican Energy's utility properties consist of physical assets necessary and appropriate to render electric and gas service in its service territories. Electric property consists primarily of generation, transmission and distribution facilities. Gas property consists primarily of distribution plant, including feeder lines to communities served from natural gas pipelines owned by others. It is the opinion of management that the principal depreciable properties owned by MidAmerican Energy are in good operating condition and well maintained. The electric transmission system of MidAmerican Energy at December 31, 1999, included 897 miles of 345-kV lines, 1,299 miles of 161-kV lines, 1,806 miles of 69-kV lines and 219 miles of 34.5-kV lines. The gas distribution facilities of MidAmerican Energy at December 31, 1999, included 19,907 miles of gas mains and services. Substantially all the former Iowa-Illinois Gas and Electric Company (predecessor to MidAmerican Energy) utility property and franchises, and substantially all of the former Midwest Power Systems Inc. (predecessor to MidAmerican Energy) electric utility property located in Iowa, or approximately 80% of gross utility plant, is pledged to secure mortgage bonds. The Company's most significant physical properties, other than those owned by Northern and MidAmerican Energy, are its current interest in operating power facilities, its plants under construction and related real property interests. -32- The Company also maintains an inventory of approximately 150,000 acres of geothermal property leases. Certain of the producing acreage owned by Magma is leased to unaffiliated power 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. The Company leases its principal executive offices and its offices in Manila. 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. HomeServices' principal offices are located in Edina, Minnesota, where HomeServices leases approximately 46,000 square feet of office space. This lease expires in 2003. The rent under this lease is approximately $600,000 per year. In addition, HomeServices has a total of 160 branch offices, substantially all of which are leased. HomeServices' office leases generally have initial terms ranging from three to ten years, with an option to extend the lease for additional periods. The leases are typically net leases, which means that HomeServices is required to pay property taxes, utilities and maintenance. HomeServices believes that its present facilities are adequate for its current level of operations. 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 and utility subsidiaries are parties to litigation or other disputes. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Not applicable. -33- PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER'S MATTERS As of March 14, 2000, the Company's equity securities are owned by the members of the Investor Group and are not registered with the Securities and Exchange Commission pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. ITEM 6. SELECTED FINANCIAL DATA Reference is made to Part IV of this report. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Reference is made to Part IV of this report. ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK Reference is made to Part IV of this report. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Reference is made to Part IV of this report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. -34- PART III MANAGEMENT ITEM 10. DIRECTORS, EXECUTIVE AND OTHER OFFICERS OF THE COMPANY AND SIGNIFICAN SUBSIDIARIES The Company's management structure is organized functionally and the current executive and other officers of the Company and their positions are as follows: Name Position Company David L. Sokol Chairman of the Board and Chief Executive Officer MEHC, MEC, Northern Gregory E. Abel President and Chief Operating Officer MEHC, Northern Patrick J. Goodman Senior Vice President and Chief Financial Officer MEHC, MEC Steven A. McArthur Senior Vice President, Mergers and Acquisitions and Secretary MEHC, MEC John A. Rasmussen Jr. Senior Vice President and General Counsel MEHC, MEC Keith D. Hartje Senior Vice President and Chief Administrative Officer MEHC, MEC Robert S. Silberman Senior Vice President and President, CalEnergy Generation MEHC Douglas L. Anderson Vice President, Assistant General Counsel and General Counsel, CalEnergy Generation MEHC Edward F. Bazemore Vice President, Human Resources/IPP MEHC, MEC James A. Flores Vice President, Project Finance MEHC Adrian M. Foley III Vice President, Marketing MEHC Brian K. Hankel Vice President and Treasurer MEHC, MEC Paul J. Leighton Vice President Corporate Law, Assistant General Counsel and Assistant Secretary MEHC, MEC Joseph M. Lillo Vice President and Controller MEHC James J. Sellner Director of Taxation, Corporate MEHC, MEC K. Taylor Smith Controller, Asian Operations MEHC Jonathan M. Weisgall Vice President, Federal Regulation MEHC, MEC Russell H. White Assistant Vice President, General Services MEHC, MEC Cathy S. Woollums Vice President, Environmental MEHC, MEC Ronald W. Stepien President MEC Jack L. Alexander Senior Vice President, Transmission and Energy Delivery MEC David C. Caris Vice President, State Government Affairs MEC Dean A. Crist Vice President, Generation MEC Steven J. Dust Vice President, Economic Development MEC Brent E. Gale Vice President, Legislation and Regulation MEC David L. Graham Vice President, Customer Service MEC James J. Howard Vice President, Regulatory Affairs MEC Todd M. Raba Vice President, Retail Business Unit MEC Mark W. Roberts Vice President, Energy Trading and Planning MEC Thomas B. Specketer Vice President & Controller MEC Steven R. Weiss Assistant General Counsel MEC P. Eric Connor President and Chief Operating Officer Northern Dave Crompton Managing Director, Retail Northern Dr. John M. France Director of Regulation Northern G. Valerie Giles Company Secretary Northern Mark Horsley Managing Director, Northern Utility Services Limited Northern Dr. Philip S. Lawless Managing Director, Generation Northern Ken Linge Director of Finance Northern -35- Neil Middleton Managing Director, Northern Electric Supply Limited Northern James D. Stallmeyer Vice President, Commercial Director and General Counsel Northern David Swan Distribution Director Northern David A. Waters Managing Director, Northern Electric Distribution Limited Northern Peter Youngs Managing Director, CalEnergy Gas (UK) Ltd. Northern Set forth below is certain information with respect to each of the foregoing officers: DAVID L. SOKOL, 43, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been CEO since April 19, 1993 and served as President of MEHC 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, 37, President and Chief Operating Officer. Mr. Abel joined the Company in 1992 and initially served as Vice President and Controller. 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. PATRICK J. GOODMAN, 33, Senior Vice President and Chief Financial Officer. Mr. Goodman joined the Company in 1995, and served in various accounting positions including Senior Vice President and Chief Accounting Officer. Prior to joining the Company, Mr. Goodman was a financial manager for National Indemnity Company and a senior associate at Coopers & Lybrand. STEVEN A. McARTHUR, 42, Senior Vice President, Mergers and Acquisitions and Secretary. Mr. McArthur joined the Company in February 1991 and has served in various executive capacities including General Counsel. 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. JOHN A. RASMUSSEN, JR., 54, Senior Vice President and General Counsel. Mr. Rasmussen has been Senior Vice President and General Counsel of MidAmerican Energy since November 1, 1996, and Group Vice President and General Counsel from July 1, 1995 to November 1, 1996. Prior to that he was Vice President and General Counsel of Midwest Power Systems, Inc., a predecessor company, from 1993 to 1995. KEITH D. HARTJE, 50, Senior Vice President and Chief Administrative Officer. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973. In that time, he has held a number of positions, including General Counsel and Corporate Secretary, District Vice President for southwest Iowa operations, and Vice President, Corporate Communications. ROBERT S. SILBERMAN, 42, Senior Vice President. 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. DOUGLAS L. ANDERSON, 42, Vice President and Assistant General Counsel. 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. Prior to that, Mr. Anderson was a principal in the firm Anderson & Anderson. -36- EDWARD F. BAZEMORE, 63, Vice President, Human Resources/IPP. 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. JAMES A. FLORES, 46, Vice President, Project Finance. Mr. Flores joined the Company 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, 53, 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 the Company, 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. BRIAN K. HANKEL, 37, 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. PAUL J. LEIGHTON, 46, Vice President, Corporate Law, Assistant General Counsel and Assistant Secretary. Mr. Leighton has served as Corporate Secretary for MidAmerican Energy and its predecessor companies since 1988 and as an attorney since 1978. JOSEPH M. LILLO, 30, Vice President and Controller. Mr. Lillo joined the Company in November 1996, and served as Manager of Financial Reporting and was promoted to Controller/IPP in March 1998. Mr. Lillo was promoted to Controller in July 1999. Prior to joining the Company, Mr. Lillo was a senior associate with Coopers & Lybrand LLP. JAMES J. SELLNER, 53, Director of Taxation. Mr. Sellner joined the Company in November, 1997. Prior to joining the Company, Mr. Sellner was employed by Central and South West Corporation and Banc One/MCorp. K. TAYLOR SMITH, 43, Controller, Asian Operations. Mr. Smith joined the Company in 1991. From 1986 to 1991 Mr. Smith was employed by Computer Technology Associates, Inc. with responsibilities including computer systems design and development, financial planning and management. JONATHAN M. WEISGALL, 51, Vice President, Federal Regulation/IPP. 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. RUSSELL H. WHITE, 53, Assistant Vice President, General Services. Mr. White was previously Manager, General Services. Mr. White joined the Company in 1988 as Manager, Asset Protection. CATHY WOOLLUMS, 39, Vice President, Environmental. Ms. Woollums was an Attorney for Iowa-Illinois Gas and Electric Company from 1991-1995. From 1995-1998, she was Manager, Environmental Services with MidAmerican Energy. RONALD W. STEPIEN, 53, President of MidAmerican Energy since November 1, 1998, Executive Vice President from November 1, 1996 to October 31, 1998, and Group Vice President from 1995 to November 1, 1996. Vice President of Iowa-Illinois Gas and Electric Company, a predecessor company, from 1990 to 1995. -37- JACK L. ALEXANDER, 52, Senior Vice President of MidAmerican Energy. Mr. Alexander has been Senior Vice President of MidAmerican Energy since November 1, 1998 and was a Vice President of MidAmerican Energy from November 1, 1996 to October 31, 1998, and held various executive and management positions with MidAmerican and Midwest Power Systems Inc., a predecessor company, for more than five years prior thereto. DAVE CARIS, 40, Vice President, State Government Affairs of MidAmerican Energy. Mr. Caris was Government Affairs Vice President for MidAmerican Energy from November 1, 1997 to March 19, 1999 and Manager of Government Affairs for Iowa-Illinois Gas & Electric Company, a predecessor company, from 1986-1995. DEAN A. CRIST, 44, Vice President, Generation of MidAmerican Energy. Mr. Crist has been in his present position since April 9, 1999 and was Generation Marketing Vice President of MidAmerican Energy from April 1, 1998 to April 9, 1999 and held various management positions with MidAmerican Energy and its predecessor companies for more than five years prior thereto. STEVEN J. DUST, 45, Vice President, Economic Development of MidAmerican Energy. Mr. Dust has been in his present position since February, 1999. Mr. Dust has over twenty year's experience in the economic development field and joined MidAmerican Energy as Manager of Economic Development in 1996. Prior to joining MidAmerican, Steve was a Principal of Septagon Industries, a Midwest firm with holdings in industrial construction, real estate development, manufacturing, and communications. BRENT E. GALE, 48, Vice President, Legislation and Regulation of MidAmerican Energy. Mr. Gale has previously held positions with MidAmerican Energy as Vice President - Regulatory Law and Analysis and Vice President - Law & Regulation. Prior to 1995, Mr. Gale was Vice President - General Counsel of Iowa-Illinois Gas and Electric Company, a predecessor company. DAVID L. GRAHAM, 54, Vice President, Customer Service, of MidAmerican Energy. Mr. Graham has been in his present position since December 1998 and was Sales Vice President from April 1998 to December 1998, and held various management positions with MidAmerican Energy and its predecessor companies for more than 30 years prior thereto. JAMES J. HOWARD, 57, Vice President, Regulatory Affairs of MidAmerican Energy. Mr. Howard has been Vice President, Regulatory Affairs since April, 1998. Previously he had been Vice President, Administrative Services since 1989. TODD M. RABA, 43, Vice President, Marketing and Sales. Mr. Raba has been in his present position since April 1999. He joined MidAmerican in December 1997 as Sales Vice President, responsible for Major Accounts. Prior to joining MidAmerican, Mr. Raba spent 13 years at Rollins Environmental Services, Inc., of Wilmington Delaware. His most recent assignments there included Northeast Region Vice President and National Director of Sales. MARK W. ROBERTS, 43, Vice President, Energy Trading and Planning of MidAmerican Energy. Mr. Roberts has been in his present position since April 1999 and was a manager and then vice president of MidAmerican Energy's generation business services from December 1996 to April 1999. Prior to that time, Mr. Roberts held various management positions with MidAmerican Energy and its predecessor companies for more than five years. THOMAS B. SPECKETER, 43, Vice President and Controller of MidAmerican Energy Company. Mr. Specketer has been in his present position since September 1999 and has over twenty years of accounting and tax experience with MidAmerican Energy and its predecessor companies. STEVEN R. WEISS, 45, Assistant General Counsel of MidAmerican Energy. Mr. Weiss has been with MidAmerican Energy and its predecessor companies since 1987 providing support to both the regulated and competitive sides of the business. He was appointed to his current position in March 1999. Prior to joining -38- MidAmerican Energy he served as a Hearing Examiner for the Illinois Commerce Commission from 1982 until 1987. P. ERIC CONNOR, 51, Director, Northern Electric and President and Chief Operating Officer, Northern Electric. 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 & Defense. DAVE CROMPTON, 46, 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. DR. JOHN M. FRANCE, 42, Director, Northern Electric and Director of Regulation, Northern Electric. Mr. France joined Northern in 1989 as Regulation Manager. Between 1982 to 1989, Mr. France held a number of regulatory positions with British Gas. G. VALERIE GILES, 48, 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. NEIL MIDDLETON, 35, Managing Director, Northern Electric Supply Limited. Mr. Middleton joined Nothern in 1989 having studied Electrical and Electronics Engineering at the University of Newcastle Upon Tyne. Prior to taking up his current appointment, Mr. Middleton worked in the Pricing and Purchasing Departments. DR. PHILIP S. LAWLESS, 38, 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. KEN LINGE, 50, Director of Finance, Northern Electric. Mr. Linge joined Northern as an accountancy trainee in 1968. He has held a variety of finance posts. Current responsibilities include financial planning, taxation, treasury, pensions, and group accounting services. MARK HORSLEY, 40, Managing Director, Northern Utility Services Limited. Mr. Horsley joined Northern in 1975 as a craft apprentice and subsequently held a number of progressing senior engineering positions. JAMES D. STALLMEYER, 42, Director, Northern Electric and Vice President and Commercial Director and General Counsel, Northern Electric. 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, 55, Distribution Director. 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. -39- DAVID A. WATERS, 57, Managing Director, Northern Electric Distribution Limited. 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. PETER YOUNGS, 45, 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 CalEnergy Gas (UK) Limited. ITEM 11. EXECUTIVE COMPENSATION To be filed by amendment. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT To be filed by amendment. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS To be filed by amendment. -40- PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Financial Statements and Schedules 1. Financial Statements (included herein) Page No. Selected Consolidated Financial Data...............................42 Management's Discussion and Analysis of Financial Condition And Results of Operations........................................43 Qualitative and Quantitative Disclosures About Market Risk.........56 Consolidated Balance Sheets as of December 31, 1999 and 1998.......59 Consolidated Statements of Operations For the Three Years Ended December 31, 1999, 1998 and 1997.......60 Consolidated Statements of Stockholders' Equity For the Three Years Ended December 31, 1999, 1998 and 1997.......61 Consolidated Statements of Cash Flows For the Three Years Ended December 31, 1999, 1998 and 1997.......62 Notes to Consolidated Financial Statements.........................63 Report of Independent Accountants..................................96 2. Financial Statement Schedules Page No. Schedule I, Financial Statements of the Company (Parent Company only)............................................97 (b) Reports on Form 8-K The Company filed a Current Report on Form 8-K dated October 8, 1999 announcing received tenders and consent from holders of an aggregate of $119 million principal amount of its 9 1/2% Senior Notes due 2006. The Company filed a Current Report on Form 8-K dated October 20, 1999 announcing that the International Arbitration Panel announces favorable final decisions for Himpurna California Energy and Patuha Power requiring Republic of Indonesia to pay $575,000,000. The Company filed a Current Report on Form 8-K dated October 21, 1999 announcing that on October 20, 1999, it has established the final pricing for the tender of its 9 1/2% Senior Notes due 2006, in connection with its previously announced cash tender offer and consent solicitation for such Notes. The Company filed a Current Report on Form 8-K dated October 24, 1999 announcing that it had entered into an Agreement and Plan of Merger, dated as of October 24, 1999 with entities formed by an investor group including Berkshire Hathaway Inc., Walter Scott, Jr. and David L. Sokol. (c) Exhibits The exhibits listed on the accompanying Exhibit Index are filed as part of this Annual Report. (d) Financial statements required by Regulations S-X, which are excluded from the Annual Report by Rule 14a-3(b). Not applicable. -41- SELECTED CONSOLIDATED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31 ------------------------------------------------------------------------- 1999 (1) 1998(2) 1997 1996(3) 1995(4) ----------- ---------- ---------- ---------- ----------- INCOME STATEMENT DATA: Operating revenue $ 4,128,737 $2,555,206 $2,166,338 $ 518,934 $ 335,630 Total revenue 4,398,783 2,682,711 2,270,911 576,195 398,723 Total costs and expenses 4,041,714 2,410,658 2,074,051 435,791 301,672 Income before provision for income taxes 357,069 272,053 196,860(6) 140,404 97,051 Minority interest 46,923 41,276 45,993 6,122 3,005 Income before change in accounting principle and extraordinary item 216,671(5) 137,512 51,823(6) 92,461 63,415 Extraordinary item, net of tax (49,441) (7,146) (135,850) -- -- Cumulative effect of change in accounting principle, net of tax -- (3,363) -- -- -- Net income (loss) 167,230(5) 127,003 (84,027)(6) 92,461 63,415 Income per share before change in accounting principle and extraordinary item $ 3.62(5) $ 2.29 $ 0.77(6) $ 1.69 $ 1.32 Extraordinary item per share (.83) (.12) (2.02) -- -- Cumulative effect of change in accounting principle per share -- (.06) -- -- -- Net income (loss) per share $ 2.79(5) $ 2.11 $ (1.25)(6) $ 1.69 $ 1.32 Basic common shares outstanding 59,929 60,139 67,268 54,739 47,249 Income per share before extraordinary item and cumulative effect of change in accounting - diluted $ 3.28(5) $ 2.15 $ 0.75(6) $ 1.54 $ 1.22 Extraordinary item - diluted (.69) (.10) (1.97) -- -- Cumulative effect of change in accounting principle - diluted -- (.04) -- -- -- Net income (loss) per share - diluted $ 2.59(5) $ 2.01 $ (1.22)(6) $ 1.54 $ 1.22 Diluted shares outstanding 71,948 74,100 68,686 65,072 56,195 BALANCE SHEET DATA: Total assets $10,766,352 $9,103,524 $7,487,626 $5,630,156 $2,654,038 Total liabilities 8,978,924 7,598,040 5,282,162 4,181,052 2,084,474 Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts 450,000 553,930 553,930 103,930 -- Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts 101,598 -- -- -- -- Preferred securities of subsidiaries 146,606 66,033 56,181 136,065 -- Total stockholders' equity 994,588 827,053 765,326 880,790 543,532
(1) Reflects the MidAmerican Merger owned for a portion of the year, the disposition of Coso Joint ventures during the year, and the disposition of 50% ownership interest in CE Generation (2) Reflects the acquisition of KDG. (3) Reflects the acquisitions of Northern, Falcon Seaboard and the Partnership Interest owned for a portion of the year. (4) Reflects the acquisition of Magma Power Company owned for a portion of the year. (5) Includes $81,556, $1.36 per basic share and $1.13 per diluted share for non-recurring Indonesia gain on settlement, gains on sales of McLeod and qualified facilities, Northern restructuring charges and Berkshire transaction costs. (6) Includes the $87,000, $1.29 per basic share, $1.27 per diluted share, non-recurring Indonesian asset impairment charge. -42- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Business of MEHC MidAmerican Energy Holdings Company (the "Company" or "MEHC"), is a United States-based privately owned global energy company with publicly traded fixed income securities that generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries the Company is organized and managed on three separate platforms: MidAmerican MidAmerican Energy ("MEC") is the largest energy company headquartered in Iowa and is a regulated public utility principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MEC distributes electricity at retail in Iowa, Illinois and South Dakota. It also distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 1999, MEC had 663,500 retail electric customers and 638,000 retail natural gas customers. In addition to retail sales, MEC delivers electric energy to other utilities, marketers and municipalities who distribute it to end-use customers. These sales are referred to as sales for resale or off-system sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. MEC's regulated electric and gas operations are conducted under franchises, certificates, permits and licenses obtained from state and local authorities. The franchises, with various expiration dates, are typically for 25-year terms. MEC has a residential, agricultural, commercial and diversified industrial customer group, in which no single industry or customer accounted for more than 5% of its total 1999 electric operating revenues or 3% of its total 1999 gas operating margin. Among the primary industries served by MEC are those that are concerned with the manufacturing, processing and fabrication of primary metals, real estate, food products, farm and other non-electrical machinery, and cement and gypsum products. Most of MEC's business is conducted in a rate-regulated environment and accordingly, many of its decisions as to the source and use of resources and other strategic matters are evaluated from a utility business perspective. MEC's operations are seasonal in nature with a disproportionate percentage of revenues and earnings historically being earned in the Company's first and third quarters. MidAmerican Capital Company manages marketable securities and passive investment activities, security services and other energy-related, nonregulated activities. MidAmerican Services Company provides energy management and related services. Midwest Capital Group, Inc. functions as a regional business development company in MEC's service territory. Through October 6, 1999, MHC Inc. owned approximately 95% of the common stock of MidAmerican Realty Services. On October 6, 1999, MidAmerican Realty Services was dividended out of MHC Inc. to the Company and merged with HomeServices.Com ("HomeServices"), a subsidiary of the Company. HomeServices includes the Company's real estate brokerage operations and offers integrated real estate services in eleven states including residential brokerage, relocation, title, abstract and mortgage services. On October 18, 1999, the Company closed on its initial public offering of 3.25 million shares of common stock of HomeServices at $15 per share. HomeServices sold 2.19 million newly issued shares and the Company, the selling stockholder, sold 1.06 million of its HomeServices shares in the offering. The offering reduced the Company's ownership in HomeServices to approximately 65%. -43- Northern The operations of Northern Electric plc ("Northern"), an indirect wholly owned subsidiary of the Company, consist primarily of the distribution and supply of electricity, supply of natural gas and other auxiliary businesses in the United Kingdom. Northern's operations are seasonal in nature with a disproportionate percentage of revenues and earnings historically being earned in the Company's first and fourth quarters. Northern receives electricity from the national grid transmission system and distributes it to customers' premises