Item 1. Business
General
MidAmerican Energy Holdings Company and its subsidiaries (the "Company" or "MEHC") is a United States-based privately owned global energy company with publicly traded fixed income securities. Through its subsidiaries, MidAmerican Energy Company ("MidAmerican Energy") and CE Electric UK Funding, the Company currently serves approximately 4.3 million electricity customers and 652,000 natural gas customers worldwide. In addition, through its subsidiaries, the Company owns interests in over 10,000 megawatts ("MW") of diversified power generation facilities in operation, construction and development. 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 Fitch ("Fitch"). The Company's utility subsidiaries are also investment grade rated by Moody's, S&P and Fitch: MidAmerican Energy (A3, A- and AA-), Northern Electric, plc (A3, A- and A-) and Yorkshire Electricity Group, plc (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.
Teton Transaction
On March 14, 2000, the Company and an investor group comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol, Chairman and Chief Executive Officer of the Company, and Gregory E. Abel, Chief Operating Officer of the Company closed on a definitive agreement and plan of merger whereby the investor group acquired all of the outstanding common stock of the Company (the "Teton Transaction"). As a result of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel became the sole shareholders of the Company in a "going private" transaction.
Business Strategy
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.
Business of MEHC
The Company 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 five separate platforms: MidAmerican Energy, CE Electric UK Funding, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign, and HomeServices.
MidAmerican Energy
MidAmerican Energy is the largest energy company headquartered in Iowa, with assets at December 31, 2001 and 2001 revenues totaling $3.6 billion and $2.7 billion, respectively. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electric energy and in distributing, selling and transporting natural gas. MidAmerican Energy 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, 2001, MidAmerican Energy had 673,000 retail electric customers and 652,000 retail natural gas customers.
In addition to retail sales, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities outside of MidAmerican Energy's delivery system. These sales are referred to as wholesale 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.
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 4% of its total 2001 electric operating revenues or 4% of its total 2001 gas operating margin. Among the primary industries served by MidAmerican Energy are those which are concerned with food products, the manufacturing, processing and fabrication of primary metals, real estate, farm and other non-electrical machinery, and cement and gypsum products.
For the year ended December 31, 2001, MidAmerican Energy derived approximately 48% of its gross operating revenues from its regulated electric business, 32% from its regulated gas business and 20% from its nonregulated business activities. For 2000 and 1999, the corresponding percentages were 48% electric, 37% gas and 15% nonregulated; and 63% electric, 30% gas and 7% nonregulated, respectively. The change in revenue mix is principally driven by an increase in natural gas prices and in nonregulated natural gas sales activity.
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 2001, 38% of MidAmerican Energy's regulated electric revenues were reported in the months of June, July, August and September, and 59% of MidAmerican Energy's regulated gas revenues were reported in the months of January, February, March and December.
Electric Operations
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 may have a significant impact on the way MidAmerican Energy does business.
MidAmerican Energy manages its operations as four separate business units: generation, energy delivery, transmission and marketing and sales. The generation segment derives most of its revenue from the sale of regulated wholesale electricity and nonregulated wholesale and retail natural gas. The energy delivery segment derives its revenue principally from the delivery of retail electricity and natural gas, while the transmission segment obtains most of its revenue from the sale of transmission capacity. The marketing and sales segment receives its revenue principally from nonregulated sales of natural gas and electricity.
The following tables present historical regulated electric sales data related to customer class and jurisdictions.
Total Regulated Electric Sales of MidAmerican Energy By Customer Class
2001 2000 1999
Residential 20.6% 20.7% 21.0% Small General Service 15.3 15.9 16.7 Large General Service 25.8 28.6 26.9 Other 7.3 5.4 4.5 Sales for Resale 31.0 29.4 30.9 ----- ----- ----- Total 100.0% 100.0% 100.0% ====== ====== ======
Regulated Retail Electric Sales of MidAmerican Energy By State
2001 2000 1999
Iowa 88.6% 89.3% 88.9% Illinois 10.6 10.0 10.4 South Dakota 0.8 0.7 0.7 ------ ------ ------ Total 100.0% 100.0% 100.0% ====== ====== ======
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 August 2001, MidAmerican Energy recorded an hourly peak demand of 3,758 MW, which is 75 MW less than MidAmerican Energy's previous record hourly peak of 3,833 MW set in 1999.
The following table sets out certain information concerning various MidAmerican Energy power generation facilities:
- ------------------------- -------- ------- ------- ---------- ------------ Operating Project(1) Facility Net MW Fuel Location Commercial Net MW Owned(2) Operation - ------------------------- -------- ------- ------- ---------- ------------ Council Bluffs Energy Center units 1 & 2 131 131 Coal Iowa 1954, 1958 - ------------------------- -------- ------- ------- ---------- ------------ Council Bluffs Energy Center unit 3 675 534 Coal Iowa 1978 - ------------------------- -------- ------- ------- ---------- ------------ Louisa Generation Station 700 616 Coal Iowa 1983 - ------------------------- -------- ------- ------- ---------- ------------ Neal Generation Station units 1 & 2 435 435 Coal Iowa 1964, 1972 - ------------------------- -------- ------- ------- ---------- ------------ Neal Generation Station unit 3 515 371 Coal Iowa 1975 - ---------------------------------- ------- ------- ---------- ------------ Neal Generation Station unit 4 624 261 Coal Iowa 1979 - ------------------------- -------- ------- ------- ---------- ------------ Ottumwa Generation Station 708 368 Coal Iowa 1981 - ------------------------- -------- ------- ------- ---------- ------------ Quad Cities Generating Station 1,529 383 Nuclear Illinois 1972 - ------------------------- -------- ------- ------- ---------- ------------ Riverside Generation Station 135 135 Coal Iowa 1925-61 - ------------------------- -------- ------- ------- ---------- ------------ Combustion Turbines 789 789 Gas/Oil Iowa 1969-95 - ------------------------- -------- ------- ------- ---------- ------------ Moline Water Power 3 3 Hydro Illinois 1970 - ------------------------- -------- ------- ------- ---------- ------------ Cooper Nuclear Station(3) 758 379 Nuclear Nebraska 1974 - ------------------------- -------- ------- ------- ---------- ------------ Portable Power Modules 56 56 Oil Iowa 2000 - ------------------------- -------- ------- ------- ---------- ------------ Total Operating Power Generation Facilities 7,058 4,461 - ------------------------- -------- ------- ------- ---------- ------------ Projects Under Construction: - ------------------------ --------- ------- ------- ---------- ------------ Greater Des Moines Energy Center 540 540 Gas Iowa 2003-05 - ------------------------ --------- ------- ------- ---------- ------------ Total Power Generation Facilities 7,598 5,001 - ------------------------ --------- ------- ------- ---------- ------------
(1) The Company operates all such power generation facilities other than Quad Cities Generating Station, Ottumwa Generation Station and Cooper Nuclear Station. (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) Cooper is owned by the Nebraska Public Power District and the amount shown is MidAmerican Energy's entitlement (50%) of Cooper's accredited capacity under a power purchase contract extending to September 2004.
MidAmerican Energy's accredited net generating capability in the summer of 2001 was 4,735 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 power purchase contracts. The net generating capability at any time may be less than it would otherwise be due to regulatory restrictions, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling or modifications.
On July 10, 2001, MidAmerican Energy announced plans to develop and con- struct two electric generating plants in Iowa, requiring an investment of approximately $1.8 billion. Participation by others in a portion of the second plant is being discussed. The two plants will provide approximately 1,400 megawatts of generating capacity. MidAmerican Energy expects to begin construction in the Spring 2002 on the first project, the Greater Des Moines Energy Center, a 540-megawatt natural gas-fired combined cycle unit that has an estimated cost of $416 million. It is anticipated that the first phase of the project will be completed in 2003 with the remainder being completed in 2005. MidAmerican Energy presently expects that all utility construction expenditures for the next five years will be met with the issuance of long-term debt and cash generated from utility operations, net of dividends. The actual level of cash generated from utility operations is affected by, among other things, economic conditions in the utility service territory, weather and federal and state regulatory actions.
MidAmerican Energy is interconnected with 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 Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP facilitates operation of the transmission system and is responsible for the safety and reliability of the bulk electric system.
In November 2001, MAPPCOR, the contractor to MAPP, sold its transmission-related assets to the Midwest Independent Transmission System Operator, Inc. ("Midwest ISO"). The Midwest ISO now has responsibility for administration of MAPP's Open-Access Transmission Tariff.