using its 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 delivered electricity through Northern's distribution system, regardless of whether it is supplied by Northern's own supply business or by other suppliers, thus providing Northern with distribution volume that is stable from year to year. Northern charges access fees for the use of the distribution system. The prices for distribution are controlled by a prescribed formula that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action. On December 2, 1999, the United Kingdom's Office of Gas and Electricity Markets ("Ofgem") issued its final proposals for regulated revenue reduction for the distribution business of Northern to be effective from April 1, 2000. The report proposed revenue reductions for all public electricity supply companies in Great Britain including a reduction of 24% (equivalent to approximately $76 million for a full year) for Northern. The proposals have been accepted by the Company. To mitigate the effects of the revenue reduction, Northern is in the process of implementing a series of cost reduction initiatives including a redundancy program which will result in 500 employees leaving Northern. Northern's supply business primarily involves the bulk purchase of electricity, through a central pool, and subsequent resale to individual customers. The supply business generally is a high volume business which tends to operate at lower profitability levels than the distribution business. Prior to November 4, 1998, Northern was the exclusive supplier of electricity to premises in its authorized area, except where the maximum demand of a customer was greater than 100kW. Beginning November 4, 1998, liberalization of the entire market in Northern's area commenced in stages with complete liberalization achieved in Northern's authorized area by the end of April 1999. In the market between 100kW and 1MW of electrical demand, Northern is now one the largest electricity suppliers in the U.K. market. As of December 31, 1999, Northern supplied electricity to 1,339,000 customers. Also, on December 2, 1999, Ofgem issued its final proposals for electricity supply prices for the two years ended March 31, 2002. The proposals which have been accepted by the Company relate mainly to domestic customers in Northern's authorized area and will lead to a price reduction of approximately 11% in real terms with effect from April 1, 2000. Northern also competes to supply gas inside and outside its authorized area. In the residential market Northern currently supplies gas to approximately 570,000 customers and is now the fourth largest gas supplier of the new entrants in the U.K. residential market. CalEnergy On February 8, 1999, the Company created a new subsidiary, CE Generation LLC ("CE Generation") and subsequently transferred its interest in the Imperial Valley Projects and Gas Plants to CE Generation. For purposes of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Elmore and Leathers (collectively the "Partnership Projects") are based on 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 Projects") are based on capacity amounts of 10, 20, 49.8 and 39.6 net MW, respectively (the Partnership Projects and the Salton Sea Projects are collectively referred to as the "Imperial Valley Projects"). Plant capacity factors for Saranac, Power Resources, NorCon and Yuma (collectively the "Gas Plants") are based on capacity amounts of 240, 200, 80, and 50 -44- net MW, respectively. Each plant possesses an operating margin that 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 between calendar quarters, under normal operating conditions. Due to the sale of 50% of its interests in CE Generation, the Company has accounted for CE Generation as an equity investment beginning March 3, 1999. Prior to that date, CE Generation results were fully consolidated. The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively, the "Philippine Projects"), which are geothermal power plants located on the island of Leyte in the Philippines. For purposes of consistent presentation, capacity amounts for Upper Mahiao, Malitbog and Mahanagdong (collectively, the "Philippine Projects") are 119, 216 and 165 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 between calendar quarters, under normal operating conditions. On February 26, 1999, the Company closed the sale of all of its ownership interests in the Navy I, Navy II and BLM, collectively the Coso Joint Ventures, to Caithness Energy, LLC ("Caithness"). The price included $205 million in cash and $5 million in contingent payments. RESULTS OF OPERATIONS - --------------------- 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. As a result of the Berkshire transaction, the MidAmerican Merger and the sales of Coso and an interest in CE Generation, the Company's future results will differ significantly from the Company's historical results. Berkshire Transaction On October 24, 1999, the Company and entities representing an investor group comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr., a director of the Company, and David L. Sokol, Chairman and Chief Executive Officer of the Company, executed a definitive agreement and plan of merger whereby the investor group would acquire all of the outstanding common stock of the Company for $35.05 per share in cash, representing a total purchase price of approximately $2.2 billion, including transaction costs. The Berkshire Transaction closed on March 14, 2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock and convertible preferred stock and approximately $455 million in nontransferable trust preferred stock. Mr. Scott, Mr. Sokol and Gregory E. Abel, Chief Operating Officer of the Company, contributed cash and current securities of the Company having a value of approximately $310 million. The remaining purchase price was funded with the Company's cash. Berkshire Hathaway owns not more than 9.9% of the voting stock, Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the voting stock. The Company incurred approximately $6.7 million of non-recurring costs in 1999, related to the Berkshire transaction, which were expensed. Acquisitions/Dispositions MidAmerican Merger On August 11, 1998, the Company entered into an Agreement and Plan of Merger with MHC. The MidAmerican Merger closed on March 12, 1999 and the Company paid $27.15 in cash for each outstanding share of MHC common stock for a total of approximately $2.42 billion in a merger, pursuant to which MHC became an indirect -45- wholly owned subsidiary of the Company. Additionally, the Company reincorporated in the State of Iowa, was renamed MidAmerican Energy Holdings Company and upon closing became an exempt public utility holding company. The MidAmerican Merger has been accounted for as a purchase business combination and as such the results of operations of the Company include the results of MHC beginning March 12, 1999. Qualified Facilities Disposition The consummation of the MidAmerican Merger was conditioned upon receipt of a number of regulatory and shareholder approvals and the disposition of partial interests in certain of the Company's power generating facilities in order to maintain the qualifying facilities status of such independent power generating facilities. To accomplish this disposition, the following events occurred in the first quarter of 1999: On February 26, 1999, the Company closed the sale of all of its ownership interests in the Coso Joint Ventures to Caithness for $205 million in cash. On February 8, 1999, the Company created a new subsidiary, CE Generation LLC ("CE Generation") and subsequently transferred its interest in the Company's power generation assets in the Imperial Valley Projects and Gas Plants to CE Generation. On March 2, 1999, CE Generation closed the sale of $400 million aggregate principal amount of its 7.416% Senior Secured Bonds due in 2018. On March 3, 1999, the Company closed the sale of 50% of its ownership interests in CE Generation to an affiliate of El Paso Energy Corporation for an aggregate consideration of approximately $245 million in cash, $6.5 million in contingent payments and $23.5 million in equity commitments. The sales of the qualified facilities resulted in a net non-recurring pre-tax gain of $20.2 million and an after-tax gain of approximately $12.4 million or $0.17 per diluted share. McLeod On May 18, 1999, the Company announced the sale of approximately 6.74 million shares of McLeodUSA ("McLeod") Class A common stock, through a secondary offering by McLeod, at $55.625 per share. Proceeds from the sale were approximately $375 million, with a resulting pre-tax gain to the Company of approximately $78.2 million and an after-tax gain of approximately $47.1 million or $0.65 per diluted share. HomeServices On October 18, 1999, the Company announced that HomeServices, a subsidiary of the Company, closed its initial public offering of 3,250,000 shares of common stock at $15 per share. HomeServices sold 2,187,500 shares and the Company, the selling stockholder, sold 1,062,500 shares in the offering. HomeServices is the surviving entity of a merger with MidAmerican Realty Services. Indonesia On December 2, 1994, subsidiaries of the Company, Himpurna California Energy Ltd. ("HCE") and Patuha Power, Ltd. ("PPL", together with HCE, the "Indonesian Subsidiaries") executed separate joint operation contracts for the development of geothermal steam fields and geothermal power facilities located in Central Java in Indonesia with Perusahaan Pertambangan Minyak Dan Gas Bumi Negara ("Pertamina"), the Indonesian national oil company, and executed separate "take-or-pay" energy sales contracts ("ESCs") with both Pertamina and P.T. PLN (Persero) ("PLN"), the Indonesian national electric utility. The Government of Indonesia provided sovereign performance undertakings of the obligations under the joint operating and "take-or-pay" contracts. -46- In 1997 and 1998 a series of Indonesian government decrees and other actions (including the non-payment of all monthly invoices from HCE's Dieng Unit I, which became operational in March 1998) created significant uncertainty as to whether PLN and the Indonesian government would honor their contractual obligations to the Indonesian Subsidiaries. In 1997, the Company recorded a non-recurring charge of $87 million representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to the Company's assets in Indonesia. The charge of $87 million represented the amount by which the carrying amount of such assets exceeded the estimated 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. On or about August 14, 1998, the Company, through the Indonesian Subsidiaries, began arbitration proceedings against PLN in connection with the HCE's and PPL's geothermal power projects in Indonesia, the Dieng Project and the Patuha Project. An arbitral tribunal found that PLN had materially breached the provisions of the ESCs between PLN and both HCE and PPL, and awarded HCE approximately $391.7 million and PPL $180.6 million, and ordered PLN to pay these amounts immediately. Following PLN's failure to pay such amounts, HCE and PPL demanded payment pursuant to the sovereign performance undertakings issued by the Minister of Finance ("MOF") on behalf of the Republic of Indonesia ("ROI") and following the ROI's failure to pay brought an arbitration against the ROI for breach of those undertakings. A final award was issued by an international arbitration panel in the ROI arbitration on October 15, 1999, which found that the ROI materially breached its performance undertakings and violated international law and the ROI was required to pay HCE and PPL an aggregate amount of approximately $575 million. The Company carried political risk insurance on its investment in HCE and PPL through OPIC, an agency of the U.S. Government, as well as through private market insurers. Such insurance covered expropriation of the Company's investment in HCE and PPL, as well as material breaches by PLN of the ESCs and by the ROI of its performance undertakings. On November 18, 1999, the Company received payment from OPIC and the private market insurers totaling $290 million under its political risk insurance policies, reflecting the return of its equity investment less policy deductibles. Due primarily to the timing of the receipt of the proceeds, the Company recorded a pre-tax gain of approximately $40.3 million on the insurance proceeds and an additional tax benefit of $17.7 million for an after-tax gain of $58.0 million, or $0.81 per diluted share. Results of Operations For The Years Ended December 31, 1999, 1998 and 1997 Operating revenue increased in the year ended December 31, 1999 to $4,128.7 million from $2,555.2 million for the same period in 1998, a 61.6% increase. Northern's operating revenue increased in the year ended December 31, 1999 to $2,072.2 million from $1,823.9 million for the same period in 1998, primarily due to higher volumes of gas supplied as well as higher electricity supply revenues. The MidAmerican Merger added $1,687.9 million in the period from March 12, 1999 through December 31, 1999. These increases were partially offset by the sales of Coso and reporting the 50% interest in CE Generation using the equity method beginning March 3, 1999. Operating revenues increased to $2,555.2 million in the year ended December 31, 1998, from $2,166.3 million in the year ended December 31, 1997, an 18.0% increase. This growth was primarily due to higher volumes and related revenues of gas and electricity supplied by Northern, commencement of operations at Malitbog Units II and III in the third quarter of 1997, and the consolidation of the Mahanagdong project resulting from the KDG Acquisition which had been accounted for using the equity method of accounting. -47- The following data represents the supply and distribution operations in the U.K.: Year Ended December 31, ----------------------------- 1999 1998 1997 ---- ---- ---- Electricity Supplied (GWh).............. 17,984 15,313 14,378 Electricity Distributed (GWh)........... 15,943 15,904 15,714 Gas Supplied (Therms in millions) ...... 484.2 359.5 74.5 The increases in electricity supplied for the year ended December 31, 1999 from the same period in 1998 are due primarily to the increase in supply volumes for customers outside of the franchise area. The increases in electricity distributed for the year ended December 31, 1999 from the same period in 1998 are due to changes in demand in the franchise area. The increases in gas supplied in 1999 from 1998 reflects the increased volume as the domestic gas supply business in the U.K. opened up to competition as a result of regulatory changes and the successful dual fuel marketing campaign. The following data represents sales from utility operations for MEC. The financial results of MEC are consolidated with the Company beginning on March 12, 1999. Year Ended December 31, ----------------------------- 1999 1998 1997 ---- ---- ---- Electric Retail Sales (GWh)............. 16,007 16,088 15,666 Electric Sales for Resale (GWh)......... 7,168 6,186 6,987 Gas Throughput (Therms in millions)..... 812 820 938 Interest and other income increased for the year ended December 1999 to $131.3 million from $127.5 million in the same period in 1998. The addition of MHC amounts following the MidAmerican Merger and the addition of equity income from CE Generation accounted for the increase partially offset by reduction of operator fees related to the qualified facilities that we sold in 1999 . Interest and other income increased in 1998 to $127.5 million from $104.6 million in 1997, a 21.9% increase. This increase was due primarily to interest earned by Casecnan on the cash held for construction, interest earned on the proceeds of the senior note and bond offering and the dividends received from our investment in Teesside Power Limited, partially offset by lower equity earnings due to the consolidation of Mahanagdong equity interest in 1998. The gains on non-recurring items of $138.7 million in 1999 represent the pre-tax gain on the sale of the qualified facilities of $20.2 million, the pre-tax gain on the sale of McLeod common stock of $78.2 million and the pre-tax gain on the Indonesia settlement of $40.3 million. Cost of sales increased in the year ended December 1999 to $2,143.9 million from $1,258.5 million from the same period in 1998, a 70.4% increase. The increase is primarily due to higher volumes of gas and electricity supplied at Northern and the MidAmerican Merger. The acquisition of MHC added $655.2 million in the period March 12, 1999 through December 31, 1999. Cost of sales increased to $1,258.5 million in 1998 from $1,055.2 million in 1997. This increase is primarily due to higher volumes of gas and electricity supplied. Operating expense increased in the year to date ended December 1999 to $989.6 million from $471.4 million for the same period in 1998, a 109.9% increase. The MidAmerican Merger added $597.3 million in the period from March 12, 1999 through December 31, 1999, partially offset by the sales of Coso and an interest in CE Generation. -48- Operating expense increased to $471.4 million in 1998 from $398.5 million in 1997, an increase of 18.3%. This increase is due to an increase in Northern's customer acquisition costs, including commissions and opening meter reads associated with the opening of the competitive gas supply market. Depreciation and amortization increased in the year to date December 1999 to $427.7 million from $333.4 million in the same period in 1998, a 28.3% increase. The MidAmerican Merger added $187.3 million in the period from March 12, 1999 through December 31, 1999, partially offset by the sales of Coso and the 50% interest in CE Generation. Depreciation and amortization increased to $333.4 million in 1998 from $276.0 million in 1997, an increase of 20.8%. This increase is due to the commencement of operations at Mahanagdong and Units II and III at Malitbog and the amortization of the allocated purchase price and goodwill related to the acquisition of KDG. As a result of the acquisition of KDG, Casecnan is fully consolidated into the Company's financial statements beginning January 2, 1998 and is no longer recorded as an equity investment. Interest expense, less amounts capitalized, increased in the year to date December 1999 to $426.2 million from $347.3 million, a 22.7% increase. The increase is primarily due to the MidAmerican Merger and the greater average outstanding debt balances. Interest expense, less amounts capitalized, increased in 1998 to $347.3 million from $251.3 million in 1997, a 38.2% increase. The increase is primarily due to the consolidation of Casecnan resulting from the KDG Acquisition, the greater average outstanding debt, the discontinued capitalization of interest due to the commencement of operations at Mahanagdong and Units II and III at Malitbog and the discontinued capitalization of interest in Indonesia as a result of the suspension of construction activity. The losses on non-recurring items of $54.4 million in 1999 represent the pre-tax loss of $47.7 million related to the costs associated with the reduction of Northern's workforce and the $6.7 million of costs related to the Berkshire transaction. The non-recurring charge of $87 million in 1997 represented an asset valuation impairment under Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to the Company's assets in Indonesia. The charge included all reasonably estimated cash flows associated with the Company's assets in Indonesia and gave effect to the political risk insurance on such investments. The provision for income taxes increased marginally to $93.5 million in 1999 from $93.3 million in 1998 and decreased from $99.0 million in 1997. The decrease from 1997 to 1998 is due to lower pre-tax book income that resulted from increased dividends on convertible preferred securities of subsidiary trusts. After adjusting for the non-recurring gains and losses and the deductible dividends on preferred securities, the effective tax rate was 38.7%, 39.5% and 38.0% in 1999, 1998 and 1997 respectively. Minority interest consists of dividends on preferred securities of subsidiaries and minority ownership of HomeServices. Minority interest increased in the year ended December 1999 to $46.9 million from $41.3 million in the same period in 1998, a 13.6% increase. The increase is primarily due to the MidAmerican Merger that has minority interests in the form of preferred stock outstanding. Minority interest decreased to $41.3 million in 1998 from $46.0 million in 1997, a decrease of 10.3%. This decrease is a result of the purchase of Northern and KDG's minority interest, partially offset by increased dividends on convertible preferred securities of subsidiary trusts. Income before extraordinary items increased in the year ended December 1999 to $216.7 million or $3.62 per share from $137.5 million or $2.29 per share in 1998, and $51.8 million or $0.77 per share in 1997. Excluding the $87.0 million, $1.29 per share, non-recurring charge, income before extraordinary item would have been $138.8 million or $2.06 per share in 1997. Due to the early retirements of the Senior Discount Notes, the Limited Recourse Notes and the 9.5% Senior Notes, the Company recorded extraordinary losses of approximately $49.4 million, net of tax, in the year ended December 31, 1999. -49- During 1998, the Company recognized an extraordinary loss of $7.1 million, net of tax, related to the redemption of the Senior Discount Notes. The Company also recognized the cumulative effect of a change in accounting principle of $3.4 million, net of tax, by adopting Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities." 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 1997 budget. This amounted to $135.9 million, net of minority interest, which was recorded as an extraordinary item in 1997. The first installment was paid on December 1, 1997 and the remainder was paid in 1998. LIQUIDITY AND CAPITAL RESOURCES - ------------------------------- The Company has available a variety of sources of liquidity and capital resources, both internal and external. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company's unrestricted cash and cash equivalents were $316.3 million at December 31, 1999 as compared to $1,606.1 million at December 31, 1998. The majority of this decrease was due to the cash used to acquire MHC and the early retirement of the Senior Discount Notes, the Limited Recourse Notes and the 9.5% Senior Notes partially offset by the sales of McLeod common stock, the Qualified Facilities and the insurance proceeds on Indonesia. In addition, the Company recorded separately restricted cash and investments of $291.7 million and $637.6 million at December 31, 1999 and December 31, 1998, respectively. The restricted cash balance as of December 31, 1999 is comprised primarily of amounts deposited in restricted accounts from which the Company will fund the various projects under construction, and the Philippine Projects' cash reserves for the debt service reserve funds. Berkshire Transaction On October 24, 1999, the Company and entities representing an investor group comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr., a director of the Company, and David L. Sokol, Chairman and Chief Executive Officer of the Company, executed a definitive agreement and plan of merger whereby the investor group would acquire all of the outstanding common stock of the Company for $35.05 per share in cash, representing a total purchase price of approximately $2.2 billion, including transaction costs. The Berkshire Transaction closed on March 14, 2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock and convertible preferred stock and approximately $455 million in nontransferable trust preferred stock. Mr. Scott, Mr. Sokol and Gregory E. Abel, Chief Operating Officer of the Company contributed cash and current securities of the Company having a value of approximately $310 million. The remaining purchase price was funded with the Company's cash. Berkshire Hathaway owns not more than 9.9% of the voting stock, Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the voting stock. The Company incurred approximately $6.7 million of non-recurring costs in 1999, related to the Berkshire tranaction, which were expensed. Financing Activities The remaining outstanding Senior Discount Notes of $369.5 million were redeemed on January 15, 1999 at a redemption price of 105.125% plus accrued interest. -50- On January 29, 1999, the Company commenced a cash offer for all of its outstanding Limited Recourse Notes. The Company received tenders from holders of an aggregate of approximately $195.8 million of principal which were paid on March 3, 1999, at a redemption price of 110.025% plus accrued interest. On March 11, 1999, MidAmerican Funding, LLC, a wholly-owned subsidiary of the Company, issued $200 million of 5.85% Senior Secured Notes due in 2001, $175 million of 6.339% Senior Secured Notes due in 2009, and $325 million of 6.927% Senior Secured Bonds due in 2029. The proceeds from the offering were used to complete the MidAmerican Merger. On May 18, 1999, CalEnergy Capital Trust, a subsidiary of the Company, effected the conversion of $103.9 million of 6 1/4% Convertible Preferred Securities into approximately 3.5 million shares of common stock of the Company. The securities were converted at a rate of 1.6728 shares of common stock of the Company for each security, equivalent to a conversion price of $29.89 per share of Company common stock. The Company has redeemed substantially all of the $225 million in principal value of the 9.5% Senior Notes at an aggregate price of $247.6 million throughout the year ended December 31, 1999. Minerals Extraction The Company developed and owns the rights to proprietary processes 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 Projects. The Company intends to sequentially develop facilities for the extraction of manganese, silver, gold, lead, boron, lithium and other products as it further develops the extraction technology. The Company is also investigating producing silica as an extraction project. Silica is used as a filler for such products as paint, plastics and high temperature cement. CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is constructing the Zinc Recovery Project that will recover zinc from the geothermal brine (the "Zinc Recovery Project"). Facilities will be installed near the Imperial Valley Projects sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operation in mid-2000. In September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby all zinc produced by the Zinc Recovery Project will be sold to Cominco, LTD. The initial term of the agreement expires in December 2005. The Zinc Recovery Project is being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procurement and construction contract (the "Zinc Recovery Project EPC Contract"). Kvaerner is a wholly owned indirect subsidiary of Kvaerner ASA, an international engineering and construction firm experienced in the metals, mining and processing industries. Total project costs of the Zinc Recovery Project are expected to be approximately $200.9 million. The Company has incurred $92.8 million of such costs through December 31, 1999. Casecnan CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE Casecnan") which at completion of the Casecnan Project is expected to be at least 70% indirectly owned by the Company, is constructing 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. -51- CE Casecnan has entered into a fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Casecnan Construction Contract"). The work under the Casecnan Construction Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. On November 20, 1999, the Casecnan Construction Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. Accordingly, the Casecnan Project is now expected to become operational by the second quarter of 2001. Under the Project Agreement, if NIA has completed certain work on its irrigation system, CE Casecnan is liable to pay NIA $5,000 per day for each day of delay in completion of the Casecnan Project beyond July 27, 2000, increasing to $13,500 per day for each day of delay in completion beyond November 27, 2000. CE Casecnan's ability to make payments on any of its existing and future obligations is dependent on NIA's and the Republic of the Philippines' performance of their obligations under the Project Agreement and the Performance Undertaking, respectively. No shareholders, partners or affiliates of CE Casecnan, including the Company, and no directors, officers or employees of the Company will guarantee or be in any way liable for payment of CE Casecnan's obligations. As a result, payment of CE Casecnan's obligations depends upon the availability of sufficient revenues from CE Casecnan's business after the payment of operating expenses. NIA's payments of obligations under the Project Agreement are substantially denominated in United States dollars and are expected to be CE Casecnan's sole source of operating revenues. Because of CE Casecnan's dependence on NIA, any material failure of NIA to fulfill its obligations under the Project Agreement and any material failure of the Republic of the Philippines to fulfill its obligations under the Performance Undertaking would significantly impair the ability of CE Casecnan to meet its existing and future obligations. Cordova Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, has commenced construction of a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). Cordova Energy has entered into an engineering, procurement and construction contract with Stone & Webster Engineering Corporation ("SWEC") to build the project. Total project costs are estimated to be approximately $288.9 million. The Company has also entered into a power sales agreement with a unit of El Paso Energy Corporation ("El Paso"). Under the power sales agreement, El Paso will purchase all the capacity and energy from the project until December 31, 2019. However, Cordova Energy has the option to elect on an annual basis to retain up to 50% of the project output for sales to others. The construction of the Cordova Project is expected to be completed in mid-2001. On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly owned subsidiary of the Company, closed the $225 million aggregate principal amount financing for the construction of the Cordova Project. As part of the financing, approximately $93.5 million of 8.64% Series A-1 Senior Secured Bonds due in 2019 were issued. An additional $31.3 million of 8.79% Series A-2 Senior Secured Bonds were issued on December 15, 1999. Additional Series A Senior Secured Bonds will be issued as required to fund construction. Cordova Funding will loan the proceeds to Cordova Energy as required. The Company has incurred $80.0 million of such costs through December 31, 1999. Total equity funding is expected to be approximately $63.9 million. Evolution of the Domestic Utility Industry The U.S. utility industry continues to evolve into an increasingly competitive environment. In virtually every region of the country, legislative and regulatory actions are being taken which result in customers having more choices in their energy decisions. -52- In the electric industry, the traditional vertical integration of generation, delivery and marketing is being unbundled, with the generation and marketing functions becoming deregulated. For local gas distribution businesses, the supply, local delivery and marketing functions are similarly being separated and opened to competitors for all classes of customers. While retail electric competition is presently not permitted in Iowa, MEC's primary market, legislation to do so was introduced in the Iowa legislature in the last session. While this legislation has not passed, it is being considered again by the Iowa legislature in 2000. Deregulation of the gas supply function related to small volume customers is also being considered by the Iowa Utilities Board ("IUB"). MEC is actively participating in the legislative and regulatory processes. The generation and retail portions of MEC's electric business will be most affected by competition. The introduction of competition in the wholesale market has resulted in a proliferation of power marketers and a substantial increase in market activity. As retail choice evolves, competition from other traditional utilities, power marketers and customer-owned generation could put pressure on utility margins. During the transition to full competition, increased volatility in the marketplace can be expected. With the elimination of the energy adjustment clause in Iowa, MEC is financially exposed to movements in energy prices. Although MEC has sufficient low cost generation under typical operating conditions for its retail electric needs, a loss of adequate generation by MEC at a time of high market prices could subject MEC to losses on its energy sales. Domestic Legislative and Regulatory Evolution In December 1997, the Governor of Illinois signed into law a bill to restructure Illinois' electric utility industry and transition it to a competitive market. Under the law, beginning October 1, 1999, larger non-residential customers in Illinois and 33% of the remaining non-residential Illinois customers are allowed to select their provider of electric supply services. All other non-residential customers will have supplier choice starting December 31, 2000. Residential customers all receive the opportunity to select their electric supplier on May 1, 2002. Accounting Effects of Industry Restructuring A possible consequence of competition in the utility industry is that SFAS 71 may no longer apply. SFAS 71 sets forth accounting principles for operations that are regulated and meet certain criteria. For operations that meet the criteria, SFAS 71 allows, among other things, the deferral of costs that would otherwise be expensed when incurred. A majority of MEC's electric and gas utility operations currently meet the criteria required by SFAS 71, but its applicability is periodically reexamined. On December 16, 1997, MEC's generation operations serving Illinois were no longer subject to the provisions of SFAS 71 due to passage of industry restructuring legislation in Illinois. Thus, in 1997 MEC was required to write off the regulatory assets and liabilities from its balance sheet related to its Illinois generation operations. The net amount of such write-offs was not material. If other portions of its utility operations no longer meet the criteria of SFAS 71, MEC could be required to write off the related regulatory assets and liabilities from its balance sheet, and thus, a material adjustment to earnings in that period could result if regulatory assets are not recovered in transition provisions of any resulting legislation. As of December 31, 1999, the Company had $278.8 million of regulatory assets on its consolidated balance sheet. Domestic Rate Matters: Electric Through several steps from mid-1997 to the end of 1998, electric prices for Iowa industrial customers were reduced by an amount which had a $6 million annual impact on revenues, and electric prices for Iowa commercial customers were reduced by an amount which had a $4 million annual impact on revenues. The reductions were achieved through a retail access pilot project, negotiated individual electric contracts and a $1.5 million tariffed rate reduction for certain non-contract commercial customers. -53- The negotiated electric contracts have differing terms and conditions as well as prices. The contracts range in length from five to ten years, and some have price renegotiation and early termination provisions exercisable by either party. The vast majority of the contracts are for terms of seven years or less, although, some large customers have agreed to ten-year contracts. Prices are set as fixed prices; however, many contracts allow for potential price adjustments with respect to environmental costs, government imposed public purpose programs, tax changes, and transition costs. While the contract prices are fixed (except for the potential adjustment elements), the costs MEC incurs to fulfill these contracts will vary. MEC presently intends to manage this risk through hedging and other similar arrangements. On an aggregate basis the annual revenues under contract are approximately $180 million. Under a 1997 pricing plan settlement agreement resulting from an IUB rate proceeding, if MEC's annual Iowa electric jurisdictional return on common equity exceeds 12%, then earnings above the 12% level will be shared equally between customers and MEC. If the return exceeds 14%, then two-thirds of MEC's share of those earnings above the 14% level will be used for accelerated recovery of certain regulatory assets. The pricing plan settlement agreement precludes MEC from filing for increased rates prior to 2001 unless the return falls below 9%. Other parties signing the agreement are prohibited from filing for reduced rates prior to 2001 unless the return, after reflecting credits to customers, exceeds 14%. On April 14, 1999, the Iowa Utilities Board approved, subject to additional refund, MEC's calculation of the 1998 return on common equity. During the second quarter of 1999, MEC credited $2.2 million to its Iowa non-contract customers related to the return calculation for 1998. The agreement also eliminated MEC's energy adjustment clause, and, as a result, the cost of fuel is not directly passed on to customers. In 1999, MEC accrued $15.0 million for customer credits relating to 1999 operations. Environmental Matters The U.S. Environmental Protection Agency, or EPA, and state environmental agencies have determined that contaminated wastes remaining at decommissioned manufactured gas plant facilities may pose a threat to the public health or the environment if these contaminants are in sufficient quantities and at sufficient concentrations as to warrant remedial action. MEC has evaluated or is evaluating 27 properties which were, at one time, sites of gas manufacturing plants in which it may be a potentially responsible party. The purpose of these evaluations is to determine whether waste materials are present, whether the materials constitute an environmental or health risk, and whether MEC has any responsibility for remedial action. MEC's estimate of the probable costs for these sites as of December 31, 1999, was $28 million. This estimate has been recorded as a liability and a regulatory asset for future recovery through the regulatory process. Although the timing of potential incurred costs and recovery of costs in rates may affect the results of operations in individual periods, management believes that the outcome of these issues will not have a material adverse effect on the Company's financial position or results of operations. On July 18, 1997, the EPA adopted revisions to the National Ambient Air Quality Standards for ozone and a new standard for fine particulate matter. Based on data to be obtained from monitors located throughout the states, the EPA will make a determination of whether the states have any areas that do not meet the air quality standards (i.e., areas that are classified as nonattainment). If a state has area(s) classified as nonattainment area(s), the state is required to submit a State Implementation Plan specifying how it will reach attainment of the standards through emission reductions or other means. In May 1999, the U.S. Court of Appeals for the District of Columbia Circuit remanded the standards adopted in July 1997 back to the EPA indicating the EPA had not expressed sufficient justification for the basis of establishing the standards and ruling that the EPA has exceeded its constitutionally-delegated authority in setting the standards. The EPA's appeal of the court's ruling to the full panel of the U.S. Court of Appeals for the District of Columbia Circuit was denied. As a result of the court's initial decision and the current status of the standards, the impact of any new standards on the Company is currently unknown. If the EPA successfully appeals the court's decision, however, and -54- the new standards are implemented, then MEC's fossil fuel generating stations may be subject to emission reductions if the stations are located in nonattainment areas. As part of an overall state plan to achieve attainment of the standards, MEC could be required to install control equipment on its fossil fuel generating stations or decrease the number of hours during which these stations operate. The degree to which MEC may be required to install control equipment or decrease operating hours under a nonattainment scenario would be determined by the state's assessment of ME's relative contribution, along with other emission sources, to the nonattainment status. The installation of control equipment would result in increased costs to MEC. A decrease in the number of hours during which the affected stations operate would decrease the revenues of the Company. Nuclear Decommissioning Each licensee of a nuclear facility is required to provide financial assurance for the cost of decommissioning its licensed nuclear facility. In general, decommissioning of a nuclear facility means to safely remove the facility from service and restore the property to a condition allowing unrestricted use by the operator. Based on information presently available, the Company expects to contribute approximately $42 million during the period 2000 through 2004 to an external trust established for the investment of funds for decommissioning Quad Cities Station. Approximately 65% of the trust's funds are now invested in domestic corporate debt and common equity securities. The remainder is invested in investment grade municipal and U.S. Treasury bonds. In addition, MEC makes payments to the Nebraska Public Power District ("NPPD") related to decommissioning Cooper. These payments are reflected in other operating expense in the consolidated statements of operations. NPPD estimates call for MEC to pay approximately $57 million to NPPD for Cooper decommissioning during the period 2000 through 2004. NPPD invests the funds predominately in U.S. Treasury Bonds and other U.S. Government securities. Approximately 20% was invested in domestic corporate debt. MEC's obligation for Cooper decommissioning may be affected by the actual plant shutdown date and the status of the power purchase contract at that time. In July 1997, NPPD filed a lawsuit in United States District Court for the District of Nebraska naming MEC as the defendant and seeking a declaration of MEC's rights and obligations in connection with Cooper nuclear decommissioning funding. Cooper and Quad Cities Station decommissioning costs charged to Iowa customers are included in base rates, and recovery of increases in those amounts must be sought through the normal ratemaking process. Cooper decommissioning costs charged to Illinois customers are recovered through a rate rider on customer billings. Securitization of Accounts Receivable In December 1998, Northern entered into a revolving receivable purchase agreement with Kitty Hawk Funding Corporation ("Kitty Hawk"), an unaffiliated special purpose entity established to purchase accounts receivable. The agreement, which expires annually, was renewed in December 1999, allows Northern to sell all of its rights, title and interest in the majority of its billed electricity accounts receivable and to borrow against its unbilled electricity accounts receivable. In March 1999, Northern received $161 million in cash associated with the agreement. As of December 31, 1999, approximately $19 million was accounted for as a loan. Development Activity 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 -55- 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 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 the value of 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 26, 1999, filed with the Securities and Exchange Commission. New Accounting Pronouncement In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," which established accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. This statement is effective for the Company in the first quarter of the year 2001. The Company is in the process of evaluating the impact of this accounting pronouncement. Qualitative and Quantitative Disclosures About Market Risk The following discussion of the Company's exposure to various market risks contains "forward-looking statements" that involve risks and uncertainties. These projected results have been prepared utilizing certain assumptions considered reasonable in the circumstances and in light of information currently available to the Company. Actual results could differ materially from those projected in the forward-looking information. Interest Rate Risk At December 31, 1999, the Company had fixed-rate long-term debt, Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts and subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts of $5,993.2 million in principal amount and having a fair value of $5,825.7 million. These instruments are fixed-rate and therefore do not expose the Company to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $281 million if interest rates were to increase by 10% from their levels at December 31, 1999. In general, such a decrease in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. At December 31, 1999, the Company had floating-rate obligations of $670.5 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating rates were to increase by 10% from December 31, 1999 levels, the Company's consolidated interest expense for unhedged floating-rate obligations would increase by approximately $414,000 each month in which such increase continued based upon December 31, 1999 principal balances. -56- Currency Exchange Rate Risk At December 31, 1999, CE Electric UK Funding Company had fixed-rate obligations denominated in U.S. dollars that expose CE Electric UK Funding Company to losses in the event of increases in the exchange rate of U.S. dollars to Sterling. CE Electric UK Funding Company entered into certain interest rate swap agreements that effectively convert the U.S. dollar fixed interest rate to a fixed rate in Sterling. At December 31, 1999, these interest rate swap agreements had an aggregate notional amount of $362 million, which the Company could terminate at a cost of approximately $12.1 million. A decrease of 10% in the December 31, 1999 rate of exchange of Sterling to dollars would increase the cost of terminating these swap agreements by approximately $54 million. Energy Commodity Price Risk Northern utilizes contracts for differences ("CFDs"), as part of the overall risk management strategy of its electricity supply business, to mitigate its exposure to volatility in the price of electricity purchased through the electricity pool (the "Pool"). The portfolio of CFDs held for risk management purposes is established to match the notional quantity of the expected or committed transaction volumes that will be subject to commodity price risk over the same time period. The portfolio is therefore managed to complement the expected electricity purchase transaction portfolio, thereby reducing electricity price change risk to within acceptable limits. As a consequence, the value of the portfolio of CFDs, which are held for risk management purposes, is directly linked to the hypothetical changes in Pool price, such that an adverse movement in Pool price would be offset by a compensating impact on the contract. For the specified volumes, therefore, the impact of Pool risk is constrained at a pre-determined level, assuming: (i) The CFD is not closed in advance of its agreed term. (ii) The level of purchase occurs as expected, matching volumes covered by the CFD. Therefore, disclosure in respect to CFDs relies on the assumption that the contracts exist in parallel to underlying actual electricity purchases. In the absence of such purchases the contract would generate a loss or gain dependent on the pool prices prevailing over the periods covered by the contract terms. As of December 31, 1999, the notional amount of executed CFDs was approximately $639.2 million, representing approximately 12% of the expected or committed transaction volumes through March 31, 2004. The fair value of these contracts was approximately $(11.5) million discounted at 15%, based upon quoted market prices at December 31, 1999. A hypothetical decrease of 10% in the market price of electricity from the December 31, 1999 levels would decrease the fair value of these contracts by approximately $54.7 million. However, as stated above, the value of the portfolio of CFDs, which are held for risk management purposes, is directly linked to the hypothetical changes in Pool price, such that a movement in Pool price would be offset by a compensating impact on the contract. The current gas purchasing strategy of Northern's gas supply business minimizes risks in a rapidly changing market by buying both medium and short-term gas forward contracts directly backing sales to customers within prudent anticipation of future demand growth. The portfolio of contracts is varied so as to lock in price at an early stage. This portfolio may take various forms including long-term daily swing contracts, annual swing contracts and flat monthly or quarterly standard blocks. Over time, each month's coverage is assessed as to the likelihood of matching demand and supply cover. Any changes to the forecast are built into the forward purchase requirements. In addition, applying pricing scenarios to the uncovered portion of the portfolio continuously assesses the supply risk to the business. -57- As of December 31, 1999, the notional amount of outstanding forward purchase contracts was approximately $226.8 million, representing approximately 13% of expected sales through December 31, 2007. The fair value of such contracts was approximately $(8.2) million discounted at 15%, based upon quoted market prices at December 31, 1999. A hypothetical decrease of 10% in the market price of gas from the December 31, 1999 levels would further decrease the fair value of these contracts by approximately $17.2 million. Forward-looking Statements Certain information included in this report contains forward-looking statements made pursuant to the Private Securities Litigation Reform Act of 1995 ("Reform Act"). Such statements are based on current expectations and involve a number of known and unknown risks and uncertainties that could cause the actual results and performance of the Company to differ materially from any expected future results or performance, expressed or implied, by the forward-looking statements. In connection with the safe harbor provisions of the Reform Act, the Company has identified important factors that could cause actual results to differ materially from such expectations, including development uncertainty, operating uncertainty, acquisition uncertainty, uncertainties relating to doing business outside of the United States, uncertainties relating to geothermal resources, uncertainties relating to domestic and international (and in particular, Indonesia) economic and political conditions and uncertainties regarding the impact of regulations, changes in government policy, industry deregulation and competition. Reference is made to all of the Company's SEC filings, including the Company's Report on Form 8-K dated March 26, 1999, incorporated herein by reference, for a description of such factors. The Company assumes no responsibility to update forward-looking information contained herein. -58- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