Each MAPP participant is required to maintain for emergency purposes a net generating capability reserve of at least 15% above its system peak demand. MidAmerican Energy's reserve margin at peak demand for 2001 was approximately 25%. However, significantly higher-than-normal temperatures during the cooling season could cause MidAmerican Energy's reserve to fall below the 15% minimum. If MidAmerican Energy fails to maintain the appropriate reserve, significant penalties could be contractually imposed by MAPP.
MidAmerican Energy's transmission system connects its generating facilities with distribution substations and interconnects with 14 other transmission providers in Iowa and five adjacent states. Under normal operating conditions, MidAmerican Energy's transmission system is unconstrained and has adequate capacity to deliver energy to MidAmerican Energy's distribution system and to export and import energy with other interconnected systems.
In December 1999, the Federal Energy Regulatory Commission ("FERC") issued Order No. 2000 establishing, among other things, minimum characteristics and functions for regional transmission organizations. Public utilities that were not a member of an independent system operator at the time of the order were required to submit a plan by which its transmission facilities would be transferred to a regional transmission organization. On September 28, 2001 MidAmerican Energy and five other electric utilities filed with the FERC a plan to create TRANSLink Transmission Company LLC and to integrate their electric transmission systems into a single, coordinated system operating as a for-profit independent transmission company in conjunction with a FERC-approved regional transmission organization. FERC approval of the plan is pending. Transferring operation and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.
Gas Operations
The following tables present historical regulated gas sales data, excluding transportation throughput, related to customer class and jurisdictions.
Total Regulated Gas Sales of MidAmerican Energy By Customer Class
2001 2000 1999
Residential 34.5% 34.9% 39.1% Small General Service 18.2 17.4 19.8 Large General Service 1.5 2.2 2.4 Other 1.7 1.2 1.7 Sales for Resale 44.1 44.3 37.0 ------ ------- ------ Total 100.0% 100.0% 100.0% ====== ======= ======
Regulated Retail Gas Sales of MidAmerican Energy By State
2001 2000 1999
Iowa 78.9% 78.0% 78.8% Illinois 9.8 10.2 10.3 South Dakota 10.5 11.0 10.1 Nebraska 0.8 0.8 0.8 ------ ------ ------ Total 100.0% 100.0% 100.0% ====== ====== ======
On February 2, 1996, MidAmerican Energy had its highest natural gas peak-day delivery of 1,143,026 MMBtus. This peak-day delivery consisted of approximately 88% traditional sales service and 12% transportation service of customer-owned gas. MidAmerican Energy's 2001/2002 winter heating season peak-day delivery of 932,615 MMBtus was reached on March 3, 2002. This peak-day delivery included approximately 73% traditional sales service and 27% transportation service.
MidAmerican Energy purchases gas supplies from producers and third party marketers. To ensure system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the gas supplies.
MidAmerican Energy has rights to firm pipeline capacity to transport gas to its service territory through direct interconnects to the pipeline systems of Northern Natural Gas, Natural Gas Pipeline Company of America, Northern Border Pipeline Company and ANR Pipeline Company. Firm capacity in excess of MidAmerican Energy's system needs, resulting from differences between the capacity portfolio and seasonal system demand, can be resold to other companies to achieve optimum use of the available capacity. Past Iowa Utilities Board ("IUB") and South Dakota Public Utility Commission rulings have allowed MidAmerican Energy to retain 30% of Iowa and South Dakota margins, respectively, earned on the resold capacity, with the remaining 70% being returned to customers through the purchased gas adjustment clause.
MidAmerican Energy's cost of gas is recovered from customers through purchased gas adjustment clauses. In 1995, the IUB gave initial approval of MidAmerican Energy's Incentive Gas Supply Procurement Program, which currently has been extended through 2002. Under the program, as amended, MidAmerican Energy is required to file with the IUB every six months a comparison of its gas procurement costs to an index-based reference price. If MidAmerican Energy's cost of gas for the period is less or greater than an established tolerance band around the reference price, then MidAmerican Energy shares a portion of the savings or costs with customers. A similar program is in effect in South Dakota. Since the implementation of the program, MidAmerican Energy has successfully achieved and shared savings with its natural gas customers.
MidAmerican Energy utilizes leased gas storage to meet peak day require- ments and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during the summer months. In addition, MidAmerican Energy also utilizes three liquefied natural gas plants and two propane-air plants to meet peak day demands.
MidAmerican Energy has strategically built multiple pipeline interconnections into several of its larger communities. Multiple pipeline interconnects create competition among pipeline suppliers for transportation capacity to serve those communities, thus reducing costs. In addition, multiple pipeline interconnects give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various pipeline supply basins into these communities and increase delivery reliability. Benefits to MidAmerican Energy's system customers are shared with all jurisdictions through a consolidated purchased gas adjustment clause.
CE Electric UK Funding
The business of CE Electric UK Funding consists of Northern Electric plc ("Northern"), Yorkshire Power Group Ltd. ("Yorkshire"), and CalEnergy Gas (Holdings) Limited ("CE Gas").
Yorkshire Swap
On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary of the Company, and Innogy Holdings, plc closed an agreement to exchange Northern's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern's supply business was initially valued at approximately $430 million ((pound)295 million), including working capital of approximately $53 million ((pound)37 million). 94.75% of Yorkshire's distribution business was initially valued at approximately $395 million ((pound)271 million), including working capital of approximately $48 million ((pound)33 million). The net cash received by Northern for the exchange was approximately $35 million ((pound)24 million). Working capital is subject to adjustment and is currently under review.
The Company paid $37.4 million, net of cash acquired of $362.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness. The acquisition has been accounted for as a purchase business combination. The results of operations for Yorkshire are included in the Company's results beginning September 21, 2001. This transaction provides the opportunity to build on Northern and Yorkshire's strong reputations for customer satisfaction by bringing together the skills and resources of two neighboring distribution businesses to create one of the largest distribution companies in the U.K., serving more than 3.6 million customers in an area of approximately 10,000 square miles.
Electricity Distribution
Northern's and Yorkshire's operations consist primarily of the distribu- tion of electricity and other auxiliary businesses in the United Kingdom. Through September 21, 2001, Northern's operations also included the supply of electricity and natural gas and the related metering business.
Northern and Yorkshire receive electricity from the national grid transmission system and distribute it to customers' premises using their network of transformers, switchgear and cables. Substantially all of the customers in their distribution service areas are connected to their network and can only be delivered through their distribution system, thus providing Northern and Yorkshire with distribution volume that is stable from year to year. Northern and Yorkshire charge 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.
Integrated Utility Services Limited ("IUS"), a subsidiary of Northern, is an engineering company whose main role is to provide electrical connection services on behalf of CE Electric UK Funding's distribution businesses and to provide electrical infrastructure contracting services to third parties. The acquisition by CE Electric UK Funding in 2001 of Yorkshire has presented IUS the opportunity to integrate all Yorkshire and external work into IUS thereby creating one of the largest electricity connection companies in the UK. The focus for IUS is to achieve the full integration of the connections businesses. To achieve this aim, IUS has already commenced with the establishment of a customer services operations center at Middlesbrough and the commissioning of a dedicated data management and telephone system to facilitate these objectives.
Northern Electric Generation Limited ("Northern Generation"), a CE Electric UK Funding subsidiary, primarily focuses on electricity generation, mainly through its ownership in Teesside (described below) and its operation and ownership of Viking (described below).
Teesside. Teesside Power Limited ("Teesside") owns and operates an 1,875 net MW combined cycle gas-fired power plant at Wilton. Northern Generation owns a 15.4% interest in Teesside, but does not operate the plant. Enron Corp. ("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668 MW of capacity. Enron's subsidiary, who owns and operates Teesside, is now in administration and administrators have been appointed to run its business and are attempting to find a buyer.
As a result of Enron's subsidiary being in administration, Teesside is in discussion with its lenders over a restructuring of the (pound)650 million debt still outstanding. It is anticipated that there will be no further dividends arising from this investment and, as a result, Northern Generation has written off its equity investments as they were estimated to be of negligible value.
Viking. Northern Generation owns 50% of this 50 MW gas-fired mid merit power plant located on Teesside. The plant is currently in the commissioning stage, however due to combustor issues it is unable to pass the performance criteria required for hand-over. Northern Generation 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 Northern Generation. CE Electric UK Funding is currently negotiating to sell Viking to Rolls Royce for a value consistent with the original investment appraisal.