AS OF DECEMBER 31, --------------------------- 1999 1998 ------------ ----------- ASSETS - ------ Current Assets: Cash and investments ....................................... $ 316,327 $ 1,606,148 Restricted cash and short term investments ................. 36,294 29,395 Accounts receivable ........................................ 600,564 525,102 Other current assets ....................................... 185,128 141,721 ------------ ----------- Total Current Assets ..................................... 1,138,313 2,302,366 Property, plant, contracts and equipment, net ................ 5,463,329 4,236,039 Excess of cost over fair value of net assets acquired, net ... 2,712,677 1,538,176 Regulatory assets ............................................ 278,757 -- Long-term restricted cash and investments..................... 255,440 608,176 Nuclear decommissioning trust fund and other marketable securities ............................ 226,298 - Equity investments ........................................... 208,023 125,036 Deferred charges, other investments and other assets ......... 483,515 293,731 ------------ ----------- Total Assets ............................................... $ 10,766,352 $ 9,103,524 ============ =========== LIABILITIES AND STOCKHOLDERS' EQUITY - ------------------------------------ Current Liabilities: Accounts payable ........................................... $ 449,203 $ 305,720 Other accrued liabilities .................................. 458,667 252,751 Current portion of long-term debt .......................... 614,725 381,491 ------------ ----------- Total Current Liabilities ................................ 1,522,595 939,962 Other long-term accrued liabilities .......................... 1,054,440 756,377 Parent company debt .......................................... 1,856,318 2,645,991 Subsidiary and project debt .................................. 3,642,703 2,712,319 Deferred income taxes ........................................ 902,868 543,391 ------------ ----------- Total Liabilities ......................................... 8,978,924 7,598,040 ------------ ----------- Deferred income .............................................. 65,509 58,468 Minority interest ............................................ 29,127 -- Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts .................. 450,000 553,930 Subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts .................. 101,598 -- Preferred securities of subsidiaries.......................... 146,606 66,033 Commitments and contingencies (Notes 17, 18 and 19) Stockholders' Equity: Preferred Stock - authorized 2,000 shares, no par value ...... -- -- Common stock - authorized 180,000 shares no par value; 82,980 shares issued, 59,944 and 59,605 shares outstanding, at December 31, 1999 and 1998, respectively ................ -- -- Additional paid in capital ................................... 1,249,079 1,238,690 Retained earnings ............................................ 507,726 340,496 Accumulated other comprehensive income ....................... (12,029) 45 Treasury stock - 23,036 and 23,375 common shares at December 31, 1999 and 1998, respectively, at cost .......... (750,188) (752,178) ------------ ----------- Total Stockholders' Equity ................................ 994,588 827,053 ------------ ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................... $ 10,766,352 $ 9,103,524 ============ ===========
The accompanying notes are an integral part of these financial statements. -59- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ---------------------------------------- 1999 1998 1997 ----------- ----------- ----------- REVENUE: Operating revenue ................................... $ 4,128,737 $ 2,555,206 $ 2,166,338 Interest and other income ........................... 131,342 127,505 104,573 Gains on non-recurring items ........................ 138,704 -- -- ----------- ----------- ----------- TOTAL REVENUES ........................................ 4,398,783 2,682,711 2,270,911 ----------- ----------- ----------- COSTS AND EXPENSES: Cost of sales ....................................... 2,143,891 1,258,539 1,055,195 Operating expense ................................... 989,551 471,405 398,538 Depreciation and amortization ....................... 427,690 333,422 276,041 Loss on equity investment in Casecanan .............. -- -- 5,972 Interest expense .................................... 496,578 406,084 296,364 Less interest capitalized ........................... (70,405) (58,792) (45,059) Losses on non-recurring items........................ 54,409 -- 87,000 ----------- ----------- ----------- TOTAL COSTS AND EXPENSES .............................. 4,041,714 2,410,658 2,074,051 ----------- ----------- ----------- Income before provision for income taxes .............. 357,069 272,053 196,860 Provision for income taxes ............................ 93,475 93,265 99,044 ----------- ----------- ----------- Income before minority interest ....................... 263,594 178,788 97,816 Minority interest ..................................... 46,923 41,276 45,993 ----------- ----------- ----------- INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE.. 216,671 137,512 51,823 Extraordinary item, net of tax ........................ (49,441) (7,146) (135,850) Cumulative effect of change in accounting principle, net of tax ............................... -- (3,363) -- ----------- ----------- ----------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS .... $ 167,230 $ 127,003 $ (84,027) =========== =========== =========== INCOME PER SHARE BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE - BASIC .................................. $ 3.62 $ 2.29 $ 0.77 Extraordinary item .................................... (.83) (.12) (2.02) Cumulative effect of change in accounting principle ... -- (.06) -- ----------- ----------- ----------- INCOME (LOSS) PER SHARE - BASIC ....................... $ 2.79 $ 2.11 $ (1.25) =========== =========== =========== INCOME PER SHARE BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE - DILUTED ................................ $ 3.28 $ 2.15 $ 0.75 Extraordinary item .................................... (.69) (.10) (1.97) Cumulative effect of change in accounting principle ... -- (.04) -- ----------- ----------- ----------- INCOME (LOSS) PER SHARE - DILUTED ..................... $ 2.59 $ 2.01 $ (1.22) =========== =========== ===========
The accompanying notes are an integral part of these financial statements. -60- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY For the Three Years Ended December 31, 1999 (In thousands)
ADDITIONAL COMMON OTHER STOCK OUTSTANDING ADDITIONAL COMPRE- & OPTIONS UNEARNED COMMON COMMON PAID-IN RETAINED HENSIVE SUBJECT TO TREASURY COMPEN- SHARES STOCK CAPITAL EARNINGS INCOME REDEMPTION STOCK SATION TOTAL ----------- ------ ---------- -------- -------- ---------- --------- -------- --------- BALANCE DECEMBER 31, 1996 63,448 $ -- $ 567,870 $297,520 $ 29,658 $ -- $ (8,787) $(5,471) $880,790 Net loss -- -- -- (84,027) -- -- -- -- (84,027) Other Comprehensive Income Foreign currency translation adjustment * -- -- -- -- (33,247) -- -- -- (33,247) -------- Comprehensive loss (117,274) Equity offering 19,100 -- 698,604 -- -- -- -- -- 698,604 Exercise of stock options and other equity transactions 396 -- (2,747) -- -- -- 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 __________________________________________________________________________________________________________________________________ BALANCE DECEMBER 31, 1997 81,322 -- 1,266,683 213,493 (3,589) (654,736) (56,525) -- 765,326 Net income -- -- -- 127,003 -- -- -- -- 127,003 Other Comprehensive Income: Foreign currency translation adjustment * -- -- -- -- 3,634 -- -- -- 3,634 -------- Comprehensive income 130,637 Exercise of stock options and other equity transactions 226 -- (7,841) -- -- -- 7,825 -- (16) Purchase of treasury stock (21,943) -- (21,313) -- -- -- (703,478) -- (724,791) Common stock and options subject to redemption -- -- -- -- -- 654,736 -- -- 654,736 Tax benefit from stock plan -- -- 1,161 -- -- -- -- -- 1,161 __________________________________________________________________________________________________________________________________ BALANCE DECEMBER 31, 1998 59,605 -- 1,238,690 340,496 45 -- (752,178) -- 827,053 Net income -- -- -- 167,230 -- -- -- -- 167,230 Other Comprehensive Income Foreign currency translation adjustment * -- -- -- -- (12,047) -- -- -- (12,047) Unrealized losses on securities, net of tax of $14 -- -- -- -- (27) -- -- -- (27) -------- Comprehensive income 155,156 Issuance of stock by subsidiary -- -- 9,113 -- -- -- -- -- 9,113 Exercise of stock options and other equity transactions 238 -- (2,628) -- -- -- 7,779 -- 5,151 Purchase of treasury stock (3,376) -- -- -- -- -- (104,847) -- (104,847) Conversion of TIDES I 3,477 -- 2,845 -- -- -- 99,058 -- 101,903 Tax benefit from stock plan -- -- 1,059 -- -- -- -- -- 1,059 __________________________________________________________________________________________________________________________________ BALANCE DECEMBER 31, 1999 59,944 $ -- $1,249,079 $507,726 $(12,029) $ -- $(750,188) $ -- $ 994,588 __________________________________________________________________________________________________________________________________ * Foreign currency translation adjustment has no tax effect
The accompanying notes are an integral part of these financial statements -61- MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------------------- 1999 1998 1997 ----------- ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) ...................................................... $ 167,230 $ 127,003 $ (84,027) Adjustments to reconcile net cash flow from operating activities: Gains on non-recurring items ........................................ (138,704) -- -- Non-recurring charge-asset valuation impairment ..................... -- -- 87,000 Extraordinary item, net of tax ...................................... 49,441 7,146 -- Cumulative effect of change in accounting principle ................. -- 3,363 -- Depreciation and amortization ....................................... 363,737 290,794 239,234 Amortization of excess of cost over fair value of net assets acquired 63,953 42,628 36,807 Amortization of deferred financing and other costs .................. 18,181 21,723 33,792 Provision for deferred income taxes ................................. (56,590) 34,332 55,584 Distributions in excess of (less than) income on equity investments . (22,796) 6,171 7,892 Income (loss) applicable to minority interest ....................... 14,240 5,313 (35,387) Changes in other items: Accounts receivable ............................................... 61,209 (135,124) (34,146) Accounts payable, accrued liabilities and deferred income ......... 32,917 (41,803) 29,799 ----------- ----------- ----------- NET CASH FLOWS FROM OPERATING ACTIVITIES ............................... 552,818 361,546 336,548 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Purchase of MidAmerican, Kiewit's Interests and Northern, net of cash acquired ................................................ (2,501,425) (500,916) (632,014) Proceeds from sale of QF's, net of cash disposed ....................... 365,074 -- -- Proceeds from Indonesia settlement ..................................... 290,000 -- -- Purchase of marketable securities ...................................... (92,523) -- -- Proceeds from sale of marketable securities ............................ 498,676 -- -- Capital expenditures relating to operating projects .................... (331,337) (227,071) (194,224) Philippine construction ................................................ (62,059) (112,263) (27,334) Acquisition of U.K. gas assets ......................................... (72,280) (35,677) -- Domestic construction and other development costs ...................... (180,683) (119,916) (159,091) Decrease (increase) in restricted cash and investments ................. 199,588 20,568 (116,668) Other .................................................................. (58,263) (32,505) 63,270 ----------- ----------- ----------- NET CASH FLOWS FROM INVESTING ACTIVITIES ............................... (1,945,232) (1,007,780) (1,066,061) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from sale of common and treasury stock and exercise of stock options ...................................... 5,482 3,412 703,624 Proceeds from convertible preferred securities of subsidiary trusts .... -- -- 450,000 Proceeds from issuance of parent company debt .......................... -- 1,502,243 350,000 Repayment of parent company debt ....................................... (853,420) (167,285) (100,000) Net proceeds from revolver ............................................. -- -- (95,000) Proceeds from subsidiary and project debt .............................. 1,429,856 464,974 795,658 Repayments of subsidiary and project debt .............................. (369,016) (255,711) (271,618) Deferred charges relating to debt financing ............................ 7,761 (47,205) (48,395) Purchase of treasury stock ............................................. (104,847) (724,791) (55,505) Other .................................................................. (1,176) 21,701 13,142 ----------- ----------- ----------- NET CASH FLOWS FROM FINANCING ACTIVITIES ............................... 114,640 797,338 1,741,906 ----------- ----------- ----------- Effect of exchange rate changes ........................................ (12,047) 3,634 (33,247) ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents ................... (1,289,821) 154,738 979,146 Cash and cash equivalents at beginning of year ......................... 1,606,148 1,451,410 472,264 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR ............................... $ 316,327 $ 1,606,148 $ 1,451,410 =========== =========== =========== Supplemental Disclosures: Interest paid, net of amount capitalized ............................... $ 439,894 $ 341,645 $ 316,060 =========== =========== =========== Income taxes paid ...................................................... $ 130,875 $ 53,609 $ 44,483 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. -62- MIDAMERICAN ENERGY HOLDINGS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BUSINESS MidAmerican Energy Holdings Company, the successor to CalEnergy Company, Inc. (the "Company" or "MEHC"), is a United States-based privately owned global energy company with publicly traded fixed income securities which generates, distributes and supplies energy to utilities, government entities, retail customers and other customers located throughout the world. Through its subsidiaries the Company is organized and managed on three separate platforms: MIDAMERICAN The MidAmerican Platform consists primarily of the Company's ownership in MidAmerican Energy Company ("MEC"). MEC is the largest energy company headquartered in Iowa and is a regulated public utility principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MEC distributes electricity at retail in Iowa, Illinois, and South Dakota. It also distributes natural gas at retail in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 1999, MEC had 663,500 retail electric customers and 638,000 retail natural gas customers. In addition to retail sales, MEC delivers electric energy to other utilities, marketers and municipalities who distribute it to end-use customers. These sales are referred to as sales for resale or off-system sales. It also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. NORTHERN The operations of Northern Electric plc ("Northern"), an indirect wholly owned subsidiary of the Company, consist primarily of the distribution and supply of electricity, supply of natural gas and other auxiliary businesses in the United Kingdom. Northern receives electricity from the national grid transmission system and distributes it to customers' premises using its 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 delivered electricity through Northern's distribution system, regardless of whether it is supplied by Northern's own supply business or by other suppliers, thus providing Northern with distribution volume that is stable from year to year. Northern charges access fees for the use of the distribution system. The prices for distribution are controlled by a prescribed formula that limits increases (and may require decreases) based upon the rate of inflation in the United Kingdom and other regulatory action. Northern's supply business primarily involves the bulk purchase of electricity, through a central pool, and subsequent resale to individual customers. The supply business generally is a high volume business that tends to operate at lower profitability levels than the distribution business. As of December 31, 1999, Northern supplied electricity to 1,339,000 customers. Northern also competes to supply gas inside and outside its authorized area. In the residential market Northern currently supplies gas to approximately 570,000 customers and is now the fourth largest gas supplier of the new entrants in the U.K. residential market. -63- CALENERGY The CalEnergy Platform is engaged in the development, ownership and operation of environmentally responsible independent power production facilities worldwide utilizing geothermal, natural gas, hydroelectric and other energy sources. Through the Company's 50% owned subsidiary, CE Generation LLC ("CE Generation"), the Company has interests in eight operating geothermal plants in Imperial Valley, California and three operating natural gas fired cogeneration plants in New York, Texas and Arizona. Plant capacity factors for Vulcan, Hoch (Del Ranch), Elmore and Leathers (collectively the "Partnership Projects") are based on 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 Projects") are based on capacity amounts of 10, 20, 49.8 and 39.6 net MW, respectively (the Partnership Projects and the Salton Sea Projects are collectively referred to as the "Imperial Valley Projects"). Plant capacity factors for Saranac, Power Resources and Yuma (collectively the "Gas Plants") are based on capacity amounts of 240, 200 and 50 net MW, respectively. The Company accounts for CE Generation under the equity method. The Company also indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively, the "Philippine Projects"), which are geothermal power plants located on the island of Leyte in the Philippines. Plant capacity amounts for the Upper Mahiao, Malitbog and Mahanagdong Projects are 119, 216 and 165 net MW, respectively. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are less than 50% owned, but 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 from 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. Investments other than restricted cash are primarily commercial paper and money market securities. Restricted cash is not considered a cash equivalent. The current restricted cash and short term investment balance includes commercial paper and money market securities, and is mainly composed of amounts deposited in restricted accounts from which the Company will source its 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. The long-term restricted cash and investment balances are mainly composed of amounts deposited in restricted accounts from which the Company will fund the various projects under construction. The Company's restricted 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 that holds the investments. The Company's nuclear decommissioning trust funds and other marketable securities are classified as available for sale and are accounted for at fair value. -64- PROPERTY, PLANT, 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 that 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. Capitalized costs for gas reserves, other than costs of unevaluated exploration projects and projects awaiting development consent, are depleted using the units 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 estimated useful lives of the developed systems that range from 3 to 15 years. An allowance for the estimated annual decommissioning costs of the Quad Cities Nuclear Power Station (Quad Cities Station) equal to the level of funding is included in depreciation expense. See Note 18 for additional information regarding decommissioning costs. In April 1998, the Accounting Standards Executive Committee issued Statement of Position (SOP) No. 98-5, "Reporting on the Costs of Start-Up Activities." SOP No. 98-5 requires that, at the effective date of adoption, costs of start-up activities previously capitalized be expensed and reported as a cumulative effect of a change in accounting principle, and further requires that such costs subsequent to adoption be expensed as incurred. The Company adopted this standard in 1998 and expensed applicable unamortized start-up costs previously capitalized. The cumulative effect of the change in accounting principle was $3.4 million, net of taxes of $2.2 million. 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 geothermal 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 OF NET ASSETS ACQUIRED Total acquisition costs in excess of the fair values assigned to the net assets acquired are amortized using the straight line method over a 40 year period for the MidAmerican and Northern acquisitions, and a 32 year period for the acquisition of KDG. 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, based on discounted cash flows or various models, whenever evidence exists that the carrying value is not recoverable. -65- REVENUE RECOGNITION Revenues are recorded based upon services rendered and electricity, gas and steam delivered, distributed or supplied to the end of the period. Where there is an over recovery of distribution business revenues against the maximum regulated amount, revenues are deferred equivalent to the over recovered amount. The deferred amount is deducted from revenue and included in other liabilities. Where there is an under recovery, 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 construction projects and 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. 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 does not intend 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 that are intended to be remitted. NET INCOME PER COMMON SHARE 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 and cumulative effect of change in accounting principle to diluted earnings per share before extraordinary item and cumulative effect of change in accounting principle follows (in thousands, except per share amounts):
1999 1998 ------------------------------- ------------------------------- PER SHARE PER SHARE INCOME SHARES AMOUNT INCOME SHARES AMOUNT -------- ------ --------- -------- ------ --------- Basic earnings per share before extraordinary item and cumulative effect of change in accounting principle $216,671 59,929 $3.62 $137,512 60,139 $2.29 Effect of dilutive securities: Stock options .......................... -- 865 -- 634 Convertible preferred securities of subsidiary trusts (1) .................. 19,383 11,154 21,883 13,327 -------- ------ -------- ------ Diluted earnings per share before extraordinary item and cumulative effect of change in accounting principle $236,054 71,948 $3.28 $159,395 74,100 $2.15 ======== ====== ======== ====== ======
-66- 1997 ------------------------------- PER SHARE INCOME SHARES AMOUNT ------- ------ --------- Basic earnings per share before extraordinary item and cumulative effect of change in accounting principle. $51,823 67,268 $0.77 Effect of dilutive securities Stock options............................ - 1,418 Convertible preferred securities of subsidiary trusts (1).................... - - ------- ------ Diluted earnings per share before extraordinary item and cumulative effect of change in accounting principle. $51,823 68,686 $0.75 ======= ====== (1) The convertible preferred securities of subsidiary trusts were antidilutive in 1997. FINANCIAL INSTRUMENTS The Company utilizes swap agreements, contracts for differences and forward purchase agreements to manage market risks and reduce its exposure resulting from fluctuation in interest rates, foreign currency exchange rates and electric and gas prices. For interest rate swap agreements, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment to interest expense. For contracts for differences, the net cash amounts paid or received on the agreements are accrued and recognized as an adjustment to cost of sales. Gains and losses related to gas forward contracts are deferred and included in the measurement of the related gas purchases. The Company's practice is not to hold or issue financial instruments for trading purposes. These instruments are either exchange traded or with counterparties of high credit quality; therefore, the risk of nonperformance by the counterparties is considered to be negligible. FOREIGN CURRENCY TRANSLATION For the Company's foreign operations whose functional currency is not the U.S. dollar, the assets and liabilities are translated into U.S. dollars at current exchange rates. Resulting translation adjustments are reflected as accumulated other comprehensive income in stockholders' equity. Revenues and expenses are translated at average exchange rates for the year. Transaction gains and losses that arise from exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those transactions which operate as a hedge of an identifiable foreign currency commitment or as a hedge of a foreign currency investment position, are included in the results of operations as incurred. RECLASSIFICATION Certain amounts in the fiscal 1998 and 1997 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 1999 presentation. Such reclassification did not impact previously reported net income or retained earnings. USE OF ESTIMATES The preparation of consolidated 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 -67- and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. ACCOUNTING FOR LONG-TERM POWER PURCHASE CONTRACT Under a long-term power purchase contract with Nebraska Public Power District ("NPPD"), expiring in 2004, MEC purchases one-half of the output of the 778-megawatt Cooper Nuclear Station. Other accrued liabilities include a liability for MEC's fixed obligation to pay 50% of NPPD's Nuclear Facility Revenue Bonds and other fixed liabilities. Cooper capital improvement costs prior to 1997, including carrying costs, were deferred in accordance with then applicable rate regulation, and are being amortized and recovered in rates over either a five-year period or the term of the power purchase contract. Beginning July 11, 1997, the Iowa portion of capital improvement costs is recovered currently from customers and is expensed as incurred. MEC began charging the remaining Cooper capital improvement costs to expense for jurisdictions other than Iowa as incurred in January 1997. The fuel cost portion of the power purchase contract is included in costs of sales. All other costs MEC incurs in relation to its long-term power purchase contract with NPPD are included in operating expense. NEW ACCOUNTING PRONOUNCEMENT In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," which established accounting and reporting standards for derivative instruments and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. This statement is effective for the Company in the first quarter of the year 2001. The Company is in the process of evaluating the impact of this accounting pronouncement. 3. BERKSHIRE TRANSACTION On October 24, 1999, the Company and entities representing an investor group comprised of Berkshire Hathaway Inc. ("Berkshire Hathaway"), Walter Scott, Jr., a director of the Company, and David L. Sokol, Chairman and Chief Executive Officer of the Company, executed a definitive agreement and plan of merger whereby the investor group would acquire all of the outstanding common stock of the Company for $35.05 per share in cash, representing a total purchase price of approximately $2.2 billion, including transaction costs. The Berkshire Transaction closed on March 14, 2000 and Berkshire Hathaway invested approximately $1.24 billion in common stock and convertible preferred stock and approximately $455 million in nontransferable trust preferred stock. Mr. Scott, Mr. Sokol and Gregory E. Abel, Chief Operating Officer of the Company, contributed cash and current securities of the Company having a value of approximately $310 million. The remaining purchase price was funded with the Company's cash. Berkshire Hathaway owns not more than 9.9% of the voting stock, Mr. Scott owns approximately 86% of the voting stock, Mr. Sokol owns approximately 3% of the voting stock and Mr. Abel owns approximately 1% of the voting stock. The Company incurred approximately $6.7 million of non-recurring costs in 1999, related to the Berkshire transaction, which were expensed. 4. ACQUISITIONS/DISPOSITIONS MIDAMERICAN MERGER On August 11, 1998, the Company entered into an Agreement and Plan of Merger with MHC Inc., formerly MidAmerican Energy Holdings Company ("MHC"). The MidAmerican Merger closed on March 12, 1999 and the -68- Company paid $27.15 in cash for each outstanding share of MHC common stock for a total of approximately $2.42 billion in a merger, pursuant to which MHC became an indirect wholly owned subsidiary of the Company. Additionally, the Company reincorporated in the State of Iowa, was renamed MidAmerican Energy Holdings Company and, upon closing, became an exempt public utility holding company. The consummation of the MidAmerican Merger was conditioned upon receipt of a number of regulatory and shareholder approvals and the disposition of partial interests in certain of the Company's power generating facilities in order to maintain the qualifying facilities status of such independent power generating facilities. See discussion of Qualified Facilities Dispositions below. The MidAmerican Merger has been accounted for as a purchase business combination and as such the results of operations of the Company include the results of MHC beginning March 12, 1999. The purchase price has been allocated to assets acquired and liabilities assumed based on preliminary valuations. The final purchase price allocation has not been completed, however, the Company does not anticipate any material changes based on currently available information. The Company recorded goodwill of approximately $1.5 billion, which is being amortized using the straight-line method over a 40-year period. Unaudited pro forma combined revenue, income before extraordinary item, net income and basic earnings per share of the Company and MHC for the years ended December 31, 1999 and 1998, as if the acquisition had occurred at the beginning of each year after giving effect to certain pro forma adjustments related to the acquisition and including the sales of the qualified facilities, the issuance of senior secured notes and bonds and the redemptions of certain limited recourse notes and senior discount notes, were $4.81 billion, $230.6 million, $181.3 million and $3.03, respectively, compared to $4.13 billion, $97.3 million, $97.3 million and $1.62, respectively. QUALIFIED FACILITIES DISPOSITIONS The consummation of the MidAmerican Merger was conditioned upon receipt of a number of regulatory approvals. Regulatory approval required the disposition of partial interests in certain of the Company's independent power generating facilities prior to the consummation of the MidAmerican Merger in order to maintain the qualifying facilities status of such power generating facilities. To accomplish this disposition, the following events occurred in the first quarter of 1999: On February 26, 1999, the Company closed the sale of all of its indirect ownership interests in the Coso Joint Ventures ("Coso") to Caithness Energy LLC ("Caithness") for $205 million in cash. On February 8, 1999, the Company created a new subsidiary, CE Generation LLC ("CE Generation") and subsequently transferred its interest in the Company's power generation assets in the Imperial Valley Projects and the Gas Plants to CE Generation. On March 2, 1999, CE Generation closed the sale of $400 million aggregate principal amount of its 7.416% Senior Secured Bonds due in 2018 and distributed the proceeds to the Company. On March 3, 1999, the Company closed the sale of 50% of its ownership interests in CE Generation to an affiliate of El Paso Energy Corporation for an aggregate consideration of approximately $245 million in cash, $6.5 million in contingent payments and $23.5 million in equity commitments. Due to the sale of 50% of its interests in CE Generation, the Company has accounted for CE Generation as an equity investment beginning March 3, 1999. The sales of the qualified facilities resulted in a net non-recurring pre-tax gain of $20.2 million and an after-tax gain of approximately $12.4 million or $0.17 per diluted share. MCLEOD On May 18, 1999, the Company announced the sale of approximately 6.74 million shares of McLeodUSA ("McLeod") Class A common stock, through a secondary offering by McLeod, at $55.625 per share. Proceeds from -69- the sale were approximately $375 million, with a resulting pre-tax gain to the Company of approximately $78.2 million, and an after-tax gain of approximately $47.1 million or $0.65 per diluted share. HOMESERVICES.COM On October 18, 1999, the Company closed on its initial public offering of 3.25 million shares of common stock of HomeServices.Com ("HomeServices"), previously a wholly-owned subsidiary of the Company, at $15 per share. HomeServices sold 2.19 million newly issued shares and the Company, the selling stockholder, sold 1.06 million of its HomeServices shares in the offering. The offering reduced the Company's ownership in HomeServices to approximately 65%. The Company recognized a pre-tax gain on the sale of its HomeServices stock of $7.9 million, which is reported in interest and other income. The Company recognized a gain for HomeServices' sale of newly issued stock of $9.1 million, net of deferred tax of $0.8 million, which was recorded as a credit to additional paid in capital. KDG On January 2, 1998, the Company completed the purchase of Kiewit Diversified Group's ("KDG") ownership interest in various project partnerships and common shares of the Company (the "KDG Acquisition") for a cash price of approximately $1.16 billion, including transaction costs. KDG's ownership interest in the Company comprised approximately 20.2 million shares of common stock (assuming exercise by KDG of one million options to purchase the Company's shares), a 30% interest in Northern, as well as the following minority project interests: Mahanagdong (45%), Casecnan (35%), Dieng (47%), Patuha (44%), Bali (30%) and other interests in international development stage projects. INDONESIA On December 2, 1994, subsidiaries of the Company, Himpurna California Energy Ltd. ("HCE") and Patuha Power, Ltd. ("PPL", together with HCE, the "Indonesian Subsidiaries") executed separate joint operation contracts for the development of geothermal steam fields and geothermal power facilities located in Central Java in Indonesia with Perusahaan Petambangan Minyak Dan Gas Gumi Negara ("Pertamina"), the Indonesian national oil company, and executed separate "take-or-pay" energy sales contracts ("ESCs") with both Pertamina and P.T. PLN (Persero) ("PLN"), the Indonesian national electric utility. The Government of Indonesia provided sovereign performance undertakings of the obligations under the joint operating and "take-or-pay" contracts. In 1997 and 1998 a series of Indonesian government decrees and other actions (including the non-payment of all monthly invoices from HCE's Dieng Unit I, which became operational in March 1998) created significant uncertainty as to whether PLN and the Indonesian government would honor their contractual obligations to the Indonesian Subsidiaries. In 1997, the Company recorded a non-recurring charge of $87 million representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to the Company's assets in Indonesia. The charge of $87 million represented the amount by which the carrying amount of such assets exceeded the estimated 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. On or about August 14, 1998, the Company, through the Indonesian Subsidiaries, began arbitration proceedings against PLN in connection with the HCE's and PPL's geothermal power projects in Indonesia, the Dieng Project and the Patuha Project. An arbitral tribunal found that PLN had materially breached the provisions of the ESCs between PLN and both HCE and PPL, and awarded HCE approximately $391.7 million and PPL $180.6 million, and ordered PLN to pay these amounts immediately. -70- Following PLN's failure to pay such amounts, HCE and PPL demanded payment pursuant to the sovereign performance undertakings issued by the Minister of Finance ("MOF") on behalf of the Republic of Indonesia ("ROI") and, following the ROI's failure to pay, brought an arbitration against the ROI for breach of those undertakings. A final award was issued by an international arbitration panel in the ROI arbitration on October 15, 1999 which found that the ROI materially breached its performance undertakings and violated international law, and the ROI was required to pay HCE and PPL an aggregate amount of approximately $575 million. The Company carried political risk insurance on its investment in HCE and PPL through the Overseas Private Investment Corporation ("OPIC"), an agency of the U.S. Government, as well as through private market insurers. Such insurance covered expropriation of the Company's investment in HCE and PPL, as well as material breaches by PLN of the ESCs and by the ROI of its performance undertakings. On November 18, 1999, the Company received payment from OPIC and the private market insurers totaling $290 million under its political risk insurance policies, reflecting the return of its equity investment less policy deductibles. Due primarily to the timing of the receipt of proceeds, the Company recorded a pre-tax gain of approximately $40.3 million on the insurance proceeds and an additional tax benefit of $17.7 million for an after-tax gain of $58.0 million, or $0.81 per diluted share. 5. PROPERTY, PLANT, CONTRACTS AND EQUIPMENT: Property, plant, contracts and equipment comprise the following at December 31 (in thousands):
1999 1998 ----------- ----------- Operating assets: Utility generation and distribution system ......... $ 3,996,389 $ 1,305,806 Independent power plants ........................... 705,346 1,868,002 Wells and resource development ..................... 123,845 473,237 Power sales agreements ............................. -- 193,868 Other assets ....................................... 377,897 313,029 ----------- ----------- Total operating assets ............................. 5,203,477 4,153,942 Less accumulated depreciation and amortization ..... (695,801) (769,526) ----------- ----------- Net operating assets ............................... 4,507,676 3,384,416 Mineral and gas reserves and exploration assets, net 476,416 375,208 Construction in progress: Casecnan ...................................... 306,007 243,948 Zinc recovery project ......................... 92,794 24,183 Cordova ....................................... 79,982 -- Indonesia and other ........................... 454 208,284 ----------- ----------- TOTAL .............................................. $ 5,463,329 $ 4,236,039 =========== ===========
MINERALS EXTRACTION The Company developed and owns the rights to proprietary processes 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 Projects. The Company intends to sequentially develop facilities for the extraction of manganese, silver, gold, lead, boron, lithium and other products as it further develops the extraction technology. The Company is also investigating producing silica as an extraction project. Silica is used as a filler for such products as paint, plastics and high temperature cement. -71- CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company, is constructing the Zinc Recovery Project that will recover zinc from the geothermal brine (the "Zinc Recovery Project"). Facilities will be installed near the Imperial Valley Projects sites to extract a zinc chloride solution from the geothermal brine through an ion exchange process. This solution will be transported to a central processing plant where zinc ingots will be produced through solvent extraction, electrowinning and casting processes. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operation in mid-2000. In September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby all zinc produced by the Zinc Recovery Project will be sold to Cominco, LTD. The initial term of the agreement expires in December 2005. The Zinc Recovery Project is being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procurement and construction contract (the "Zinc Recovery Project EPC Contract"). Kvaerner is a wholly owned indirect subsidiary of Kvaerner ASA, an international engineering and construction firm experienced in the metals, mining and processing industries. Total project costs of the Zinc Recovery Project are expected to be approximately $200.9 million. CASECNAN CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE Casecnan") which at completion of the Casecnan Project is expected to be at least 70% indirectly owned by the Company, is constructing 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 has entered into a fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Casecnan Construction Contract"). The work under the Casecnan Construction Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. On November 20, 1999, pursuant to an amendment of the Casecnan Construction Contract which was approved by the independent engineer under the Bond Indenture, the Guaranteed Substantial Completion Date for the Casecnan Project was extended to March 31, 2001. Accordingly, the Casecnan Project is now expected to become operational by the second quarter of 2001. CORDOVA Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, has commenced construction of a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). Cordova Energy has entered into an engineering, procurement and construction contract with Stone & Webster Engineering Corporation ("SWEC") to build the project. Total project costs are estimated to be approximately $288.9 million. The Company has also entered into a power sales agreement with a unit of El Paso Energy Corporation ("El Paso"). Under the power sales agreement, El Paso will purchase all the capacity and energy from the project until December 31, 2019. However, Cordova Energy has the option to elect on an annual basis to retain up to 50% of the project output for sales to others. The construction of the Cordova Project is expected to be completed in mid-2001. -72- 6. PARENT COMPANY DEBT Parent company debt comprises the following at December 31 (in thousands): 1999 1998 ---------- ---------- Senior Discount Notes ............... $ -- $ 369,501 9.5% Senior Notes ................... 32 224,265 7.63% Senior Notes .................. 350,000 350,000 Limited Recourse Senior Secured Notes 4,225 200,000 $1.4 Billion Senior Notes ........... 1,400,000 1,400,000 $100 Million Senior Notes ........... 102,061 102,225 ---------- ---------- $1,856,318 $2,645,991 ========== ========== SENIOR DISCOUNT NOTES In March 1994, the Company issued $400 million of 10.25% Senior Discount Notes which accreted to an aggregate principal amount of $529.6 million 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 was payable semiannually on January 15 and July 15 of each year, commencing July 15, 1997. During 1998, the Company repurchased and retired $160.1 million of the notes at an average price of 106.173% plus accrued interest. The remainder of the Senior Discount Notes were subsequently redeemed on January 15, 1999 at a redemption price of 105.125% plus accrued interest. Due to the early extinguishment of the Senior Discount Notes, the Company recorded extraordinary losses, net of tax, of $14.0 million and $7.1 million in 1999 and 1998 respectively. 9.5% SENIOR NOTES On September 20, 1996, the Company issued $225 million of 9.5% Senior Notes (the "9.5% Senior Notes") due in 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. During 1999, the Company repurchased and retired substantially all of the notes at an average price of 110.055% plus accrued interest. Due to the early extinguishments of the 9.5% Senior Notes, the Company recorded an extraordinary loss in 1999 of $17.9 million, net of tax. The 9.5% Senior Notes are unsecured senior obligations of the Company. 7.63% SENIOR NOTES On October 28, 1997, the Company issued $350 million of 7.63% Senior Notes (the "7.63% Senior Notes") due in 2007. Interest on the 7.63% Senior Notes is 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 million of 9 7/8% Limited Recourse Senior Secured Notes due in 2003 (the "Limited Recourse Notes"). Interest on the Limited Recourse Notes is payable on June 30 and December 30 of each year, commencing December 1995. The Limited Recourse 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 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, 1999. On January 29, 1999, the Company commenced a cash offer for all of its outstanding Limited Recourse Notes. The Company received tenders from holders of an aggregate of approximately $195.8 million of principal which were -73- paid on March 3, 1999 at a redemption price of 110.025% plus accrued interest. Due to early extinguishments of the Limited Recourse Notes, the Company recorded an extraordinary loss of $17.5 million, net of tax. On or after June 30, 2000, the remaining Limited Recourse 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. The Company expects to redeem the remaining Limited Recourse Notes on or about June 30, 2000. $1.4 BILLION SENIOR NOTES On September 22, 1998, the Company issued $215 million of 6.96% Senior Notes due in 2003, $260 million of 7.23% Senior Notes due in 2005, $450 million of 7.52% Senior Notes due in 2008, and $475 million of 8.48% Senior Bonds due in 2028 (collectively, the "$1.4 Billion Senior Notes"). Interest on the $1.4 Billion Senior Notes is payable semiannually on March 15 and September 15 of each year, commencing March 15, 1999. The $1.4 Billion Senior Notes are unsecured senior obligations of the Company. $100 MILLION SENIOR NOTES On November 13, 1998 the Company issued $100 million at a premium of approximately 102.243% of 7.52% Senior Notes (the "$100 Million Senior Notes") due in 2008. Interest on the $100 Million Senior Notes is payable semiannually on March 15 and September 15 of each year, commencing March 15, 1999. The $100 Million Senior Notes are unsecured senior obligations of the Company. REVOLVING CREDIT FACILITY The Company has available a $400 million revolving credit facility expiring in November 2000. The facility is unsecured and is available to fund working capital requirements and finance future business expansion opportunities. There was no outstanding balance under this revolving credit facility as of December 31, 1999. 7. SUBSIDIARY AND PROJECT DEBT Project loans held by subsidiaries and projects comprise the following at December 31 (in thousands):
1999 1998 ---------- ---------- MidAmerican Funding, LLC Senior Notes and Bonds .............. $ 702,089 $ -- MEC Mortgage Bonds ........................................... 450,570 -- MEC Pollution Control Bonds .................................. 157,129 -- MEC Notes .................................................... 262,240 -- MEC Commercial Paper ......................................... 204,000 -- MidAmerican Capital Notes .................................... 70,098 -- HomeServices Senior Notes and Revolving Debt ................. 48,817 -- Salton Sea Notes and Bonds ................................... 140,520 626,816 Northern Eurobonds ........................................... 324,850 426,785 CE Electric UK Funding Company Senior Notes and Sterling Bonds 670,327 684,986 Casecnan Notes and Bonds ..................................... 363,085 371,500 Philippine Term Loans ........................................ 449,739 517,998 Northern Short Term Treasury Loan ............................ 174,593 72,740 Cordova Funding Senior Secured Bonds ......................... 124,824 -- CE Gas Loan .................................................. 113,267 41,355 CE Indonesia Funding Corp. Construction Loans, Power Resources and Coso Funding Corp. Project Debt and Other .... 1,280 351,630 ---------- ---------- $4,257,428 $3,093,810 ========== ==========
-74- 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 Northern, MHC, HomeServices or the Imperial Valley, Saranac, Power Resources, Mahanagdong, Malitbog, Upper Mahiao, Casecnan, and Cordova projects or (2) owning interests in the subsidiaries that own interests in the foregoing subsidiaries or projects. MIDAMERICAN FUNDING, LLC SENIOR NOTES AND BONDS On March 11, 1999, MidAmerican Funding, LLC, a wholly owned subsidiary of the Company, issued $200 million of 5.85% Senior Secured Notes due in 2001, $175 million of 6.339% Senior Secured Notes due in 2009, and $325 million of 6.927% Senior Secured Bonds due in 2029. The proceeds from the offering were used to complete the MidAmerican Merger. MEC MORTGAGE BONDS, POLLUTION CONTROL BONDS AND NOTES The components of MEC's Mortgage Bonds, Pollution Control Bonds and Notes at December 31, 1999 are as follows (in thousands): Mortgage bonds: 6% Series, due 2000......................................... $ 35,000 6.75% Series, due 2000...................................... 75,000 7.125% Series, due 2003..................................... 100,000 7.70% Series, due 2004...................................... 55,630 7% Series, due 2005......................................... 90,500 7.375% Series, due 2008..................................... 75,000 7.45% Series, due 2023...................................... 6,940 6.95% Series, due 2025...................................... 12,500 -------- $450,570 ======== Pollution control revenue obligations: 5.75% Series, due periodically through 2003................. $ 7,704 5.95% Series, due 2023 (secured by general mortgage bonds).. 29,030 Variable rate series - Due 2016 and 2017, 3.95% ................................ 37,600 Due 2023 (secured by general mortgage bond, 3.95%)....... 28,295 Due 2023, 3.95%.......................................... 6,850 Due 2024, 3.95%.......................................... 34,900 Due 2025, 3.95%.......................................... 12,750 -------- $157,129 ======== Notes: 8.75% Series, due 2002...................................... $ 240 6.5% Series, due 2001....................................... 100,000 6.375% Series, due 2006..................................... 160,000 6.7% Series, due 2003....................................... 1,000 6.1% Series, due 2007....................................... 1,000 -------- $262,240 ======== MEC COMMERCIAL PAPER MEC has authority from the Federal Energy Regulatory Commission ("FERC") to issue short-term debt in the form of commercial paper and bank notes aggregating $400 million for interim financing of working capital needs. As of December 31, 1999, MEC had a $250 million revolving credit facility and lines of credit totaling $95 million -75- and MHC had lines of credit totaling $24 million. MEC's commercial paper borrowings are supported by the revolving credit facility and the lines of credit. As of December 31, 1999, commercial paper and bank notes totaled $204 million for MEC with a weighted average interest rate of 6.3%. MIDAMERICAN CAPITAL NOTES MidAmerican Capital Company, a wholly owned subsidiary of the Company, has debt of $70 million of 8.52% Senior Notes. These notes are due in annual increments of $23.3 million beginning in 2000 with final payment in 2002. HOMESERVICES SENIOR NOTES AND REVOLVING DEBT HomeServices debt includes $35 million of 7.12% Senior Notes due in annual increments of $5 million beginning in 2004. HomeServices also obtained a $75 million senior secured revolving credit facility of which HomeServices had drawn down $11 million as of December 31, 1999. This credit agreement has a variable interest rate at either the prime lending rate or LIBOR plus a fixed spread of 1.25% to 2.50% that varies based on HomeServices' cash flow leverage ratio, as defined in the agreement. As of December 31, 1999, the blended average interest rate on the senior secured revolving credit facility borrowings was 8.08%. SALTON SEA NOTES AND BONDS As the Company's interest in Salton Sea Funding Corporation was transferred to CE Generation, the balance of Salton Sea Notes and Bonds as of December 31, 1998 of $626.8 million is included in the Company's equity investment in CE Generation as of December 31, 1999. However, the Company retained CalEnergy Minerals LLC, which is one of the guarantors of this debt. As a result of a note allocation agreement, CalEnergy Minerals LLC is primarily responsible for $140.52 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018. The Company has guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to the current principal amount of $140.52 million and associated interest. NORTHERN EUROBONDS The balance at December 31, 1999 and 1998 consists of the following (in thousands): 1999 1998 -------- -------- 12.661% Debenture due 1999 ................... $ -- $ 94,393 8.625% Bearer bonds due 2005 ................. 162,512 166,286 8.875% Bearer bonds due 2020 ................. 