Northern Electric Retail Limited ("Northern Retail"), a subsidiary of CE Electric UK Funding, sells electrical and gas appliances.
Gas Exploration and Production
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 shown below. CE Gas has also been involved in certain gas development and exploration activities relating to a large gas field prospect in Poland, the EP389 concession in the Perth Basin in Australia and the Yolla discovery in the Bass Basin of Australia.
CalEnergy Generation - Domestic
The following table sets out certain information concerning various domestic independent power projects in operation.
- -------------------- -------- ------- ----- ------------ ---------- ------------ Project Facility Net MW Fuel Location Commercial Power Net MW Owned1 Operation Purchaser2 - -------------------- -------- ------- ----- ------------ ---------- ------------ Cordova 537 537 Gas Illinois 2001 El Paso/MEC - -------------------- -------- ------- ----- ------------ ---------- ------------ Salton Sea I 10 5 Geo California 1987 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Salton Sea II 20 10 Geo California 1990 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Salton Sea III 50 25 Geo California 1989 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Salton Sea IV 40 20 Geo California 1996 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Salton Sea V 49 25 Geo California 2000 El Paso/Zinc - -------------------- -------- ------- ----- ------------ ---------- ------------ Vulcan 34 17 Geo California 1986 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Elmore 38 19 Geo California 1989 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Leathers 38 19 Geo California 1990 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ Del Ranch 38 19 Geo California 1989 Edison - -------------------- -------- ------- ----- ------------ ---------- ------------ CE Turbo 10 5 Geo California 2000 El Paso/Zinc - -------------------- -------- ------- ----- ------------ ---------- ------------ Saranac 240 90 Gas New York 1994 NYSEG - -------------------- -------- ------- ----- ------------ ---------- ------------ Power Resources 200 100 Gas Texas 1988 TXU - -------------------- -------- ------- ----- ------------ ---------- ------------ Yuma 50 25 Gas Arizona 1994 SDG&E - -------------------- -------- ------- ----- ------------ ---------- ------------ Roosevelt Hot Springs 23 17 Geo Utah 1984 UP&L - -------------------- -------- ------- ----- ------------ ---------- ------------ Total CalEnergy Generation - Domestic Operations 1,377 933 - -------------------- -------- ------- ----- ------------ ---------- ------------
1 Actual MW may vary depending on operating and reservoir conditions and plant design. Facility Net Capacity (in MW) represents facility gross capacity (in MW) less parasitic load. Parasitic load is electrical output used by the facility and not made available for sale to utilities or other outside purchasers. Net MW owned indicates current legal ownership, but, in some cases, does not reflect the current allocation of partnership distributions. 2 Southern California Edison Company ("Edison"); San Diego Gas & Electric Company ("SDGandE"); Utah Power & Light Company ("UP&L"); New York State Electric & Gas Corporation ("NYSEG"); TXU Generation Company LP ("TXU"); Zinc Recovery Project ("Zinc"); El Paso Corporation ("El Paso") and MidAmerican Energy Company ("MEC").
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova Project commenced commercial operations in June 2001. Cordova Energy entered into a power purchase agreement with a unit of El Paso Corporation ("El Paso") in which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. Cordova Energy exercised an option under the El Paso power purchase agreement to callback 50% of the project output for sales to others for the contract years ending on or prior to May 14, 2004. Cordova Energy subsequently entered into a power purchase agreement with MidAmerican Energy whereby MidAmerican Energy will purchase 50% of the capacity and energy from the Cordova Project until May 14, 2004.
The Company has a 50% ownership interest in CE Generation LLC ("CE Generation") which has interests in ten geothermal plants in the Imperial Valley, California and three natural gas-fired cogeneration plants. For purposes of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V plants (collectively the "Salton Sea Projects") are based on capacity amounts of 10, 20, 50, 40 and 49 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. 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.
Imperial Valley Projects. The Vulcan Project, Hoch (Del Ranch) Project, Elmore Project, Leathers Project, Salton Sea II Project and the Salton Sea III Project sell electricity to Southern California Edison Company ("Edison") under 30-year Standard Offer No. 4 Agreements ("SO4 Agreements"). Under the SO4 Agreements, Edison is obligated to pay capacity payments, capacity bonus payments and energy payments. The price for contract capacity payments is fixed for the life of such SO4 Agreement. The contract energy payment was fixed for the first ten years. The fixed price periods for the Vulcan, Del Ranch, Elmore, Leathers, Salton Sea II and Salton Sea III Projects expired in February 1996, January 1999, December 1998, December 1999, April 2000, and February 1999, respectively. Thereafter, the energy payments are based on the cost Edison avoids by purchasing energy from the projects instead of obtaining the energy from other sources ("Avoided Cost of Energy").
In June and November 2001, the Imperial Valley Projects which receive Edison`s Avoided Cost of Energy, entered into agreements that provide for amended energy payments under the SO4 Agreements. The amendments provide for fixed energy payments per kWh in lieu of Edison's Avoided Cost of Energy. The fixed energy payment is 3.25 cents per kWh from December 1, 2001 through April 30, 2002 and 5.37 cents per kWh commencing May 1, 2002 for a five year period. Following the five year period, the energy payments revert back to Edison's Avoided Cost of Energy.
The Salton Sea I Project and Salton Sea IV Project have negotiated contracts with Edison. The Salton Sea I contract provides for a capacity payment and energy payment for the life of the contract. Both payments are based upon an initial value that is subject to quarterly adjustment by reference to various inflation-related indices. The Salton Sea IV contract also provides for fixed price capacity payments for the life of the contract. Approximately 56% of the kWhs are sold under the Salton Sea IV Power Purchase Agreement at a fixed energy price, which is subject to quarterly adjustment by reference to various inflation-related indices, through June 20, 2017 (and at Edison's Avoided Cost of Energy thereafter), while the remaining 44% of the Salton Sea IV Project kWhs are sold according to a 10-year fixed price schedule followed by payments based on a modified Avoided Cost of Energy for the succeeding 5 years and at Edison's Avoided Cost of Energy thereafter.
The Salton Sea V Project began operations in 2000 and will sell approxi- mately one-third of its net output to the Zinc Recovery Project which is expected to become operational in 2002. The remainder is being sold through other market transactions.
The net output of the Turbo Project is being sold through market trans- actions but may be sold to the Zinc Recovery Project when completed.
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 agreement ("Yuma PPA"). 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"). 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.
Saranac Project. The Saranac Project is a 240 net MW natural gas-fired cogeneration facility located in Plattsburgh, New York. 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 agreement (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 and General Electric Capital Corporation.
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 TXU Generation Company LP, formerly known as Texas Utilities Electric Company. 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-Dreyfus Gas Supply Agreement contains rates that are fixed for the respective contract terms. Revenues escalate at a higher rate than fuel costs.
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.
Zinc Recovery Project. The Company 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. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Projects.
CalEnergy 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"). Facilities are being installed near the Imperial Valley Project's 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 operations in 2002. 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.
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.
CalEnergy Generation - Foreign
The following table sets out certain information concerning various foreign independent power projects in operation.
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively, the "Leyte Projects"), which are geothermal power plants located on the island of Leyte in the Philippines, and the Casecnan Project, a combined irrigation and hydroelectric power generation project, which is located in the central part of Island of Luzon in the Philippines. The Casecnan Project commenced commercial operations on December 11, 2001. For purposes of consistent presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and Casecnan are 119, 216, 165 and 150 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.
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.
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 Corporation ("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 which is 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. 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 the Philippine National Power Corporation ("NPC") for distribution to the island of Luzon.
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 approximately 97% of total revenues at the design capacity levels and the energy fees are 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). 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.
The Malitbog Project is located on land provided by PNOC-EDC at no cost. The electrical energy produced by the facility is 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, which provides that all of PNOC-EDC's obligations pursuant to the Malitbog ECA carry the full faith and credit of, and are affirmed and guaranteed by, the Government of the Philippines.
PNOC-EDC is obligated to purchase VGPC's interest in the facility under certain circumstances, including (i) certain material changes in policies or laws which adversely affect VGPC's interest in the project, (ii) any event of force majeure which delays performance by more than 90 days and (iii) certain other events. The price will be the net present value of the capital cost recovery fees that would have been due for the remainder of the Cooperation Period with respect to such generating unit(s).
The Malitbog ECA cooperation period expires ten years after the date of commencement of commercial operation of Unit III (the "Cooperation Period"). At the end of the Cooperation Period, the facility will be transferred to PNOC-EDC at no cost, on an "as is" basis.
Casecnan. CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE Casecnan") and an indirectly majority owned subsidiary of the Company, operates the Casecnan Project, a combined irrigation and 150 net MW hydroelectric power generation project (the "Casecnan Project"). The Casecnan Project consists generally of diversion structures in the Casecnan and Taan Rivers that captures and diverts excess water in the Casecnan watershed by means of concrete, in-stream diversion weirs and transfers that water through a transbasin tunnel of approximately 23 kilometers (including the intake audit from the Taan to the Casecnan River), with a diameter of approximately 6.5 meters to an existing underutilized water storage reservoir at Pantabangan. During the water transfer, the elevation differences between the two watersheds allows electrical energy to be generated at a 150 net MW rated capacity power plant, which is located in an underground powerhouse cavern at the end of the water tunnel. A tailrace discharge tunnel of approximately three kilometers delivers water from the water tunnel and the powerhouse to the Pantabangan Reservoir, providing additional water for irrigation and increasing the potential electrical generation at two downstream existing hydroelectric facilities of NPC, the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines.
CE Casecnan constructed 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 developed, financed and constructed the Casecnan Project over the construction period, and will 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 fixed fee for the delivery of a minimum volume of water and a fixed fee for the delivery of a minimum amount of electricity. 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 fixed fees for the delivery of water and energy, regardless of the amount of electricity or water actually delivered, are expected to provide approximately 78% of CE Casecnan's revenues. 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 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 Philippine 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.
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 ("Performance Undertaking"). The Project Agreement and the Performance Undertaking provide for the resolution of disputes by binding arbitration in Singapore under international arbitration rules.
HomeServices
HomeServices.Com Inc. ("HomeServices"), a wholly-owned subsidiary of the Company, is the second largest residential real estate brokerage firm in the United States based on aggregate closed transaction sides in 2001 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 in the following fourteen states: Minnesota, Iowa, California, Arizona, Kansas, Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota, South Dakota and Georgia. HomeServices generally 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, 2001. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Los Angeles and San Diego, California; Omaha, Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson, Arizona; Annapolis, Maryland and Atlanta, Georgia.
Regulatory Matters
United States
Each of the operating domestic power facilities partially owned through CE Generation meets the requirements promulgated under the Public Utility Regulatory Policies Act ("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 Avoided Cost of Energy, (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.
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 Cost of Energy. 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 an independent system operator and direct access to generation for all power purchasers under certain circumstances. Under the bill, consistent with the requirements of PURPA, the 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 impact on its operations.
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 connection with the March 1999 approval by the IUB of the MidAmerican acquisition and March 2000 affirmation as part of the Teton Transaction, the Company is required, among other things, to use all commercially reasonable efforts to maintain an investment grade credit rating for MidAmerican Energy and its long-term debt and to seek the approval of the IUB 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 circumstances. MidAmerican Energy's common equity level at December 31, 2001 was above these levels.
With the elimination of the energy adjustment clause in Iowa, MidAmerican Energy is financially exposed to movements in energy prices. Although MidAmerican Energy has sufficient low cost generation under typical operating conditions for its retail electric needs, a loss of adequate generation by MidAmerican Energy requiring the purchase of replacement power at a time of high market prices could subject MidAmerican Energy to losses on its energy sales.
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, larger non-residential customers in Illinois and 33% of the remaining non-residential Illinois customers were allowed to select their provider of electric supply services beginning in October 1, 1999. Starting December 31, 2000, all other non-residential customers were allowed supplier choice. Residential customers all receive the opportunity to select their electric supplier beginning May 1, 2002.
The law also provides for Illinois earnings above a computed level of return on common equity to be shared equally between customers and MidAmerican Energy. MidAmerican Energy's computed level of return on common equity is based on a rolling two-year average of the 30-year Treasury Bond rates plus a premium of 5.5% for 1998 and 1999 and a premium of 8.5% for 2000 through 2004. The two-year average above which sharing must occur for 2001 was 14.34%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of regulatory assets.
In December 1999, FERC issued Order No. 2000 establishing among other things minimum characteristics and functions for regional transmission organizations. Public utilities that were not a member of an independent system operator at the time of the order were required to submit a plan by which its transmission facilities would be transferred to a regional transmission organization. On September 28, 2001, MidAmerican Energy and five other electric utilities filed with FERC a plan to create TRANSLink Transmission Company LLC and to integrate their electric transmission systems into a single, coordinated system operating as a for-profit independent transmission company in conjunction with a FERC approved regional transmission organization. FERC approval of the plan is pending. Transferring operation and control of MidAmerican Energy's transmission assets to other entities could increase costs for MidAmerican Energy; however, the actual impact of TRANSLink on MidAmerican Energy's future transmission costs is not yet known.
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
Since 1990, the electricity industry in Great Britain has seen the privatization of electric generation, supply and distribution, and the introduction of competition in generation and supply. Electricity is produced by generators, transmitted through the national grid transmission system by The National Grid Company plc ("NGC") (or in Scotland by Scottish Power or Scottish Hydro Electric) and distributed to customers by the fourteen Distribution License Holders ("DLHs") in their respective distribution service areas. 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.
Under the Utilities Act 2000, the Public Electricity Supply License granted at privatization was replaced by two separate licenses - the Electricity Distribution license and the Electricity Supply license. The Public Electricity Supplier ("PES") licenses formerly held by Northern Electric plc and Yorkshire Electricity Group plc were split so that separate subsidiaries held licenses for distribution and electricity supply. In order to comply with the legislation the Northern Electric plc and Yorkshire Electricity Group plc each made a Statutory Transfer Scheme ("Scheme") that was approved by the Secretary of State for Trade and Industry. The Schemes provide for the transfer of certain assets and liabilities to the licensed subsidiaries. This occurred on October 1, 2001, a date set by the Secretary of State for Trade and Industry. As a consequence of the Schemes the electricity distribution businesses of Northern Electric plc and Yorkshire Electricity Group plc were transferred to Northern Electric Distribution Ltd ("NEDL") and Yorkshire Electricity Distribution plc ("YEDL"), respectively. NEDL and YEDL are each holders of an electricity distribution license.
Each of the DLHs is required to offer terms for connection to its distribution system and for use of its distribution system to any person. In providing the use of its distribution system, a DLH must not discriminate between users, nor may its charges differ except where justified by differences in cost.
Most revenue of the DLHs is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where the Retail Price Index ("RPI") 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 adjustment factor ("Xd") which was established by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the last price control review (and continues to be 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. This formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a DLH is entitled to charge. The distribution price control formula permits DLHs 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 DLH from year to year. It is a control on revenue that operates independently of most of the DLH'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 Ofgem in 1999, the allowable revenue of NEDL's predecessor, Northern Electric plc, was reduced by 24%, and the allowable revenue of YEDL's predecessor, Yorkshire Electricity Group plc, was reduced by 23%, with effect from April 1, 2000. As part of the review, the Xd factor was not modified and therefore remained at 3%.
The distribution prices allowable under the current distribution price control formula are expected to be reviewed by Ofgem 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. Accordingly Ofgem is proposing to modify the licenses of all DLHs to implement the Information and Incentives Project under which up to two per cent of regulated income will depend upon the performance of the DLH's distribution system as measured by the number and duration of customer interruptions and upon the level of customer satisfaction monitored by Ofgem.
Philippines
The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 which is aimed at restructuring the electric industry, privatizing of the NPC and introducing a competitive electricity market, among others. The passage of the bill may have an impact on the Company's future operations and the industry as a whole, the effect of which is not yet determinable and estimable.
Environmental Regulation
United States
The Company is subject to a number of environmental laws and other regulations affecting many aspects of its present and future operations. 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.
The Clean Air Act Amendments of 1990 ("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 requirements and fees and emissions of certain substances. MidAmerican Energy has five jointly owned and six wholly owned coal-fired generating units, which represent approximately 60% of MidAmerican Energy's electric generating capability. MidAmerican Energy's generating units meet all requirements under Title IV of the CAAA. 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.