162,338 166,106 -------- -------- $324,850 $426,785 ======== ======== 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 "CE Electric UK Funding Company"), issued the Senior Notes and Sterling Bonds. The balances at December 31 are comprised of the following (in thousands): 1999 1998 -------- -------- 6.853% Senior Notes due 2004 ................. $121,754 $124,376 6.995% Senior Notes due 2007 ................. 230,662 235,694 7.25% Sterling Bonds due 2022 ................ 317,911 324,916 -------- -------- $670,327 $684,986 ======== ======== -76- 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 CE Electric UK Funding Company or the long term debt rating falls below a prescribed level. 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 million 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 million 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 $12.1 million based on quotes from the counterparty 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 these swap agreements to maturity. CASECNAN NOTES AND BONDS On November 27, 1995, CE Casecnan issued $371.5 million of notes and bonds to finance the construction of the Casecnan Project. These consist of $75 million Senior Secured Floating Rate Notes (FRNs) due in 2002; $125 million Senior Secured Series A Notes (Series A Notes) with interest at 11.45% due in 2005; and $171.5 million Senior Secured Series B Bonds (Series B Bonds) with interest at 11.95% due in 2010. Quarterly interest payments for the FRNs commenced on February 15, 1996, and semiannual interest payments for Series A Notes and Series B Bonds commenced on May 15, 1996. During 1999, the Company purchased $8.4 million of the FRNs. The Casecnan Notes and Bonds are subject to redemption at the Company's option as provided for in the Trust Indenture. The Casecnan Notes and Bonds are also subject to mandatory redemption based on certain conditions. PHILIPPINE TERM LOANS On April 8, 1998, the Company converted the construction project financing for its Malitbog geothermal power project to term loans. OPIC is providing term loan financing of $46.8 million that was fixed as of June 15, 1998 at an interest rate of 9.176%. A syndicate of international commercial banks is providing term loan financing of $84.4 million at a variable interest rate based on LIBOR (8.37% at December 31, 1999). The loans have scheduled repayments through June 2005. On May 5, 1998, the Company converted the construction project financing for its Upper Mahiao geothermal power project to term loans. Export-Import Bank of the United States ("Ex-Im Bank") is providing term loan financing of $121.3 million at a fixed interest rate of 5.95%. United Coconut Planters Bank of the Philippines is providing term loan financing of $8.3 million at a variable interest rate based on LIBOR (9.10% at December 31, 1999). The loans have scheduled repayments through June 2006. On June 18, 1998, the Company converted the construction project financing for its Mahanagdong geothermal power project to term loans. Ex-Im Bank is providing term loan financing of $154.6 million at a fixed rate of 6.92%. OPIC is providing term loan financing of $34.3 million that was fixed as of September 30, 1998 at an interest rate of 7.6%. The loans have scheduled repayments through June 2007. NORTHERN SHORT TERM TREASURY LOAN Northern had short-term money market loans in place at December 31, 1999 and 1998 of $174.6 million and $72.7 million, respectively. The amounts have varying maturities generally less than one month and carry variable interest rates based on LIBOR and ranging from 5.58% to 6.19% at December 31, 1999. -77- CORDOVA FUNDING SENIOR SECURED BONDS On September 10, 1999 Cordova Funding Corporation ("Cordova Funding"), a wholly owned subsidiary of the Company, closed the $225 million aggregate principal amount financing for the construction of the Cordova Project. As part of the financing, approximately $93.5 million of 8.64% Series A-1 Senior Secured Bonds due in 2019 were issued. An additional $31.3 million of 8.79% Series A-2 Senior Secured Bonds due in 2019 were issued on December 15, 1999. Additional Series A Senior Secured Bonds will be issued as required to fund construction. Cordova Funding will loan the proceeds to Cordova Energy as required. CE GAS LOAN CE Gas, a wholly owned subsidiary of the Company, had borrowed $113.3 million and $41.4 million on a 70 million pounds sterling revolving facility at December 31, 1999 and 1998, respectively, to fund the purchases of certain UK gas assets in the North Sea. The amount carries a variable interest rate based on LIBOR (7.055% at December 31, 1999). The revolving facility was completely utilized at December 31, 1999. ANNUAL REPAYMENTS OF SUBSIDIARY AND PROJECT DEBT The annual repayments of the subsidiary and project debt for the years beginning January 1, 2000 and thereafter are as follows (in thousands):
MIDAMERICAN MIDAMERICAN FUNDING, MIDAMERICAN ENERGY NOTES, LLC MIDAMERICAN ENERGY COMMERCIAL HOMESERVICES SENIOR ENERGY POLLUTION PAPER & SENIOR NOTES SALTON NOTES AND MORTGAGE CONTROL MIDAMERICAN AND REVOLVING SEA NORTHERN BONDS BONDS BONDS CAPITAL NOTES DEBT BONDS EUROBONDS --------- ----------- ----------- ------------- ------------- -------- --------- 2000 $ - $110,000 $ 504 $227,578 $ 707 $ - $ - 2001 200,000 - 1,440 123,333 730 632 - 2002 - - 1,440 23,574 11,694 2,108 - 2003 - 100,000 5,320 - 482 1,405 - 2004 - 55,630 - - 5,084 1,757 - Thereafter 502,089 184,940 148,425 162,203 30,120 134,618 324,850 -------- -------- -------- --------- ------- -------- -------- $702,089 $450,570 $157,129 $536,688 $48,817 $140,520 $324,850 ======== ======== ======== ======== ======= ======== ========
CE ELECTRIC UK FUNDING COMPANY NORTHERN CORDOVA SENIOR SHORT TERM FUNDING NOTES AND TREASURY CASECNAN PHILIPPINE SENIOR STERLING CE LOAN NOTES AND TERM SECURED BONDS GAS LOAN AND OTHER BONDS LOANS BONDS TOTAL -------------- --------- ----------- ---------- ---------- -------- ---------- 2000 $ - $ 15,508 $ 175,523 $ 16,646 $ 68,259 $ - $ 614,725 2001 - 19,340 - 26,301 68,259 - 440,035 2002 - 17,553 - 32,213 68,259 699 157,540 2003 - 21,640 - 41,468 72,148 4,993 247,456 2004 121,754 21,045 - 49,360 67,148 4,494 326,272 Thereafter 548,573 18,181 - 197,097 105,666 114,638 2,471,400 -------- -------- ---------- --------- --------- -------- ---------- $670,327 $113,267 $ 175,523 $ 363,085 $ 449,739 $124,824 $4,257,428 ======== ======== ========== ========= ========= ======== ==========
-78- 8. INCOME TAXES Provision for income taxes was comprised of the following at December 31 (in thousands): 1999 1998 1997 -------- ------- -------- Current: State ............ $ 7,337 $ 5,677 $ 5,084 Federal .......... 128,839 33,160 33,114 Foreign .......... 13,889 20,096 5,262 -------- ------- -------- 150,065 58,933 43,460 -------- ------- -------- Deferred: State ............ 1,791 161 (264) Federal .......... (75,510) 14,973 14,579 Foreign .......... 17,129 19,198 41,269 -------- ------- -------- (56,590) 34,332 55,584 -------- ------- -------- Total ............ $ 93,475 $93,265 $ 99,044 ======== ======= ======== A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows: 1999 1998 1997 ----- ----- ----- Federal statutory rate ......................... 35.00% 35.00% 35.00% Percentage depletion in excess of cost depletion (.38) (3.52) (3.77) Investment and energy tax credits .............. (1.78) (.93) (.64) State taxes, net of federal tax effect ......... 1.66 1.71 1.59 Goodwill amortization .......................... 5.46 2.51 2.06 Dividends on preferred securities of subsidiary trusts* ........... (3.75) (4.63) (4.12) Tax effect of foreign income ................... .36 1.86 2.64 Non-recurring items on Indonesia ............... (10.99) -- 15.47 Other .......................................... .60 2.28 2.08 ----- ----- ----- Effective tax rate ............................. 26.18% 34.28% 50.31% ===== ===== ===== * Dividends on convertible and non-convertible preferred securities of subsidiary trusts are included in minority interest. Deferred tax liabilities (assets) are comprised of the following at December 31 (in thousands): 1999 1998 ----------- --------- Depreciation and amortization, net ............... $ 983,038 $ 769,376 Income taxes recoverable through future rates .... 187,379 -- Demand side management ........................... 14,805 -- Reacquired debt .................................. 12,476 -- Pensions/profit sharing .......................... -- 22,305 Unremitted foreign earnings ...................... -- 25,393 ----------- --------- 1,197,698 817,074 ----------- --------- Nuclear reserve and decommissioning .............. (20,280) -- Deferred income .................................. (19,502) (9,458) Deferred contract costs .......................... (215,388) (182,745) General business tax credits ..................... -- (21,300) Alternative minimum tax credits .................. -- (44,452) Accruals not currently deductible for tax purposes (32,211) (11,591) Other ............................................ (7,449) (4,137) ----------- --------- (294,830) (273,683) ----------- --------- Net deferred income taxes ........................ $ 902,868 $ 543,391 =========== ========= -79- 9. 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 (in thousands): CONVERSION ISSUER ISSUE DATE RATE AMOUNT 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 $103.9 million, $180 million and $270 million, 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. Prior to the Berkshire transaction, each Trust Security with a par value of $50 was convertible at the option of the holder at any time into shares of the Company's common stock based on the conversion rate. As a result of the Berkshire transaction, in lieu of shares of the Company's common stock, holders of Trust Securities will receive $35.05 for each share of common stock it would have been entitled to receive on conversion. 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. On May 18, 1999, CalEnergy Capital Trust I effected the conversion of $103.9 million of the convertible preferred securities into approximately 3.5 million shares of common stock of the Company. The Securities were converted at a rate equivalent to a conversion price of $29.89 per share of Company common stock. 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. 10. SUBSIDIARY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST In December 1996, MidAmerican Energy Financing I, a wholly owned statutory business trust of MEC, issued 4,000,000 shares of 7.98% Series MEC-obligated mandatorily redeemable preferred securities . The sole assets of MidAmerican Energy Financing are $103.1 million of MEC 7.98% Series A Debentures due 2045 (the "Debentures"). There is a full and unconditional guarantee by MEC of MidAmerican Energy Financing's obligations under the preferred securities. MEC has the right to defer payments of interest on the Debentures by extending the interest payment period for up to 20 consecutive quarters. If interest payments on the Debentures are deferred, distributions on the preferred securities will also be deferred. During any deferral, distributions will -80- continue to accrue with interest thereon, and MEC may not declare or pay any dividend or other distribution on, or redeem or purchase, any of its capital stock. The Debentures may be redeemed by MEC on or after December 18, 2001, or at an earlier time if there is more than an insubstantial risk that interest paid on the Debentures will not be deductible for federal income tax purposes. If the Debentures, or a portion thereof, are redeemed, MidAmerican Energy Financing must redeem a like amount of the preferred securities. If a termination of MidAmerican Energy Financing occurs, MidAmerican Energy Financing will distribute to the holders of the preferred securities a like amount of the Debentures unless such a distribution is determined not to be practicable. If such determination is made, the holders of the preferred securities will be entitled to receive, out of the assets of MidAmerican Energy Financing after satisfaction of its liabilities, a liquidation amount of $25 for each preferred security held plus accrued and unpaid distributions. 11. PREFERRED STOCK 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 are automatically attached to, and trade with, each share of common stock. In 1999, the Board of Directors renewed the Company's shareholder rights plan. The expiration date of the rights plan was extended to September 14, 2009. The amended plan reflects prevailing shareholder rights plan terms. The share ownership level which triggers the exercise of the rights and the flip-in and flip-over features of the rights plan has been reduced to 15% and the exercise price of the rights has been increased to $140 per right. The Berkshire transaction was approved by the Board of Directors and did not trigger the dividend of a preferred share purchase right. 12. STOCK OPTIONS AND RESTRICTED STOCK The Company has various 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 of the common stock at the date of grant. Generally, options are issued at 100% of fair market value of the common stock 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. As a result of the Berkshire transaction, all options, except for David Sokol's and Greg Abel's, were cashed out at $35.05 per share. The Company granted 500 shares of restricted common stock with an aggregate market value of $9.5 million in exchange for the relinquishment of 500 stock options that 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, $5.5 million of unearned compensation was charged to operating expense in 1997. -81- TRANSACTIONS IN STOCK OPTIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
SHARES OPTIONS OUTSTANDING AVAILABLE ------------------------------------------- FOR GRANT UNDER 1996 OPTION PRICE WEIGHTED AVG. OPTION PLAN SHARES PER SHARE OPTION PRICE TOTAL ----------- ------ ---------------- ------------- -------- Balance December 31, 1996 .......... 311 4,777 $ 3.00 - $ 30.38 $ 17.92 $ 85,585 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 Revaluation ................... -- -- 29.00 - 40.81 -- (16,011) Options granted ............... (405) 405 24.22 - 28.75 24.61 9,968 Options terminated ............ 311 (1,311) 3.74 - 25.06 14.71 (19,284) Options exercised ............. -- (164) 3.74 - 24.70 11.41 (1,872) Additional shares reserved under 1996 Option Plan ..... 1,000 -- -- -- -- -- ____________________________________________________________________ Balance December 31, 1998 .......... 1,075 5,710 9.71 - 34.69 24.16 137,953 Options granted ............... (1,106) 1,106 15.10 - 32.56 28.88 31,937 Options terminated ............ 386 (386) 9.71 - 34.69 27.72 (10,689) Options exercised ............. -- (171) 9.71 - 26.29 17.68 (3,018) ____________________________________________________________________ Balance December 31, 1999 .......... 355 6,259 $9.71 - $34.69 $ 24.95 $156,183 ____________________________________________________________________ Options exercisable at: December 31, 1997 3,665 $3.74 - $40.19 $ 18.12 $ 66,425 December 31, 1998 3,167 $9.71 - $34.56 $ 20.55 $ 65,097 December 31, 1999 3,776 $9.71 - $34.56 $ 22.17 $ 83,708
During 1998, the Company revalued certain of its stock options granted in 1996 and 1997 and reduced the exercise price of those options by 15%. The following table summarizes information about stock options outstanding and exercisable as of December 31, 1999 (in thousands, except per share amounts): WEIGHTED WEIGHTED AVERAGE WEIGHTED RANGE OF AVERAGE REMAINING AVERAGE EXERCISED NUMBER EXERCISE CONTRACTUAL NUMBER EXERCISE PRICES OUTSTANDING PRICE LIFE EXERCISABLE PRICE - --------------- ----------- -------- ----------- ----------- -------- $ 9.71 $18.99 1,531 $16.23 4 years 1,529 $16.23 19.00 24.99 1,298 21.30 6 years 906 21.30 25.00 28.99 1,224 28.41 8 years 615 28.42 29.00 34.69 2,206 31.81 9 years 726 31.73 ----- ----- 6,259 24.96 7 years 3,776 22.17 ===== ===== 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, non-cash compensation expense and the effect on net income available to common stockholders and earnings per share would have been approximately $5.5 million or $0.09 per -82- share in 1999, $4.8 million, or $0.08 per share for 1998 and $3.6 million, or $0.05 per share for 1997. The fair value for stock options was estimated using the Black-Scholes option pricing model with the weighted average fair value of options granted during 1999, 1998 and 1997 of $11.17, $7.71 and $9.55 per option, respectively using the following assumptions: 1999 1998 1997 ---- ---- ---- Risk-fee interest rate 5.10% 5.10% 5.50% Expected volatility 31.50% 34.50% 25.00% Expected life 4.8 years 3.4 years 3.7 years Expected dividends 0% 0% 0% 13. EQUITY OFFERING On October 17, 1997, the Company completed the public offering of 17.1 million shares of its common stock at $37 7/8 per share (the "Public Offering"). In addition, 2 million shares of common stock were purchased from the Company in a direct sale by a trust affiliated with Walter Scott (the "Direct Sale"), contemporaneously with the closing of the Public Offering. Proceeds from the Public Offering and the Direct Sale were approximately $699.9 million. 14. UK WINDFALL TAX 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 1997 budget. This amounted to $135.9 million, net of minority interest of $58.2 million, which was recorded as an extraordinary item. The first installment was paid December 1, 1997 and the remainder was paid in 1998. 15. 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. The Company is unable to estimate a fair value for the Philippine term loans and CE Indonesia Funding Corp. construction loans as there are no quoted market prices available. Other financial instruments - All other financial instruments of a material nature are short-term and the fair value approximates the carrying amount. -83-
1999 1998 ---- ---- ESTIMATED ESTIMATED CARRYING FAIR CARRYING FAIR VALUE VALUE VALUE VALUE ---------- ----------- ---------- --------- (IN THOUSANDS) Senior Discount Notes $ -- $ -- $ 369,501 $ 388,438 9.5% Senior Notes 32 34 224,265 243,328 7.63% Senior Notes 350,000 346,220 350,000 372,365 Limited Recourse Senior Secured Notes 4,225 4,449 200,000 217,900 $1.4 Billion Senior Notes 1,400,000 1,396,360 1,400,000 1,495,742 $100 Million Senior Notes 102,061 97,920 102,225 111,973 MidAmerican Funding, LLC Senior Notes and Bonds 702,089 638,101 -- -- MEC Mortgage Bonds 450,570 445,502 -- -- MEC Pollution Control Bonds 157,129 157,868 -- -- MEC Notes 262,240 249,084 -- -- MEC Commercial Paper 204,000 204,000 -- -- MidAmerican Capital Notes 70,098 71,526 -- -- HomeServices Senior Notes and Revolving Debt 48,817 44,862 -- -- Saton Sea Bonds 140,520 128,815 626,816 646,397 Northern Eurobonds 324,850 379,987 426,785 516,080 CE Electric UK Funding Company Senior Notes and Sterling Notes 670,327 671,779 684,986 772,900 Casecnan Notes and Bonds 363,085 353,789 371,500 302,248 Northern Short Term Treasury Loan 174,593 174,593 72,740 72,740 Cordova Funding Senior Secured Bonds 124,824 120,399 -- -- CE Gas Loan 113,267 113,267 41,355 41,355 Power Resources Project Debt, Coso Funding Corp. Project Loans and Other 1,280 1,280 159,152 162,575 Convertible Preferred Securities of Subsidiary Trusts 450,000 353,925 553,930 562,012 Preferred Securities of Subsidiary Trusts 101,598 87,240 -- -- Preferred Securities of Subsidiaries 146,606 135,216 66,033 66,033
The amortized cost, gross unrealized gain and losses and estimated fair value of investments in debt and equity securities at December 31 are as follows (in thousands): 1999 -------------------------------------------- Amortized Unrealized Unrealized Fair Cost Gains Losses Value --------- ---------- ---------- -------- Available-for-sale: Equity securities ......... $122,327 $ 37,941 $ (13,530) $146,738 Municipal bonds ........... 30,913 868 (355) 31,426 U. S. Government securities 14,159 78 (123) 14,114 Corporate securities ...... 26,935 5 (1,511) 25,429 Cash equivalents .......... 8,591 -- -- 8,591 -------- -------- --------- -------- $202,925 $ 38,892 $ (15,519) $226,298 ======== ======== ========= ======== -84- 16. REGULATORY MATTERS NORTHERN Northern is subject to price cap regulation and the Office of Gas and Electricity Markets ("Ofgem") enforces the price control formulas for the supply and distribution businesses. The current distribution price control period expires on March 31, 2000. The changes to the formula took effect from April 1, 1995 and April 1, 1996 resulting 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 regulated distribution income per unit is increased or decreased each year by RPI-Xd where RPI reflects the average of the twelve months' 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 December 1999 Northern accepted Ofgem's proposals for the next distribution price control period which will bring about a further one-time reduction of around 24% in regulated distribution income with effect from April 1, 2000 with continuing Xd of 3% in each subsequent year. As a result of the distribution price reviews, Northern implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, Northern put in place a workforce reduction program. The Company recorded a non-recurring pre-tax loss of approximately $47.7 million and an after-tax loss of approximately $29.2 million or $0.41 per diluted share in 1999 due to costs associated with the reduction of Northern's workforce. Northern's current supply price control applies only to domestic and some smaller non-domestic customers in the North East of England and is due to expire on March 31, 2000. The current formula took effect on April 1, 1998 and required Northern to reduce prices to those customers from the level prevailing at August 1, 1997 by about 4.2% (minus inflation) from April 1, 1998 and by a further 3% (minus inflation) from April 1, 1999. In December 1999, Northern accepted Ofgem's proposals for the next supply price control period to be effective from April 1, 2000 until March 31, 2002. The new control relates to domestic customers only and will lead to a further price reduction for those customers of 10.8% in real terms with effect from April 1, 2000. The market for electricity supplied to customers with demands of over 1 MW was opened to competition in 1990. In 1994, this limit was reduced to 0.1 MW. During 1998, liberalization of the entire market commenced in stages and was completed during 1999. MEC As a result of a negotiated settlement in Illinois, MEC reduced its Illinois electric service rates by annual amounts of $13.1 million and $2.4 million, effective November 3, 1996, and June 1, 1997, respectively. MEC implemented an additional $0.9 million annual rate reduction for its Illinois residential customers, effective August 1, 1998, in connection with Illinois' electric utility restructuring law. On June 27, 1997, the Iowa Utilities Board approved a March 1997 settlement agreement between MEC, the Iowa Office of Consumer Advocate and other parties. Four major components of the settlement and their status are as follows: 1) On an annualized basis, prices for residential customers were reduced $8.5 million, $10.0 million and $5.0 million effective November 1, 1996, July 11, 1997, and June 1, 1998, respectively, for a total annual decrease of $23.5 million. -85- 2) Prices for industrial customers were reduced by $6 million annually and prices for commercial customers were reduced by $4 million annually. MEC was given permission to implement these reductions through a retail access pilot project, negotiated individual contracts and tariffed rate reductions. On January 1, 1999, MEC reduced base rates for selected non-contract commercial customers by approximately $1.5 million annually, subject to Iowa Utilities Board approval. The remainder of the commercial and industrial price reductions were achieved through negotiated contracts and a retail access pilot project. The negotiated contracts have differing terms and conditions as well as prices. The contracts range in length from five to ten years, and some have price renegotiation and early termination provisions exercisable by either party. The vast majority of the contracts are for terms of seven years or less, although, some large customers have agreed to 10-year contracts. Prices are set as fixed prices; however, many contracts allow for potential price adjustments with respect to environmental costs, government imposed public purpose programs, tax changes, and transition costs. While the contract prices are fixed (except for the potential adjustment elements), the costs MEC incurs to fulfill these contracts will vary. On an aggregate basis the annual revenues under contract are approximately $180 million. 3) The Iowa energy adjustment clause was eliminated. Prior to July 11, 1997, MEC collected fuel costs from Iowa customers on a current basis through the energy adjustment clause, and thus, fuel costs had little impact on net income. Since then, base rates for Iowa customers include a factor for recovery of a representative level of fuel costs. If the actual per-unit fuel cost varies from that factor, pre-tax earnings are affected. The fuel cost factor was to be reviewed in February 1999 and adjusted prospectively if the actual 1998 fuel cost per unit varied by more than 15% above or below the factor included in base rates. Based on 1998 actual fuel costs, MEC reduced the fuel cost recovery factor in 1999 base rates effective March 1, 1999. The estimated annual reduction in revenues associated with this adjustment is $1.1 million. 4) If MEC's annual Iowa electric jurisdictional return on common equity exceeds 12%, an equal sharing between customers and shareholders of earnings above the 12% level begins; if it exceeds 14%, two-thirds of MEC's share of those earnings will be used for accelerated recovery of regulatory assets. The agreement precludes MEC from filing for increased rates prior to 2001 unless the return on common equity falls below 9%. Other parties signing the agreement are prohibited from filing for reduced rates prior to 2001 unless the return on common equity, after reflecting credits to customers, exceeds 14%. Under a restructuring law enacted in 1997, a similar sharing mechanism is in place for Illinois operations. Two-year average returns on common equity greater than a two-year average benchmark will trigger an equal sharing of earnings on the excess. The benchmark is a calculation of average 30-year Treasury Bond rates plus 5.5% for 1998 and 1999 and 8.5% for 2000 through 2004. The initial calculation, due March 31, 2000, will be based on 1998 and 1999 results. 17. PENSION COMMITMENTS UNITED KINGDOM OPERATIONS 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, 1999, 1998 and 1997 assumed interest rates of 6.0%, 5.5% and 6.75% respectively, an expected return on plan assets of 6.5%, 6.0% and 7.25%, respectively, and annual compensation increases of 3.0%, 3.5% and 4.75%, 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. -86- The following table details the funded status and the amount recognized in the consolidated balance sheets for Northern's plan as of December 31, 1999 and 1998 (in thousands): 1999 1998 ----------- ------------ Change in benefit obligation: Benefit obligation at beginning of year .......... $ 926,000 $ 888,500 Service cost ..................................... 10,200 12,600 Interest cost .................................... 48,500 58,800 Participant contributions ........................ 5,700 5,800 Benefits paid .................................... (53,700) (46,700) FAS 88 curtailment ............................... 38,300 -- Experience loss (gain) and change of assumptions . (34,400) 7,000 ----------- ----------- Benefit obligation at end of the year ............ 940,600 926,000 ----------- ----------- Change in plan assets: Fair value of plan assets at beginning of the year 1,143,100 1,012,600 Actual return on plan assets ..................... 181,600 154,200 Contributions .................................... 12,600 23,000 Benefits paid .................................... (53,700) (46,700) ----------- ----------- Fair value of plan assets at end of the year ..... 1,283,600 1,143,100 ----------- ----------- Funded status .................................... 343,000 217,100 Unrecognized net gain ............................ 300,100 140,200 ----------- ----------- Prepaid benefit cost ............................. $ 42,900 $ 76,900 =========== =========== As a result of the distribution price reviews, Northern implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, Northern put in place a workforce reduction program. The Company recorded a non-recurring pre-tax loss of approximately $47.7 million which included a pension curtailment of $38.3 million. Net periodic pension cost (benefit) for Northern's plan for 1999, 1998 and 1997 included the following components (in thousands):
1999 1998 1997 ------- ------- -------- Service cost - benefits earned during the period. $10,200 $12,600 $ 12,600 Interest cost on projected benefit obligation.... 48,500 58,800 62,400 Actual return on plan assets..................... (59,500) (68,000) (71,400) ------- ------- -------- Net periodic pension cost (benefit).............. $ (800) $ 3,400 $ 3,600 ======= ======= ========
DOMESTIC OPERATIONS The Company has primarily noncontributory cash balance defined benefit pension plans covering substantially all employees. Benefit obligations under the plans are based on participants' compensation, years of service and age at retirement. Funding is based upon the actuarially determined costs of the plans and the requirements of the Internal Revenue Code and the Employee Retirement Income Security Act. The Company has been allowed to recover pension costs related to its employees in rates. MEC currently provides certain health care and life insurance (postretirement) benefits for retired employees. Under the plans, substantially all of MEC's employees may become eligible for these benefits if they reach retirement age while working for MEC. However, MEC retains the right to change these benefits anytime at its -87- discretion. MEC expenses postretirement benefit costs on an accrual basis and includes provisions for such costs in rates. In 1999, the noncontributory cash balance defined benefit pension plans, the noncontributory, nonqualified supplemental executive retirement plan, and the postretirement plans were amended to include participants from the Company. Prior to the amendment, these plans included only employees and participants of MEC, MidAmerican Capital and Midwest Capital. This inclusion increased the benefit obligation by $14.8 million for the pension and nonqualified supplemental retirement plans and $2.8 million for the postretirement plans and is reflected in the Benefit Obligation of MEC as of December 31, 1999. MEC also maintains noncontributory, nonqualified supplemental executive retirement plans for active and retired participants. Net periodic pension, supplemental retirement and postretirement benefit costs included the following components for the Company for the period from March 12, 1999 through December 31, 1999 (in thousands): Pension Cost Postretirement Cost ------------ ------------------- Service cost.......................... $ 9,854 $ 2,478 Interest cost......................... 25,505 6,423 Expected return on plan assets........ (37,392) (3,540) Curtailment loss...................... 4,270 - -------- ------- Net periodic pension cost (benefit). $ 2,237 $ 5,361 ======== ======= The pension plan assets are in external trusts and are comprised of corporate, domestic and international equity securities, United States government debt, corporate bonds, real estate, and insurance contracts. The postretirement benefit plans assets are in external trusts and are comprised primarily of corporate equity securities, corporate bonds, money market investment accounts and municipal bonds. Although the supplemental executive retirement plans had no plan assets as of December 31, 1999, MEC has Rabbi trusts which hold corporate-owned life insurance to provide funding for the future cash requirements. Because these plans are nonqualified, the fair value of these assets is not included in the following table. The fair value of the life insurance policies was $64.8 million at December 31, 1999. During 1999 certain participants in the supplemental executive retirement plan left MEC reducing the future service of active employees by 28%. As a result, a curtailment loss of $4.3 million was recognized by the Company in the period from March 12, 1999 through December 31, 1999. Additionally, termination benefits provided to the participants, totaling $3.5 million, were expensed by MEC during the year ended December 31, 1999. The projected benefit obligation and accumulated benefit obligation for the supplemental executive retirement plans were $68.8 million and $65.5 million, respectively, as of December 31, 1999. The following table presents a reconciliation of the beginning and ending balances of the benefit obligation, fair value of plan assets and the funded status of the Company plans to the net amounts recognized in the consolidated balance sheet as of December 31, 1999 (dollars in thousands): -88- Pension Postretirement Benefits Benefits --------- -------------- Reconciliation of benefit obligation: Benefit obligation at beginning of year ........ $ 456,475 $ 120,188 Service cost ................................... 12,192 3,066 Interest cost .................................. 31,556 7,947 Participant contributions ...................... 107 1,838 Plan amendments ................................ 14,823 2,775 Actuarial gain ................................. (41,567) (18,248) Curtailment .................................... (705) -- Termination benefits ........................... 3,471 -- Benefits paid .................................. (29,182) (9,822) --------- --------- Benefit obligation at end of year .......... 447,170 107,744 --------- --------- Reconciliation of the fair value of plan assets: Fair value of plan assets at beginning of year . 524,508 63,093 Employer contributions ......................... 4,201 12,405 Participant contributions ...................... 107 1,838 Actual return on plan assets ................... 105,425 5,108 Benefits paid .................................. (29,182) (9,822) --------- --------- Fair value of plan assets at end of year ... 605,059 72,622 --------- --------- Funded status .................................. 157,889 (35,122) Unrecognized net gain .......................... (101,434) (18,943) Unrecognized prior service cost ................ 9,540 2,776 --------- --------- Net amount recognized in the consolidated balance sheet ............................ $ 65,995 $ (51,289) ========= ========= Pension Postretirement Benefits Benefits --------- -------------- Amounts recognized in the consolidated balance sheet consist of: Prepaid benefit cost ......................... $ 108,907 $ 1,042 Accrued benefit liability .................... (65,533) (52,331) Intangible asset ............................. 22,621 -- --------- --------- Net amount recognized .................... $ 65,995 $ (51,289) ========= ========= Pension and Postretirement Assumptions -------------------------- Assumptions used were: Discount rate................................ 7.75% Rate of increase in compensation levels...... 5.00% Weighted average expected long-term rate of return on assets................. 9.00% For purposes of calculating the postretirement benefit obligation, it is assumed health care costs for covered individuals prior to age 65 will increase by 7.5% in 2000 and that the rate of increase thereafter will decline by .75% annually to an ultimate rate of 5.25% by the year 2003. For covered individuals age 65 and older, it is assumed health care costs will increase by 5.5% annually. -89- If the assumed health care trend rates used to measure the expected cost of benefits covered by the plans were increased by 1.0%, the total service and interest cost for 1999 would increase by $2.0 million, and the postretirement benefit obligation at December 31, 1999, would increase by $15.2 million. If the assumed health care trend rates were to decrease by 1.0%, the total service and interest cost for 1999 would decrease by $1.6 million and the postretirement benefit obligation at December 31, 1999, would decrease by $12.1 million. 18. COMMITMENTS AND CONTINGENCIES DECOMMISSIONING COSTS Based on site-specific decommissioning studies that include decontamination, dismantling, site restoration and dry fuel storage cost, MEC's share of expected decommissioning costs for Cooper and Quad Cities Station, in 1999 dollars, is $267 million and $255 million, respectively. In Illinois, nuclear decommissioning costs are included in customer billings through a mechanism that permits annual adjustments. These costs are reflected in base rates in Iowa tariffs. For purposes of developing a decommissioning funding plan for Cooper, Nebraska Public Power District ("NPPD") assumes that decommissioning costs will escalate at an annual rate of 4.0%. Although Cooper's operating license expires in 2014, the funding plan assumes decommissioning will start in 2004, the anticipated plant shutdown date. As of December 31, 1999, MEC's share of funds set aside by NPPD in internal and external accounts for decommissioning was $109.8 million. In addition, the funding plan also assumes various funds and reserves currently held to satisfy NPPD bond resolution requirements will be available for plant decommissioning costs after the bonds are retired in early 2004. The funding schedule assumes a long-term return on funds in the trust of 6.75% annually. Certain funds will be required to be invested on a short-term basis when decommissioning begins and are assumed to earn at a rate of 4.0% annually. MEC makes payments to NPPD related to decommissioning Cooper. The Cooper decommissioning component of MEC's payments to NPPD was $9.1 million, for the period from March 12, 1999 through December 31, 1999 and is included in operating expenses. Earnings from the internal account and external trust fund, which are recognized by NPPD as the owner of the plant, are tax exempt and serve to reduce future funding requirements. External trusts have been established for the investment of funds for decommissioning the Quad Cities Station. The total accrued balance as of December 31, 1999, was $141.6 million and is included in other long-term accrued liabilities and a like amount is reflected in nuclear decommissioning trust fund and other marketable securities and represents the fair value of the assets held in the trusts. MEC's provision for depreciation included costs for Quad Cities Station nuclear decommissioning of $8.2 million for the period from March 12, 1999 through December 31, 1999. The provision charged to expense is equal to the funding that is being collected in rates. The decommissioning funding component of MEC's Illinois and Iowa tariffs assumes decommissioning costs, related to the Quad Cities Station, will escalate at an annual rate of 5.0% and the assumed annual return on funds in the trust is 6.9%. Earnings, net of investment fees, on the assets in the trust fund were $1.6 million for the period from March 12, 1999 through December 31, 1999. NUCLEAR INSURANCE MEC maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station and Cooper through a combination of insurance purchased by the NPPD (the owner and operator of Cooper) and ComEd (the joint owner and operator of Quad Cities Station), insurance purchased directly by MEC, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability. -90- The NPPD and ComEd each purchase nuclear liability insurance for Cooper and Quad Cities Station, respectively, in the maximum available amount of $200 million. In accordance with the Price-Anderson Amendments Act of 1988, excess liability protection above that amount is provided by a mandatory industry-wide program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MEC's aggregate maximum potential share of an assessment for Cooper and Quad Cities Station combined is $88.1 million per incident, payable in installments not to exceed $10 million annually. The property coverage provides for property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning. For Quad Cities Station, ComEd purchases primary and excess property insurance protection for the combined interests in Quad Cities, with coverage limits totaling $2.1 billion. For Cooper, MEC and the NPPD separately purchase primary and excess property insurance protection for their respective obligations, with coverage limits of $1.375 billion each. This structure provides that both MEC and the NPPD are covered for their respective 50% obligation in the event of a loss totaling up to $2.75 billion. MEC also directly purchases extra expense/business interruption coverage for its share of replacement power and/or other extra expenses in the event of a covered accidental outage at Cooper or Quad Cities Station. The coverages purchased directly by MEC, and the property coverages purchased by ComEd, which includes the interests of MEC, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum retrospective amounts that could be assessed against MEC from industry mutual policies for its obligations associated with Cooper and Quad Cities Station combined, total $11.6 million. The master nuclear worker liability coverage, which is purchased by the NPPD and ComEd for Cooper and Quad Cities Station, respectively, is an industry-wide guaranteed-cost policy with an aggregate limit of $200 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries. -91- 19. SEGMENT INFORMATION: The Company has identified four reportable business segments principally based on geographic area: Domestic electricity generation, foreign electricity generation (primarily the Philippines), domestic utility operations and foreign utility operations (primarily the United Kingdom). Information related to the Company's reportable operating segments are shown below (in thousands). Year Ended December 31, --------------------------------------- 1999 1998 1997 ---------- ----------- ----------- REVENUE: Domestic generation ........ $ 106,894 $ 583,311 $ 570,587 Foreign generation ......... 210,366 223,650 102,960 Domestic utility ........... 1,811,599 -- -- Foreign utility ............ 2,098,976 1,842,930 1,566,442 ---------- ----------- ----------- Segment revenue ............ 4,227,835 2,649,891 2,239,989 Corporate .................. 170,948 32,820 30,922 ---------- ----------- ----------- $4,398,783 $ 2,682,711 $ 2,270,911 ========== =========== =========== OPERATING INCOME: (1) Domestic generation ........ $ 67,936 $ 313,983 $ 301,589 Foreign generation ......... 126,245 142,977 61,131 Domestic utility ........... 271,442 -- -- Foreign utility ............ 201,203 172,772 191,299 ---------- ----------- ----------- Segment operating income ... 666,826 629,732 554,019 Corporate .................. 116,416 (10,387) (12,882) ---------- ----------- ----------- $ 783,242 $ 619,345 $ 541,137 ========== =========== =========== CAPITAL EXPENDITURES: Domestic generation ........ $ 145,255 $ 105,458 $ 58,956 Foreign generation ......... 95,552 204,301 177,813 Domestic utility ........... 203,359 -- -- Foreign utility (2) ........ 202,073 184,631 134,050 ---------- ----------- ----------- Segment capital expenditures 646,239 494,390 370,819 Corporate .................. 120 537 9,830 ---------- ----------- ----------- $ 646,359 $ 494,927 $ 380,649 ========== =========== =========== (1) Operating income excludes interest expense, net of capitalized interest. 1997 excludes the losses on non-recurring items of $87.0 million and the loss on equity investment in Casecnan (2) Capital expenditures at the foreign utility exclude the effect of exchange rate changes. -92- As of December 31, ------------------------ 1999 1998 ----------- ---------- IDENTIFIABLE ASSETS: Domestic generation ....... $ 858,812 $2,458,842 Foreign generation ........ 1,259,463 1,956,387 Domestic utility .......... 5,192,448 -- Foreign utility ........... 2,972,705 3,095,839 ----------- ---------- Segment identifiable assets 10,283,428 7,511,068 Corporate ................. 482,924 1,592,456 ----------- ---------- $10,766,352 $9,103,524 =========== ========== LONG-LIVED ASSETS: Domestic generation ....... $ 595,607 $1,960,433 Foreign generation ........ 996,764 1,275,104 Domestic utility .......... 4,166,595 -- Foreign utility ........... 2,438,877 2,519,615 ----------- ---------- Segment long-lived assets . 8,197,843 5,755,152 Corporate ................. 20,991 19,063 ----------- ---------- $ 8,218,834 $5,774,215 =========== ========== The remaining differences from the segment amounts to the consolidated amounts described as "Corporate" relate principally to the corporate functions including administrative costs, corporate cash and related interest income as well as the non-recurring gains on the sales of the qualified facilities and McLeod common stock, the gain on the Indonesia insurance proceeds and the Berkshire transaction costs. -93- 20. QUARTERLY FINANCIAL DATA (UNAUDITED) Following is a summary of the Company's quarterly results of operations for the years ended December 31, 1999 and 1998 (in thousands, except per share amounts):
THREE MONTHS ENDED * 1999: MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 --------- ----------- ------------ ----------- Operating revenue ..................................... $ 797,885 $ 1,003,602 $ 1,062,560 $ 1,264,690 Total revenue ......................................... 858,018 1,115,442 1,089,917 1,335,406 Total costs and expenses .............................. 781,259 1,004,713 1,000,545 1,255,197 --------- ----------- ----------- ----------- Income before income taxes ............................ 76,759 110,729 89,372 80,209 Provision for income taxes ............................ 26,065 37,227 27,491 2,692 --------- ----------- ----------- ----------- Income before minority interest ....................... 50,694 73,502 61,881 77,517 Minority interest ..................................... 10,903 12,441 12,185 11,394 --------- ----------- ----------- ----------- Income before extraordinary item ...................... 39,791 61,061 49,696 66,123 Extraordinary item, net of tax ........................ (31,520) (5,366) (3,170) (9,385) --------- ----------- ----------- ----------- Net income attributable to common stockholders ........ $ 8,271 $ 55,695 $ 46,526 $ 56,738 ========= =========== =========== =========== Income per share before extraordinary item ............ $ .67 $ 1.02 $ .82 $ 1.11 Extraordinary item .................................... (.53) (.09) (.05) (.16) --------- ----------- ----------- ----------- Net income per share .................................. $ .14 $ .93 $ .77 $ .95 ========= =========== =========== =========== Weighted average basic shares outstanding ............. 59,205 60,037 60,592 59,880 ========= =========== =========== =========== Income per share before extraordinary item diluted .... $ .62 $ .91 $ .75 $ 1.00 Extraordinary item - diluted .......................... (.43) (.08) (.05) (.13) --------- ----------- ----------- ----------- Net income per share - diluted ........................ $ .19 $ .83 $ .70 $ .87 ========= =========== =========== =========== Weighted average diluted shares outstanding ........... 73,244 72,638 71,330 70,615 ========= =========== =========== ===========
-94-
THREE MONTHS ENDED * 1998: MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 --------- ----------- ------------ ----------- Operating revenue ..................................... $ 621,851 $ 590,589 $ 600,862 $ 741,904 Total revenue ......................................... 644,311 620,518 627,747 790,135 Total costs and expenses .............................. 588,401 555,961 537,477 728,819 --------- ----------- ----------- ----------- Income before income taxes ............................ 55,910 64,557 90,270 61,316 Provision for income taxes ............................ 18,531 21,952 32,112 20,670 --------- ----------- ----------- ----------- Income before minority interest ....................... 37,379 42,605 58,158 40,646 Minority interest ..................................... 10,084 10,139 10,535 10,518 --------- ----------- ----------- ----------- Income before extraordinary item and cumulative effect of change in accounting principle ........... 27,295 32,466 47,623 30,128 Extraordinary item, net of tax ........................ -- -- -- (7,146) Cumulative effect of change in accounting principle, net of tax .............................. -- -- -- (3,363) --------- ----------- ----------- ----------- Net income attributable to common stockholders ........ $ 27,295 $ 32,466 $ 47,623 $ 19,619 ========= =========== =========== =========== Income per share before extraordinary item and cumulative effect of change in accounting principal .45 $ .54 $ .80 $ .51 Extraordinary item .................................... -- -- -- (.12) Cumulative effect of change in accounting principle ... -- -- -- (.06) --------- ----------- ----------- ----------- Net income per share .................................. .45 $ .54 $ .80 $ .33 ========= =========== =========== =========== Weighted average basic shares outstanding ............. 61,081 60,235 59,674 59,566 ========= =========== =========== =========== Income per share before extraordinary item and cumulative effect of change in accounting principle - diluted ................................ .43 $ .51 $ .72 $ .48 Extraordinary item - diluted .......................... -- -- -- (.10) Cumulative effect of change in accounting principle - diluted ................................ -- -- -- (.04) --------- ----------- ----------- ----------- Net income per share - diluted ........................ .43 $ .51 $ .72 $ .34 ========= =========== =========== =========== Weighted average diluted shares outstanding ........... 69,343 74,346 73,540 73,627 ========= =========== =========== ===========
* The Company's operations are seasonal in nature. -95- INDEPENDENT AUDITORS' REPORT Board of Directors and Stockholders MidAmerican Energy Holdings Company Des Moines, Iowa We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company and subsidiaries (the "Company") as of December 31, 1999 and 1998, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1999. Our audit also included the financial statement schedule listed in the Index at Item 14. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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 MidAmerican Energy Holdings Company and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Des Moines, Iowa January 25, 2000 (March 14, 2000 as to Note 3) -96- MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I PARENT COMPANY ONLY CONDENSED BALANCE SHEETS as of December 31, 1999 and 1998 (dollars in thousands)
1999 1998 ----------- ----------- ASSETS Current Assets: Cash and cash equivalents .................................... $ 240,938 $ 1,522,294 ----------- ----------- Total current assets ....................................... 240,938 1,522,294 Investments in and advances to subsidiaries and joint ventures 2,972,843 2,430,734 Equipment, net ............................................... 16,728 17,554 Deferred charges and other assets ............................ 158,887 155,332 ----------- ----------- Total assets ............................................... $ 3,389,396 $ 4,125,914 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and other accrued liabilities ............... $ 88,490 $ 98,940 ----------- ----------- Total current liabilities .................................. 88,490 98,940 Parent company debt ............................................. 1,856,318 2,645,991 ----------- ----------- Total liabilities ............................................ 1,944,808 2,744,931 ----------- ----------- Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts ........ 450,000 553,930 Stockholders' equity: Preferred stock - authorized 2,000 shares, no par value ...... -- -- Common stock -authorized 180,000 shares, no par value issued 82,980 shares, 59,944 and 59,605 shares, respectively -- -- Additional paid in capital ................................... 1,249,079 1,238,690 Retained earnings ............................................ 507,726 340,496 Accumulated other comprehensive income ....................... (12,029) 45 Treasury stock - 23,036 and 23,375 common shares, respectively, at cost ...................................... (750,188) (752,178) ----------- ----------- Total stockholders' equity ................................... 994,588 827,053 ----------- ----------- Total liabilities and stockholders' equity ................... $ 3,389,396 $ 4,125,914 =========== ===========