In accordance with the requirements of Section 112 of the CAAA, the Environmental Protection Agency ("EPA") has performed a study of the hazards to public health reasonably anticipated to occur as a result of emissions of hazardous air pollutants by electric utility steam generating units. In February 1998, EPA issued its Final Report to Congress, indicating that mercury is the hazardous air pollutant of greatest potential concern from coal-fired generating units and that additional research and monitoring are necessary. As such the EPA issued a request under Section 114 of the CAAA requiring all electric utilities to provide information that will allow the EPA to calculate the annual mercury emissions from each coal-fired generating unit for the calendar year 1999. In December 2000, the EPA concluded that it is appropriate and necessary to regulate mercury emissions from coal-fired generating units. It is anticipated that rules will be developed to regulate these emissions in 2003 or 2004. The cost to MidAmerican Energy of reducing its mercury emissions would depend on available technology at the time, but could be material.
State and federal environmental laws and regulations currently have, and future modifications may have, the effect of increasing the lead time for the construction of new facilities, significantly increasing the total cost of new facilities, requiring modification of the Company's existing facilities, increasing the risk of delay on construction projects, increasing the Company's cost of waste disposal and 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.
United Kingdom
CE Electric UK Funding's businesses are subject to numerous regulatory requirements with respect to the protection of the environment. The Electricity Act 1989 obligates either the UK Secretary of State or the Director General of Electric Supply 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 CE Electric UK Funding 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. CE Electric UK Funding 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.
CE Electric UK Funding's policy is to carry out its activities in such a manner as to minimize the impact of its works and operations on the environment, and in accordance with environmental legislation and good practice. There have not been any significant regulatory environmental compliance issues and there are no material legal or administrative proceedings pending against CE Electric UK Funding with respect to any environmental matter.
Employees
As of December 31, 2001, the Company and its subsidiaries employed approximately 9,780 people.
As of December 31, 2001, MidAmerican Energy employed approximately 3,770 people, of which approximately 47% are represented by labor unions. MidAmerican Energy believes that its relations with its employees are good.
As of December 31, 2001, CE Electric UK Funding employed approximately 3,460 people, of which approximately 76% are represented by labor unions. All CE Electric UK Funding 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. CE Electric UK Funding believes that its relations with its employees are good.
As of December 31, 2001, the CalEnergy Generation platforms employed approximately 560 people, of which approximately 240 people were in the Philippines. None of CalEnergy Generation's employees are covered by a collective bargaining agreement. Management believes that CalEnergy Generation's relations with its employees are good.
As of December 31, 2001, HomeServices employed approximately 1,930 individuals and had approximately 8,700 sales associates, who are independent contractors and not employees. None of HomeServices' employees or sales associates are covered by a collective bargaining agreement. HomeServices believes that its relations with its employees and sales associates are good.
Item 2.
Item 2. Properties
The Company'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 the Company are in good operating condition and well maintained.
The electric transmission system of MidAmerican Energy at December 31, 2001, included 897 miles of 345-kV lines, and 1,122 miles of 161-kV lines. The gas distribution facilities of MidAmerican Energy at December 31, 2001, included 20,561 miles of gas mains and services. Substantially all of 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 79% of gross utility plant, is pledged to secure mortgage bonds.
Northern's and Yorkshire's electricity distribution networks (excluding service connection to consumers) included approximately 10,500 and 9,800 miles of overhead lines and approximately 16,800 and 25,200 miles of underground cables, respectively.
The Company's most significant physical properties, other than those owned by CE Electric UK Funding and MidAmerican Energy, are its current interests in operating power facilities, its plants under construction and related real property interests. See Item 1 for further detail.
Item 3.
Item 3. Legal Proceedings
In addition to the proceedings described below, the Company and its subsidiaries are currently parties to various minor items of litigation or arbitration, none of which, if determined adversely, would have a material adverse effect on the Company.
Southern California Edison
Southern California Edison Company ("Edison"), a wholly-owned subsidiary of Edison International, is a public utility primarily engaged in the business of supplying electric energy to retail customers in Central and Southern California, excluding Los Angeles. The Company is aware that there have been public announcements that Edison's financial condition has deteriorated as a result of reduced liquidity. Following Edison's recent financing, Edison's senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P.
Edison failed to pay approximately $119 million due under the power purchase agreement with CE Generation affiliates for power delivered in November and December 2000 and January, February and March 2001, although the Power Purchase Agreements provide for billing and payment on a schedule where payments would have normally been received in early January, February, March, April and May 2001.
On February 21, 2001, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) filed a lawsuit against Edison in California's Imperial County Superior Court seeking a court order requiring Edison to make the required payments under the Power Purchase Agreements. The lawsuit also requested, among other things, that the court order permit the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries of power to Edison and to permit the Imperial Valley Projects to sell such power to other purchasers in California.
On March 22, 2001, the Imperial County Superior Court granted the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) have the right to temporarily suspend deliveries of capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity to other purchasers and 3) the interim suspension of deliveries to Edison shall not in any respect result in the modifications or termination of the Power Purchase Agreements, and the Power Purchase Agreements shall in all respects continue in full force and effect other than the temporary suspension of deliveries to Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) suspended deliveries of energy to Edison and entered into a transaction agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) available power was sold to EPME based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court prospectively vacated its order authorizing the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) right to resell power pursuant to the Declaratory Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and Payment Issues with Edison ("Settlement Agreements") and, as a result, resumed power sales to Edison on June 22, 2001. The Settlement Agreements required that Edison make an initial payment to repay the past due balances under the Power Purchase Agreements (the "stipulated amounts"). The initial payment of approximately $11.6 million, which represented 10% of the stipulated amounts, was received June 22, 2001. On October 2, 2001, the California Public Utilities Commission announced an agreement with Edison that allowed Edison to recover in retail electric rates its past due obligations. On November 30, 2001, the Settlement Agreements were amended to reflect when Edison would be required to make the final payment on past due amounts. On March 1, 2002, Edison obtained $1.8 billion in secured financing that, when combined with cash on hand, enabled Edison to pay off its past due debts. The final payment of approximately $104.6 million, representing the remaining stipulated amounts, was received March 1, 2002. In addition to these payments, Edison was required to make monthly interest payments calculated at a rate of 7% per annum on the outstanding stipulated amounts. The amended Settlement Agreements provide a revised energy pricing structure, whereby Edison elects to pay the Imperial Valley Projects a fixed energy price in lieu of the Commission-approved Avoided Cost of Energy Methodology under the Power Purchase Agreements. The fixed energy price is 3.25 cents/kWh from December 2001 through April 30, 2002 and 5.37 cents/kWh commencing May 1, 2002 for a five year period. Following the five year period, the energy payments revert back to the Commission-approved Avoided Cost of Energy Methodology under the Power Purchase Agreements. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year.
As a result of Edison's failure to make the payments due under the Power Purchase Agreements and the downgrades of Edison's credit rating, Moody's downgraded the ratings for the Salton Sea Funding Corporation (the "Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the ratings for the Funding Corporation Securities to BBB- and placed the Securities on "credit watch negative." Moody's downgraded the ratings for the CE Generation Securities to B1 from Baa3 (review for possible downgrade). Following the execution of the Settlement Agreements, Moody's placed the Salton Sea Funding and CE Generation securities on "credit watch positive." The Funding Corporation Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation Securities are currently Ba2 by Moody's and BBB- by S&P.
Kvaerner Arbitration
The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procure, construct and manage contract (the "Zinc Recovery Project EPC Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default, termination and demand for payment of damages to Kvaerner under the Zinc Recovery Project EPC Contract due to failure to meet performance obligations. As a result of Kvaerner's failure to pay monetary obligations under the Zinc Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.6 million under the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has entered into a time and materials reimbursable engineer, procure and construction management contract with AMEC E&C Services, Inc. to complete the Zinc Recovery Project.
On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration against CalEnergy Minerals LLC characterizing the nature of the dispute as concerns regarding change orders and performance penalties. Kvaerner did not state the amount of its claim.
On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement and Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material allegations in Kvaerner's Amended Demand for Arbitration, and asserted a counterclaim against Kvaerner for breach of contract and specific performance. CalEnergy Minerals LLC alleged that its total estimated damage for Kvaerner's breach of contract are in excess of approximately $60 million; however, CalEnergy Minerals LLC has offset approximately $42.5 million of these damages by exercising its rights under the EPC Contract to claim the retainage and by drawing on a letter of credit. Therefore, CalEnergy Minerals LLC asked for a judgment in excess of approximately $20 million. The arbitration is scheduled for June 2002.
Casecnan
The Casecnan Project was initially being constructed pursuant to a fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As of May 7, 1997, the Company terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, the Company entered into a new fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract was 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. (collectively, the "Contractor").
On November 20, 1999, the Replacement Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lender's independent engineer under the Casecnan Indenture.
On February 12, 2001, the Contractor filed a Request for Arbitration with the International Chamber of Commerce seeking an extension of the Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In a March 20, 2001 Supplement to Request for Arbitration, the Contractor also seeks compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional approximately $62 million in damages for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation on December 11, 2001 amounted to a termination of the Replacement Contract and filed a claim for unspecified quantum meruit damages. CE Casecnan believes such allegations and claims are without merit and is vigorously defending the Contractor's claims. The arbitration is being conducted applying New York law and pursuant to the rules of the International Chamber of Commerce.
On June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. Hearings on the force majeure claims were held in London from July 2 to 14, 2001, and hearings on the Contractor's April 20, 2001 supplement were held in London from September 24 to October 3, 2001. Further hearings were held in Paris from January 2 to February 1, 2002 and additional hearings were held from March 14 to 19, 2002.
As of December 31, 2001 the Company has received approximately $6.0 million of liquidated damages from demands made or the demand guarantees posted by Commerzbank on behalf of the Contractor. Although the outcome of the arbitration is difficult to assess, CE Casecnan believes it will prevail and receive substantial additional liquidated damages in the arbitration.
Malitbog Arbitration
VGPC and PNOC-EDC have been negotiating with respect to certain disputes concerning the Malitbog ECA but have been unable to reach a mutually acceptable resolution. Accordingly, on October 16, 2000, VGPC commenced arbitration against PNOC-EDC by serving it with a Notice of Arbitration and Statement of Claim (the "Notice of Arbitration"). In the Notice of Arbitration, VGPC claimed that PNOC-EDC breached the Malitbog ECA by improperly characterizing certain No Fault Outages as Forced Outage Hours and then deducting them from the total number of hours each month. On December 22, 2000, VGPC filed an Amended Statement of Claim pursuant to which VGPC added a claim that PNOC-EDC breached the Malitbog ECA by refusing to accept VGPC's specified Nominated Capacity for contract years July 25, 1999 to July 25, 2000, and July 25, 2000 to July 25, 2001. A Second Amended Statement of Claim was filed on March 9, 2001 to add the Scheduled Maintenance issue. VGPC intends to vigorously pursue its claims in this proceeding.
Cooper Litigation
On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a complaint, in the United States District Court for the District of Nebraska, naming MidAmerican Energy as the defendant and seeking declaratory judgment as to three issues under the parties' long-term power purchase agreement for Cooper capacity and energy. More specifically, NPPD sought a declaratory judgment in the following respects:
(1) that MidAmerican Energy is obligated to pay 50% of all costs and expenses associated with decommissioning Cooper, and that in the event NPPD continues to operate Cooper after expiration of the power purchase agreement (September 2004), MidAmerican Energy is not entitled to reimbursement of any decommissioning funds it has paid to date or will pay in the future;
(2) that the current method of allocating transition costs as a part of the decommissioning cost is proper under the power purchase agree- ment; and
(3) that the current method of investing decommissioning funds is proper under the power purchase agreement.
MidAmerican Energy filed its answer and counterclaims. The counterclaims filed by MidAmerican Energy are generally as follows:
(1) tha MidAmerican Energy has no duty under the power purchase agreement to reimburse or pay 50% of the decommissioning costs unless conditions to reimbursement occur;
(2) that the term "monthly power costs" as defined in the power purchase agreement does not include costs and expenses associated with decommissioning the plant;
(3) that NPPD violated MidAmerican Energy's directions for application of payments;
(4) that transition costs are not included in any decommissioning costs and are not any kind of costs that MidAmerican Energy is obligated to pay;
(5) that NPPD has the duty to repay all amounts that MidAmerican Energy has prefunded for decommissioning in the event the Nebraska Public Power District operates the plant after the term of the power purchase agreement;
(6) that NPPD is equitably estopped from continuing to operate the plant after the term of the power purchase agreement so long as NPPD does not repay all amounts MidAmerican Energy has prefunded for estimated decommissioning costs together with other amounts in certain funds and accounts and for so long as NPPD fails to provide MidAmerican Energy with certain requested accountings and information;
(7) that certain funds, accounts, and reserves are excessive and are required to be paid to MidAmerican Energy or credited to MidAmerican Energy's pre-2004 monthly power costs;
(8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations and maintenance projects or capital improvements that have useful lives after the term of the power purchase agreement;
(9) that NPPD has mismanaged the plant in numerous described transactions resulting in damage to MidAmerican Energy;
(10) that NPPD has breached its contractual and other duties to MidAmerican Energy by not joining certain litigation and by failing to credit or agree to credit MidAmerican Energy with any recovery for low-level radioactive waste; and
(11) that NPPD has breached its duty to MidAmerican Energy in making invest- ments of decommissioning funds;
On October 6, 1999, the court rendered summary judgment for NPPD on the above-mentioned issue concerning liability for decommissioning (issue one in the first paragraph above) and the related counterclaims filed by MidAmerican Energy (issues one and two in the second paragraph above). The court referred all remaining issues in the case to mediation, and cancelled the November 1999 trial date.
MidAmerican Energy appealed the court's summary judgment ruling. On December 12, 2000, the United States Court of Appeals for the Eighth Circuit reversed the ruling of the district court and granted summary judgment in favor of MidAmerican Energy on issues one and two in the second paragraph above, as well as issue one in the first paragraph above. Additionally, it remanded the case for trial on all other claims and counterclaims.
Since the remand to the District Court from the Eighth Circuit Court of Appeals, NPPD has been granted permission, over MidAmerican Energy's objections, to file a second amended complaint. The second amended complaint asserts that even though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no liability under the power purchase agreement to reimburse or pay NPPD a 50% share of decommissioning costs unless certain conditions occur, MidAmerican Energy has unconditional liability for a 50% share based on agreements other than the power purchase agreement as originally written. NPPD's post-remand contentions -- all strongly disputed by MidAmerican Energy -- are that MidAmerican Energy has unconditional liability for a 50% share of decommissioning based on any of the following alternative theories: (i) the parties without written amendment either modified the power purchase agreement or made a separate agreement that imposes unconditional liability on MidAmerican Energy for decommissioning costs; (ii) absent unconditional liability for a 50% share of decommissioning costs, MidAmerican Energy would be unjustly enriched; (iii) MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs based on promissory estoppel; or (iv) NPPD is entitled to have the power purchase agreement reformed to provide that MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs. In response to NPPD's second amended complaint, MidAmerican Energy filed its first amended answer and third amended counterclaims containing denials, several affirmative defenses, and the counterclaims summarized above. In the course of discovery, NPPD has contended that MidAmerican Energy has some responsibility for some costs of storage of spent fuel resulting from the operation of the plant during the term of the power purchase agreement. MidAmerican Energy disputes this. MidAmerican Energy recently filed a mandamus petition with Eighth Circuit Court of Appeals seeking an order of that court directing the District Court not to permit NPPD to pursue the above alternative theories at trial, since the above alternative theories appear to be contrary to the December 12, 2000 Eighth Circuit Court of Appeals decision. If such relief is not granted, MidAmerican Energy will strongly dispute at trial these contentions and theories put forth by NPPD. Trial in these matters has been recently rescheduled to September 9, 2002.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5.
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 a limited group of private investors 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.
Item 6. Selected Financial Data
Reference is made to Part IV of this report.
Item 7.
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.
Item 7A. Qualitative and Quantitative Disclosures About Market Risk
Reference is made to Part IV of this report. Refer to Note 16 in notes to consolidated financial statements.
Item 8.
Item 8. Financial Statements and Supplementary Data
Reference is made to Part IV of this report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
PART III
MANAGEMENT
Item 10.
Item 10. Directors, Executive and Other Officers of the Company
The Company's management structure is organized functionally and the current executive officers and directors of the Company and their positions are as follows:
Name Position
David L. Sokol Chairman of the Board, Chief Executive Officer and Director Gregory E. Abel President, Chief Operating Officer and Director Patrick J. Goodman Senior Vice President and Chief Financial Officer Douglas L. Anderson Senior Vice President and General Counsel Keith D. Hartje Senior Vice President and Chief Administrative Officer Warren Buffett Director Walter Scott Jr. Director Marc D. Hamburg Director W. David Scott Director Edgar D. Aronson Director John Boyer Director Stanley J. Bright Director Richard Jaros Director
Officers are elected annually by the Board of Directors. There are no family relationships among the executive officers, nor any arrangements or understanding between any officer and any other person pursuant to which the officer was selected.