The notes to the consolidated MEHC financial statements are an integral part of these financial statements. -97- MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I PARENT COMPANY ONLY (CONTINUED) CONDENSED STATEMENTS OF OPERATIONS for the three years ended December 31, 1999 (dollars and shares in thousands, except per share amounts)
1999 1998 1997 --------- --------- ---------- Revenue: Equity in undistributed earnings of subsidiary companies and joint ventures ......................................... $ 159,439 $ 205,049 $ 79,905 Cash dividends and distributions from subsidiary companies and joint ventures ............................... 345,430 179,782 156,686 Interest and other income ..................................... 34,002 44,686 49,488 --------- --------- --------- Total revenues ............................................. 538,871 429,517 286,079 --------- --------- --------- Expenses: General and administration .................................... 40,262 30,527 36,616 Interest, net of capitalized interest ......................... 156,600 132,250 75,438 --------- --------- --------- Total expenses ............................................. 196,862 162,777 112,054 --------- --------- --------- Income before provision for income taxes ...................... 342,009 266,740 174,025 Provision for income taxes .................................... 93,475 93,265 99,044 --------- --------- --------- Income before minority interest ............................... 248,534 173,475 74,981 Minority interest ............................................. 31,863 35,963 23,158 --------- --------- --------- Income before extraordinary items and cumulative effect of change in accounting principle ............................. 216,671 137,512 51,823 Extraordinary items, net of tax ............................... (49,441) (7,146) (135,850) Cumulative effect of change in accounting principle, net of tax -- (3,363) -- --------- --------- --------- Net income (loss) available to common stockholders ............ $ 167,230 $ 127,003 $ (84,027) ========= ========= ========= Income per share before extraordinary items and cumulative effect of change in accounting principle ................... $ 3.62 $ 2.29 $ .77 Extraordinary items ........................................... (.83) (.12) (2.02) Cumulative effect of change in accounting principle ........... -- (.06) -- --------- --------- --------- Net income (loss) per share ................................... $ 2.79 $ 2.11 $ (1.25) ========= ========= ========= Income per share before extraordinary items and cumulative effect of change in accounting principle - diluted ......... $ 3.28 $ 2.15 $ .75 Extraordinary items - diluted ................................. (.69) (.10) (1.97) Cumulative effect of change in accounting principle - diluted . -- (.04) -- --------- --------- --------- Net income (loss) per share - diluted ......................... $ 2.59 $ 2.01 $ (1.22) ========= ========= ========= Average number of shares outstanding .......................... 59,929 60,139 67,268 ========= ========= ========= Diluted shares ................................................ 71,948 74,100 68,686 ========= ========= =========
The notes to the consolidated MEHC financial statements are an integral part of these financial statements. -98- MIDAMERICAN ENERGY HOLDINGS COMPANY SCHEDULE I PARENT COMPANY ONLY (continued) CONDENSED STATEMENTS OF CASH FLOWS for the three years ended December 31, 1999 (dollars in thousands)
1999 1998 1997 ----------- ----------- ----------- Cash flows from operating activities ................ $ (261,276) $ (219,705) $ (200,057) ----------- ----------- ----------- Cash flows from investing activities: Decrease (increase) in advances to and investments in subsidiaries and joint ventures .................. (53,215) (103,494) 174,584 Decrease (increase) in short-term investments ....... -- 421 (229) Other ............................................... (4,390) (24,749) 18,330 ----------- ----------- ----------- Cash flows from investing activities ................ (57,605) (127,822) 192,685 ----------- ----------- ----------- Cash flows from financing activities: Proceeds from sale of common and treasury stock and exercise of stock options .................... 5,482 3,412 703,624 Proceeds from issuance of parent company debt ....... -- 1,502,243 350,000 Proceeds from convertible preferred securities of subsidiary trusts ............................. -- -- 450,000 Repayment of parent company debt .................... (853,420) (167,285) (100,000) Net proceeds from revolver .......................... -- -- (95,000) Purchase of treasury stock .......................... (104,847) (724,791) (55,505) Deferred charges relating to debt financing ......... (9,690) (24,235) (33,719) ----------- ----------- ----------- Cash flows from financing activities ................ (962,475) 589,344 1,219,400 ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents (1,281,356) 241,817 1,212,028 Cash and cash equivalents at beginning of period .... 1,522,294 1,280,477 68,449 ----------- ----------- ----------- Cash and cash equivalents at end of period .......... $ 240,938 $ 1,522,294 $ 1,280,477 =========== =========== =========== Supplemental disclosures: Interest paid (net of amount capitalized) ........... $ 173,285 $ 104,350 $ 38,176 =========== =========== =========== Income taxes paid ................................... $ 83,280 $ 32,100 $ 35,302 =========== =========== ===========
The notes to the consolidated MEHC financial statements are an integral part of these financial statements. -99- 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 30th day of March, 2000. MIDAMERICAN ENERGY HOLDINGS COMPANY /s/ David L. Sokol* - ------------------- David L. Sokol Chairman of the Board and Chief Executive Officer 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 30, 2000 David L. Sokol Chairman of the Board, Chief Executive Officer, and Director /s/ Gregory E. Abel* March 30, 2000 Gregory E. Abel President, Chief Operating Officer and Director /s/ Patrick J. Goodman* March 30, 2000 Patrick J. Goodman Senior Vice President and Chief Financial Officer /s/ Edgar D. Aronson* March 30, 2000 Edgar D. Aronson Director /s/ Stanley J. Bright * March 30, 2000 Stanley J. Bright Director /s/ Walter Scott, Jr.* March 30, 2000 Walter Scott, Jr. Director -100- /s/ Marc D. Hamburg * March 30, 2000 Marc D. Hamburg Director /s/ Warren Buffett* March 30, 2000 Warren Buffett Director /s/ John Boyer* March 30, 2000 John Boyer Director /s/ W. David Scott* March 30, 2000 W. David Scott Director *By:/s/ Steven A. McArthur March 30, 2000 Steven A. McArthur Attorney-in-Fact -101- EXHIBIT INDEX 3.1* Restated Articles of Incorporation of the Company. 3.2* Bylaws of the Company. 4.2 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). 4.3 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 1/2% 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). 4.4 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 refer- ence to Exhibit 10.129 to the Company's 1996 Form 10-K). 4.5 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). 4.6 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). 4.7 Form of Second Supplemental Indenture, dated as of September 22, 1998 between 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 September 17, 1998.) 4.8 Form of Third Supplemental Indenture, dated as of November 13, 1998, between the Company and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to the Company's Current Report on Form 8-K dated November 10, 1998). 4.9* Indenture, dated as of March 14, 2000, among the Company and the Bank of New York, as Trustee. 4.10* Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 14, 2000. 10.1* Employment Agreement between the Company and David L. Sokol, dated May 10, 1999. 10.2* Amendment No. 1 to the Amended and Restated Employment Agreement between the Company and David L. Sokol, dated March 14, 2000. 10.3* Amended and Restated Employment Agreement between the Company and Gregory E. Abel, dated May 10, 1999. 10.4* Amended and Restated Employment Agreement between the Company an Steven A. McArthur, dated May 10, 1999. -102- 10.5* Employment Agreement between the Company and Patrick J. Goodman, dated May 10, 1999. 10.9 125 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 Agreemen dated February 18, 1994 and the Fourth Amendment to 25 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). 10.10 Credit Agreement dated April 8, 1994 among CE Cebu Geothermal Power Company, Inc., the Banks thereto, Credit Suisse as Agent (incorporated by reference to Exhibit 10.96 to the Company's 1994 Form 10-K). 10.11 Credit Agreement dated as of April 8, 1994 between CE Cebu Geothermal Power Company, Inc., Export-Import Bank of the United States (incor- porated by reference to Exhibit 10.97 to the Company's 1994 Form 10-K). 10.12 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). 10.13 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 refer- ence to Exhibit 10.99 to the Company's 1994 Form 10-K). 10.14 180 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). 10.15 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 SavingsAssocia- tion as Administrative Agent (incorporated by reference to Exhibit 10.101 to the Company's 1994 Form 10-K). 10.16 Credit Agreement dated as of June 30, 1994 between CE Luzon Geotherma 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). 10.17 Finance Agreement dated as of June 30, 1994 between CE Luzon Geo- thermal Power Company, Inc. and Overseas Private Investment Corpora- tion (incorporated by reference to Exhibit 10.103 to the Company's 1994 Form 10-K). 10.18 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 Geo- thermal Power Company, Inc. (incorporated by reference to Exhibit 10.104 to the Company's 1994 Form 10-K). 10.19 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). -103- 10.20 231 MW Power Plant - Malitbog Agreement ("Malitbog ECA") dated Sep- tember 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). 10.21 Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Ban Agent (incorporated by reference to Exhibit 10.107 to the Company's 1994 Form 10-K). 10.22 Finance Agreement dated as of November 10, 1994 between Visayas Geo- thermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to the Company's 1994 Form 10-K). 10.23 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). 10.24 Overseas Private Investment Corporation Contract of Insurance dated December 21, 1994 between OPIC and Magma Netherlands, B.V. (incor- porated by reference to Exhibit 10.110 to the Company's 1994 Form 10-K). 10.25 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 refer- ence to Exhibit 10.111 to the Company's 1994 Form 10-K). 10.26 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"). 10.27 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). 10.28 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). 10.29 Public Electricity Supply License (incorporated by reference to Exhibit 10.131 to the Company's 1996 Form 10-K) 10.30 Second Tier Supply Licenses to Supply Electricity for England & Wales and Scotland (incorporated by reference to Exhibit 10.132 to th Company's 1996 Form 10-K). 10.31 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 -104- deFrance, Service National and Others (incorporated by reference to Exhibit 10.133 to the Company's 1996 Form 10-K). 10.32 Master Connection and User System Agreement with The National Grid Company plc (incorporated by reference to Exhibit 10.134 to the Com- pany's 1996 Form 10-K). 10.33 Gas Suppliers License dated February 21, 1996 (incorporated by refer- ence to Exhibit 10.135 to the Company's 1996 Form 10-K). 10.34 Acquisition Agreement by and between CalEnergy Company, Inc. an Kiewit Diversified Group Inc. dated as of September 10, 1997 (incor- porated by reference to Exhibit 2 to the Company's Current Report on Form 8-K dated September 11, 1997). 10.35 Agreement and Plan of Merger dated as of August 11, 1998 by and among CalEnergy Company, Inc., Maverick Reincorporation Sub, Inc., MidAmeri- can Energy Holdings Company and MAVH Inc. (incorporated by reference to the Company's Current Report on Form 8-K dated August 11, 1998). 10.36 Indenture and First Supplemental Indenture, dated March 11, 1999, between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company and the First Supplement thereto relating to the $700 million Senior Notes and Bonds (incorporated by reference to the Company's 1998 Form 10-K). 10.37 Settlement Agreement by and between MidAmerican Energy Company, the Iowa Utilities Board, the Iowa Office of Consumer Advocate, and others (incorporated by reference to the Company's 1998 Form 10-K). 10.38 General Mortgage Indenture and Deed of Trust dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee. (incorporated by reference to Exhibit 4(b)-1 to Midwest Resources Inc.'s Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654.) 10.39 First Supplemental Indenture dated as of January 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee. (incorporated by reference to Exhibit 4(b)-2 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654.) 10.40 Second Supplemental Indenture dated as of January 15, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee. (incorporated by reference to Exhibit 4(b)-3 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654.) 10.41 Third Supplemental Indenture dated as of May 1, 1993, between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee. (incorporated by reference to Exhibit 4.4 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654.) 10.42 Fourth Supplemental Indenture dated as of October 1, 1994, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee. (incorporated by reference to Exhibit 4.5 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654.) 10.43 Fifth Supplemental Indenture dated as of November 1, 1994, betwee Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee. (incorporated by reference to Exhibit 4.6 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654.) -105- 10.44 Indenture of Mortgage and Deed of Trust, dated as of March 1, 1947. (incorporated by reference to Iowa-Illinois Gas and Electric Company ("Iowa-Illinois") as Exhibit 7B to Commission File No. 2-6922.) 10.45 Sixth Supplemental Indenture dated as of July 1, 1967. (incorporated by reference to Iowa-Illinois as Exhibit 2.08 to Commission File No. 2-28806.) 10.46 Twentieth Supplemental Indenture dated as of May 1, 1982. (incorpor- ated by reference to Exhibit 4.B.23 to Iowa-Illinois' Quarterly Report on Form 10-Q for the period ended June 30, 1982, Commission File No. 1-3573.) 10.47 Resignation and Appointment of successor Individual Trustee. (inco- porated by reference to Iowa-Illinois as Exhibit 4.B.30 to Commissio File No. 33-39211.) 10.48 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992. (incor- porated by reference to Exhibit 4.31.B to Iowa-Illinois' Current Report on Form 8-K dated May 21, 1992, Commission File No. 1-3573.) 10.49 Twenty-Ninth Supplemental Indenture dated as of March 15, 1993. (incorporated by reference to Exhibit 4.32.A to Iowa-Illinois' Current Report on Form 8-K dated March 24, 1993, Commission File No. 1-3573.) 10.50 Thirtieth Supplemental Indenture dated as of October 1, 1993. (incor- porated by reference to Exhibit 4.34.A to Iowa-Illinois' Current Report on Form 8-K dated October 7, 1993, Commission File No. 1-3573.) 10.51 Sixth Supplemental Indenture dated as of July 1, 1995, between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee. (incorporated by reference to Exhibit 4.15 to MidAmerican Energy Company's ("MidAmerican Energy") Annual Report on Form 10-K dated December 31, 1995, Commission File No. 1-11505.) 10.52 Thirty-First Supplemental Indenture dated as of July 1, 1995, between Iowa-Illinois Gas and Electric Company and Harris Trust and Savings Bank, Trustee. (incorporated by reference to Exhibit 4.16 to Mid- American Energy's Annual Report on Form 10-K dated December 31, 1995, Commission File No. 1-11505.) 10.53 Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967. (incorporated by reference to Exhibit 4-C-2 to Iowa Power Inc.'s (IPR) Registration Statement, Reg- istration No. 2-27681). 10.54 Amendments Nos. 1 and 2 to Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District. (incorporated by reference to Exhibit 4-C-2a to IPR's Registration Statement, Registration No. 2-35624.) 10.55 Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967. (incorporated by reference to Exhibit 5-C-2-b to IPR's Registration Statement, Registration No. 2-42191.) 10.56 Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between Iowa Power Inc. and Nebraska Public Power District, dated September 22, 1967. (incorporated by reference to Exhibit 5-C-2-c to IPR's Registration Statement, Registration No. 2-51540.) 10.57 Amendment No. 5 dated September 2, 1997, to the Power Sales Contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967. (incorporated by reference to Exhibit 10.2 to MidAmerican Energy's Quarterly Reports on the combined Form 10-Q for the quarter ended September 30, 1997, Commission File Nos. 1-12459 and 1-11505, respectively.) -106- 10.58 MidAmerican Energy Company Severance Plan For Specified Officers dated November 1, 1996. (incorporated by reference to Exhibit 10.1 to MidAmerican Energy's Annual Reports on the combined Form 10-K for the year ended December 31, 1996, Commission File Nos. 1-12459 and 1-11505, respectively.) 10.59* MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan. 10.60* MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers. (incorporated by reference to Exhibit 10.3 to MidAmerican Energy's Annual Report on Form 10-K dated December 31, 1995, Commis- sion File No. 1-11505.) 10.61* MidAmerican Energy Company Restated Executive Deferred Compensation Plan. 10.62* MidAmerican Energy Holdings Company Restated Deferred Compensation Plan - Board of Directors. 10.63* MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan - Board of Directors. 10.66 Midwest Resources Inc. Supplemental Retirement Plan (formerly the Midwest Energy Company Supplemental Retirement Plan). (incorporated by reference to Exhibit 10.10 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654.) 10.72 Supplement Retirement Plan for Principal Officers, as amended as o July 1, 1993. (incorporated by reference to Exhibit 10.K.2 to Iowa- Illinois' Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573.) 10.73 Compensation Deferral Plan for Principal Officers, as amended as of July 1, 1993. (incorporated by reference to Exhibit 10.K.2 to Iowa- Illinois' Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-3573.) 10.74 Board of Directors' Compensation Deferral Plan. (incorporated by reference to Exhibit 10.K.4 to Iowa-Illinois' Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-3573.) 10.75 Amendment No. 1 to the Midwest Resources Inc. Supplemental Retirement Plan. (incorporated by reference to Exhibit 10.24 to Midwest Resources' Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654.) 10.78 Amendment No. 5 dated September 2, 1997, to the Power Sales contract between MidAmerican Energy Company and Nebraska Public Power District, dated September 22, 1967. (incorporated by reference to Exhibit 10.2 to MidAmerican Energy's Quarterly Reports on the combined Form 10- for the quarter ended September 30, 1997, Commission File Nos. 1-12459 and 1-11505, respectively.) 21.0 Subsidiaries of Registrant. 23.0 Consent of Independent Auditors 24.0 Power of Attorney. 27.0 Financial Data Schedule. *To be filed by amendment. -107- EX-21 2 SUBSIDIARIES OF THE REGISTRANT Exhibit 21 MIDAMERICAN ENERGY HOLDINGS COMPANY SUBSIDIARIES AND JOINT VENTURES Subsidiaries: MIDAMERICAN FUNDING LLC Iowa IPP CO Delaware IPP CO LLC Delaware CE MINERALS DEVELOPMENT LLC Delaware CALENERGY HOLDINGS INC. Delaware CE TEXAS ENERGY LLC Delaware CE TEXAS GAS LP Delaware FISH LAKE POWER LLC Delaware IMPERIAL MAGMA LLC Delaware SALTON SEA ROYALTY LLC Delaware VPC GEOTHERMAL LLC Delaware CALENERGY CAPITAL TRUST I Delaware CALENERGY CAPITAL TRUST II Delaware CALENERGY CAPITAL TRUST III Delaware CALENERGY CAPITAL TRUST IV Delaware CALENERGY CAPITAL TRUST V Delaware CALENERGY CAPITAL TRUST VI Delaware CE GEOTHERMAL, INC. Delaware WESTERN STATES GEOTHERMAL COMPANY Delaware INTERMOUNTAIN GEOTHERMAL COMPANY Delaware CALIFORNIA ENERGY DEVELOPMENT CORPORATION Delaware CALIFORNIA ENERGY YUMA CORPORAITON Utah CE EXPLORATION COMPANY Delaware CE NEWBERRY, INC. Delaware CALENERGY INTERNATIONAL SERVICES, INC. Delaware CALIFORNIA ENERGY GENERAL CORPORATION Delaware CE GENERATION LLC 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 BALI ENERGY LTD. Bermuda CE CASECNAN LTD. Bermuda -1- CE SINGAPORE LTD. Bermuda CALENERGY INTERNATIONAL LTD. Bermuda CE CASECNAN WATER AND ENERGY COMPANY, INC. Philippines CE BALI LTD. Bermuda CE ASIA LTD. Bermuda MAGMA POWER COMPANY Nevada DESERT VALLEY COMPANY California VULCAN POWER COMPANY Nevada CALENERGY OPERATING CORPORATION Delaware SALTON SEA POWER COMPANY Nevada MAGMA LAND COMPANY I Nevada MAGMA GENERATING COMPANY II Nevada MAGMA GENERATING COMPANY I Nevada CALIFORNIA ENERGY MANAGEMENT COMPANY Delaware SALTON SEA FUNDING CORPORATION Delaware TONGONAN POWER INVESTMENT, INC. Philippines MAGMA NETHERLANDS B.V. Netherlands NORMING INVESTMENTS B.V. Netherlands CALENERGY IMPERIAL VALLEY COMPANY, INC. Delaware SLUPO I B.V. Netherlands CONEJO ENERGY COMPANY California NIGUEL ENERGY COMPANY California SAN FELIPE ENERGY COMPANY California FALCON SEABOARD RESOURCES, INC. Texas FALCON SEABOARD OIL COMPANY Texas FALCON SEABOARD PIPELINE CORPORATION Texas FALCON SEABOARD POWER CORPORATION Texas POWER RESOURCES, LTD 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 -2- 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 INFOCOM 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 NEPTUNE POWER LTD England/Wales CALENERGY GAS (POLSKA) SP. Z O.O. Poland CE (BERMUDA) FINANCING LTD. Bermuda CALENERGY GAS (PIPELINES) LIMITED England/Wales CALENERGY POWER POLSKA SP. Z O.O. Poland SALTON SEA POWER L.L.C. 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 2000, L.L.C. Delaware CE AURORA I, INC. Delaware NORTHERN AURORA, INC. Delaware CALENERGY MINERALS LLC Delaware YUMA COGENERATION ASSOCIATES Utah VULCAN/BN GEOTHERMAL POWER COMPANY Nevada LEATHERS, L.P. California ELMORE, L.P. California DEL RANCH, L.P. (HOCH) California -3- SALTON SEA BRINE PROCESSING, L.P. California SALTON SEA POWER GENERATION L.P. California 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 CE ELECTRIC UK FUNDING COMPANY England/Wales MHC INC. Iowa MIDAMERICAN ENERGY COMPANY Iowa THE REFERRAL COMPANY Iowa SELECT RELOCATION SERVICES, INC. Iowa EDINA REALTY MORTGAGE, LLC Delaware CBSHOME REAL ESTATE COMPANY Nebraska MIDAMERICAN HOME SERVICES MORTGAGE, LLC Iowa TITLE INFORMATION SERVICES, LLC Minnesota QUAD CITIES ENERGY COMPANY Iowa CORDOVA ENERGY COMPANY LLC Iowa MIDWEST GAS COMPANY Iowa DCCO, INC. Minnesota INTERCOAST SIERRA POWER COMPANY Delaware MIDAMERICAN ENERGY FINANCING II Delaware BETTENDORF LOCK & SECURITY SERVICES, INC. Iowa SUTTON SECURITY, INC. Nebraska PRO-TEC ALARM SYSTEMS AND SERVICES, INC. Missouri CBS BROKERAGE SYSTEMS, INC Nebraska CBEC RAILWAY INC. Iowa MIDAMERICAN ENERGY FINANCING I Delaware MIDAMERICAN ENERGY FUNDING CORPORATION Delaware MIDAMERICAN CAPITAL COMPANY Delaware MHC INVESTMENT COMPANY South Dakota MWR CAPITAL INC. South Dakota MIDWEST CAPITAL GROUP, INC. Iowa DAKOTA DUNES DEVELOPMENT COMPANY Iowa TWO RIVERS INC. South Dakota MIDAMERICAN SERVICES COMPANY Iowa NORTHERN ELECTRIC & GAS LIMITED United Kingdom NORTHERN ELECTRIC INVESTMENTS LIMITED United Kingdom CALENERGY EUROPE LIMITED United Kingdom NORTHERN AURORA LIMITED United Kingdom RYHOPE ROAD DEVELOPMENTS LTD. United Kingdom KINGS ROAD DEVELOPMENTS LIMITED United Kingdom SEAL SANDS NETWORK LTD. United Kingdom -4- TEESSIDE POWER LIMITED United Kingdom KIRKHEATON WIND LIMITED United Kingdom VEHICLE LEASE AND SERVICE LIMITED United Kingdom CE TURBO LLC Delaware CE TEXAS FUEL, LLC Delaware CE TEXAS POWER, LLC Delaware CE TEXAS PIPELINE, LLC Delaware CE TEXAS RESOURCES, LLC Delaware CE ADMINISTRATIVE SERVICES, INC. Delaware AMERICAN PACIFIC FINANCE COMPANY Delaware CALENERGY COMPANY, INC. Delaware SALTON SEA MINERALS CORP. Delaware CALENERGY INTERNATIONAL, INC. Delaware CORDOVA FUNDING CORPORATION Delaware GILBERT/CBE INDONESIA L.L.C. Nebraska -5- EX-23 3 AUDITOR'S CONSENT Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statements No. 33-51363, No. 333-32821 and No. 333-62697 on Form S-3 of MidAmerican Energy Holdings Company of our report dated January 25, 2000 (March 14, 2000 as to Note 3) appearing in the Annual Report on Form 10-K of MidAmerican Energy Holdings Company for the year ended December 31, 1999. Des Moines, Iowa March 30, 2000 EX-24 4 POWER OF ATTORNEY Exhibit 24 POWER OF ATTORNEY ----------------- The undersigned, a member of the Board of Directors or an officer of MIDAMERICAN ENERGY HOLDINGS COMPANY, an Iowa corporation (the "Company"), hereby constitutes and appoints Steven A. McArthur 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, 1999 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. Executed as of March 29, 2000 /s/ David L. Sokol /s/ Gregory E. Abel - ------------------------------------ ----------------------------------- DAVID L. SOKOL GREGORY E. ABEL /s/ Patrick J. Goodman /s/ Stanley J. Bright - ------------------------------------ ----------------------------------- PATRICK J. GOODMAN STANLEY J. BRIGHT /s/ Edgar D. Aronson /s/ Walter Scott Jr. - ------------------------------------ ----------------------------------- EDGAR D. ARONSON WALTER SCOTT, JR. /s/ Warren Buffett - ------------------------------------ ----------------------------------- RICHARD R. JAROS WARREN BUFFETT /s/ Marc D. Hamburg /s/ W. David Scott - ------------------------------------ ----------------------------------- MARC D. HAMBURG W. DAVID SCOTT /s/ John Boyer - ------------------------------------ JOHN BOYER EX-27 5 ART. 5 FDS - 12/31/99 MEHC
5 0001081316 MIDAMERICAN ENERGY HOLDINGS COMPANY 1,000 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 352,621 226,298 600,564 0 0 1,138,313 5,463,329 695,801 10,766,352 1,522,595 6,113,746 551,598 146,606 0 994,588 10,766,352 0 4,398,783 0 3,133,442 427,690 0 426,173 357,069 93,475 216,671 0 (49,441) 0 167,230 2.79 2.59
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