Set forth below is certain information with respect to each of the foregoing officers:
DAVID L. SOKOL, 45, 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, 39, President, Chief Operating Officer and Director. 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, 35, 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.
DOUGLAS L. ANDERSON, 44, Senior Vice President and General Counsel. Mr. Anderson joined the Company in February 1993 and has served in various legal positions including General Counsel of the Company's independent power affiliates. From 1990 to 1993 Mr. Anderson was a corporate attorney with Fraser, Stryker in Omaha, NE. Prior to that Mr. Anderson was a principal in the firm Anderson and Anderson.
KEITH D. HARTJE, 52, 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.
WARREN BUFFETT, 71, Director. Mr. Buffett has been a director of the Company since March 2000. He is Chairman of the Board and Chief Executive Office of Berkshire Hathaway Inc. Mr. Buffett is a Director of the Coca-Cola Company, the Gillette Company and The Washington Post Company.
WALTER SCOTT, JR., 71, Director. Mr. Scott has been a director of the Company since June 1991. Mr. Scott was the Chairman and Chief Executive Officer of the Company from January 8, 1992 until April 19, 1993. For more than the past five years, he has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit Sons Inc. Mr. Scott is a director of Peter Kiewit Sons Inc., Berkshire Hathaway Inc., Burlington Resources, Inc., ConAgra, Inc., Valmont Industries, Inc., Kiewit Materials Co., Commonwealth Telephone Enterprises, Inc. and RCN Corporation.
MARC D. HAMBURG, 52, Director. Mr. Hamburg has been a director of the Company since March 2000. He has served as Vice President - Chief Financial Officer of Berkshire Hathaway Inc. since October 1, 1992 and Treasurer since June 1, 1987, his date of employment with Berkshire Hathaway Inc.
W. DAVID SCOTT, 40, Director. Mr. Scott has been a director of the Company since March 2000. Mr. Scott formed Magnum Resources, Inc., a commercial real estate investment and management company, in October 1994 and has served as its President and Chief Executive Office since its inception. Before forming Magnum Resources, Mr. Scott worked for America First Companies, Cornerstone Banking Group and Peter Kiewit Sons Inc. Mr. Scott has been a director of America First Mortgage Investments, Inc., a mortgage REIT, since 1998.
EDGAR D. ARONSON, 67, Director. Mr. Aronson has been a director of the Company since 1983. Mr. Aronson founded EDACO, Inc., a private venture capital company, in 1981, and has been President of EDACO, Inc. since that time. Prior to that, Mr. Aronson was Chairman of Dillon, Read International from 1979 to 1981 and a General Partner in charge of the International Department of Salomon Brothers Inc. from 1973 to 1979. Mr. Aronson served during 1962-1968 as Vice President consecutively in the International Departments of First National Bank of Chicago and Republic National Bank of New York. He founded the International Department of Salomon Brothers and Hutzler in 1968.
JOHN BOYER, 58, Director. Mr. Boyer has been a director of the Company since March 2000. He is a partner with Fraser, Stryker, Meusey, Olson, Boyer & Bloch, P.C. from 1973 to present with emphasis on corporate, commercial, federal, state, and local taxation.
STANLEY J. BRIGHT, 62, Director. Mr. Bright is Vice Chairman of the Company and was Chairman and Chief Executive Officer of MidAmerican Energy Company from July 1, 1995 until March 1999. Mr. Bright joined Iowa-Illinois Gas and Electric Company (a predecessor of MidAmerican Energy Company) as Vice President and Chief Financial Officer in 1986, became a director in 1987, President and Chief Operating Officer in 1990, and Chairman and Chief Executive Officer in 1991.
RICHARD R. JAROS, 50, Director. Mr. Jaros has been a director since March 1991. Mr. Jaros served as President and Chief Operating Officer of the Company from January 8, 1992 to April 19, 1993 and as Chairman of the Board from April 19, 1993 to May 1994. Until July 1997, Mr. Jaros was Executive Vice President and Chief Financial Officer of Peter Kiewit Sons Inc. and President of Kiewit Diversified Group, Inc., which is now Level 3 Communications, Inc. From 1990 until January 8, 1992, Mr. Jaros served as a Vice President of Peter Kiewit Sons Inc. Mr. Jaros serves as director of Commonwealth Telephone Enterprises, Inc., RCN Corporation and Level 3 Communications, Inc.
Item 11.
Item 11. Executive Compensation
The following table sets forth the compensation of the chief executive officer and the four other most highly compensated executive officers of the Company who were employed as of December 31, 2001 ("Named Executive Officers"). Information is provided regarding the Named Executive Officers for the last three fiscal years during which they were executive officers of the Company, if applicable.
Option Grants in Last Fiscal Year
The Company did not grant any options during 2001.
Aggregated Option Exercises In Last Fiscal Year And Fiscal Year End Option Values
The following table sets forth the option exercises and the number of securities underlying exercisable and unexercisable options held by each of the Named Executive Officers at December 31, 2001.
Long-Term Incentive Plans - Awards in Last Fiscal Year
Amount of Performance or other Annual Award period until Name ($) (1) maturation or payout - ---- ------- -------------------- Ronald W. Stepien $ 56,106 December 31,2005 Patrick J. Goodman 107,212 December 31,2005 Douglas L. Anderson 87,769 December 31,2005
(1) The awards shown in the foregoing table are made pursuant to the Long-Term Incentive Partnership Plan ("LTIP") which provides that awards vest equally over five years with any unvested balances forfeited upon termination of employment unless the participant retires at or above age 55 with at least 5 years of service in which case the participant will receive any unvested portion of the award. Vested balances are paid to the participant at the time of termination. Once an award is fully vested, the participant may elect to defer or receive payment of part or all of the award. Messrs. Sokol and Abel are not participants in the LTIP. Awards are credited with annual interest based on a composite of funds or indices.
Compensation of Directors
All directors, excluding Messrs. Sokol, Abel, Buffet and Walter Scott, are paid an annual retainer fee of $20,000 and a fee of $500 per day for attendance at Board and Committee meetings. Directors who are employees of the Company do not receive such fees. All directors are reimbursed for their expenses incurred in attending Board meetings.
Retirement Plans
The Company maintains a Supplemental Retirement Plan for Designated Officers ("Supplemental Plan") to provide additional retirement benefits to designated participants, as determined by the Board of Directors. Messrs. Sokol, Abel, Stepien and Goodman are participants in the Supplemental Plan. The Supplemental Plan provides retirement benefits up to sixty-five percent of a participant's Total Cash Compensation in effect immediately prior to retirement, subject to a $1 million maximum retirement benefit. "Total Cash Compensation" means the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12 plus the average of the participant's last three years (i) awards under an annual incentive bonus program and (ii) special, additional or non-recurring bonus awards, if any, that are required to be included in Total Cash Compensation pursuant to a participant's employment agreement or approved for inclusion by the Board. Participants must be credited with five years service in order to be eligible to receive benefits under the Supplemental Plan. Each of the Named Executive Officers has or will have five years of credited service with the Company as of their respective normal retirement age and will be eligible to receive benefits under the Supplemental Plan. A participant who elects early retirement is entitled to reduced benefits under the Supplemental Plan, however, in accordance with their respective employment agreements, Messrs. Sokol and Abel are eligible to receive the maximum retirement benefit at age 47. A survivor benefit is payable to a surviving spouse under the Supplemental Plan. Benefits from the Supplemental Plan will be paid out of general corporate funds, however, the Company, through a rabbi trust, maintains life insurance on the participants in amounts expected to be sufficient to fund the after-tax cost of the projected benefits. Deferred compensation is considered part of the salary covered by the Supplemental Plan.
The supplemental retirement benefit will be reduced by the amount of the participant's regular retirement benefit under the MidAmerican Energy Company Cash Balance Retirement Plan ("MidAmerican Retirement Plan") that became effective January 1, 1997, and by benefits under the Iowa-Illinois Gas and Electric Company Supplemental Retirement Plan ("Iowa-Illinois Supplemental Plan"), as applicable.
The MidAmerican Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional, defined benefit plans. Under the MidAmerican Retirement Plan, each participant has an account, for recordkeeping purposes only, to which credits are allocated each payroll period based upon a percentage of the participant's salary paid in the current pay period. In addition, all balances in the accounts of participants earn a fixed rate of interest that is credited annually. The interest rate for a particular year is based on the constant maturity Treasury yield plus seven-tenths of one percentage point. At retirement or other termination of employment, an amount equal to the vested balance then credited to the account is payable to the participant in the form of a lump sum or a form of annuity for the entire benefit under the MidAmerican Retirement Plan. Mr. Anderson is a participant in this plan.
The table below shows the estimated aggregate annual benefits payable under the Supplemental Plan and the MidAmerican Retirement Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at ages 55, 60 and 65. Federal law limits the amount of benefits payable to an individual through the tax qualified defined benefit and contribution plans, and benefits exceeding such limitation are payable under the Supplemental Plan.
Pension Plan Table
Total Cash Estimated Annual Benefit Compensation Age at Retirement Retirement ----------------------------------------------------- - --------------- 55 60 65 --------- ---------- ---------- $400,000 $ 220,000 $240,000 $260,000 500,000 275,000 300,000 325,000 600,000 330,000 360,000 390,000 700,000 385,000 420,000 455,000 800,000 440,000 480,000 520,000 900,000 495,000 540,000 585,000 1,000,000 550,000 600,000 650,000 1,250,000 687,500 750,000 812,500 1,500,000 825,000 900,000 975,000 1,750,000 962,500 1,000,000 1,000,000 2,000,000 and greater 1,000,000 1,000,000 1,000,000
Employment Agreements
Pursuant to his Employment Agreement, Mr. Sokol will serve as Chairman of the Board of Directors and Chief Executive Officer of the Company. The Employment Agreement provides that Mr. Sokol is to receive an annual base salary of not less than $750,000, senior executive employee benefits and annual bonus awards that shall not be less than $675,000.
The Employment Agreement provides that the Company may terminate the employment of Mr. Sokol (i) with cause in which case the Company is to pay to him any accrued but unpaid salary and a bonus of not less than the minimum annual bonus or (ii) due to death, permanent disability or other than for cause, including a change in control, in which case Mr. Sokol is entitled to receive an amount equal to three times the sum of (a) his annual salary then in effect and (b) the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as three years of accelerated option vesting plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, the Company is to pay to him any accrued but unpaid salary and a bonus of not less than the annual minimum bonus, unless he resigns for good reason in which case he will receive the same benefits as if he were terminated other than for cause.
In the event Mr. Sokol has relinquished his position as Chief Executive Officer and is subsequently terminated as Chairman of the Board due to death, disability or other than for cause, he is entitled to any accrued but unpaid salary plus an amount equal to the aggregate annual salary that would have been paid to him through the fifth anniversary of the date he commenced his employment solely as Chairman of the Board, the immediate vesting of all of his options and the continuation of his senior executive employee benefits (or the economic equivalent thereof) through such fifth anniversary. If Mr. Sokol relinquishes his position as Chief Executive Officer but offers to remain employed as the Chairman of the Board, he is to receive a special achievement bonus equal to two times the sum of (a) his annual salary then in effect and (b) the greater of his minimum annual bonus or his average annual bonus for the two preceding years, as well as two years of accelerated option vesting.
Under the terms of separate employment agreements between each of Messrs. Abel and Goodman and the Company, each of such Executives is entitled to receive two years base salary continuation, payments in respect of average bonuses for the prior two years and two years continued option vesting in the event of the termination of his employment by the Company other than for cause. If such persons were terminated without cause, Messrs. Sokol, Abel and Goodman would currently be entitled to be paid approximately $12,225,000, $3,290,000 and $780,000, respectively, pursuant to their employment agreements, without giving effect to any tax related provisions.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information regarding beneficial ownership of the shares of Company common stock and certain information with respect to the beneficial ownership of each director, the Named Executive Officers and all directors and executive officers of the Company as a group as of December 31, 2001. Number Of Shares Name and Address of Beneficially Percentage Of Beneficial Owner (1) Owned (2) Class (2) - -------------------- ---------------- ------------- Common Stock: Gregory E. Abel (3) 649,362 5.47% Douglas L. Anderson - - Edgar D. Aronson - - Berkshire Hathaway Inc. (4) 900,942 9.71% Stanley J. Bright - - John K. Boyer - - Warren E. Buffett (5) - - Patrick J. Goodman - - Marc D. Hamburg (5) - - Richard R. Jaros - - W. David Scott (6) 624,350 6.73% Walter Scott, Jr. (7) 5,000,000 53.87% David L. Sokol (8) 2,325,132 19.58% Ronald W. Stepien - - All directors and executive officers as a group (14 persons) 9,499,786 80.00%
(1) Unless otherwise indicated, each address is c/o the Company at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309. (2) Includes shares which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days. (3) Includes options to purchase 593,422 shares of common stock which are exercisable within 60 days. (4) Such beneficial owner's address is 1440 Kiewit Plaza, Omaha, Nebraska 68131. (5) Excludes 900,942 shares of common stock held by Berkshire Hathaway Inc. of which beneficial ownership of such shares is disclaimed. (6) Includes shares held by trusts for the benefit of or controlled by W. David Scott. Such beneficial owner's address is 402 South 36th Street, Suite 800, Omaha, Nebraska 68131. (7) Excludes 3 million shares held by family members and family controlled trusts and corporations ("Scott Family Interests") as to which Mr. Scott disclaims beneficial ownership. Such beneficial owner's address is 1000 Kiewit Plaza, Omaha, Nebraska 68131. (8) Includes options to purchase 2,000,927 shares of common stock that are exercisable within 60 days.
The terms of the Company's Zero Coupon Convertible Preferred Stock held by Berkshire athaway nc. entitle the holder thereof to designate two members of the Company's Board of Directors. Similarly, Mr. Sokol's employment agreement gives him the right during the term of his employment to serve as a member of the Board of Directors and to designate two additional directors.
Pursuant to a shareholders agreement, following March 14, 2003, Walter Scott, Jr. or any of the Scott Family Interests would be able to require Berkshire Hathaway Inc. to purchase, for an agreed value or an appraised value, any or all of Walter Scott, Jr.'s and the Scott Family Interests' shares of Company common stock, provided that Berkshire Hathaway Inc. is then a purchaser of a type which is able to consummate such a purchase without causing it or any of its affiliates or the Company or any of its subsidiaries to become subject to regulation as a registered holding company or a subsidiary of a registered holding company under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"). The consummation of such a transaction could result in a change in control of the Company.
The Company's Amended and Restated Articles of Incorporation ("Articles") provide that each share of the Zero Coupon Convertible Preferred Stock is convertible at the option of the holder thereof into one conversion unit, which is one share of Company common stock subject to certain adjustments as described in the Articles, upon the occurrence of a Conversion Event. A "Conversion Event" includes (i) any conversion of Zero Coupon Convertible Preferred Stock that would not cause the holder of the shares of common stock issued upon conversion (or any affiliate of such holder) or the Company to become subject to regulation as a registered holding company or as a subsidiary of a registered holding company under PUHCA either as a result of the repeal or amendment of PUHCA, the number of shares involved or the identity of the holder of such shares and (ii) a Company Sale. A "Company Sale" includes any involuntary or voluntary liquidation, dissolution, recapitalization, winding-up or termination of the Company and any merger, consolidation or sale of all or substantially all of the assets of the Company. The conversion by Berkshire Hathaway Inc. of its shares of Zero Coupon Convertible Preferred Stock could result in a change in control of the Company.
Item 13.
Item 13. Certain Relationships and Related Transactions
Under a subscription agreement with the Company, under certain circumstances, Berkshire Hathaway has agreed to purchase additional 11% trust issued preferred securities in the event preferred securities outstanding prior to the closing of the Teton Transaction are tendered for conversion to cash by the current holders.
PART IV
Item 14.
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......................................36 Management's Discussion and Analysis of Financial Condition And Results of Operations............................................37 Qualitative and Quantitative Disclosures About Market Risk................48 Consolidated Balance Sheets as of December 31, 2001 and 2000..............50 Consolidated Statements of Operations For the Three Years Ended December 31, 2001, 2000 and 1999...........51 Consolidated Statements of Stockholders' Equity For the Three Years Ended December 31, 2001, 2000 and 1999...........52 Consolidated Statements of Cash Flows For the Three Years Ended December 31, 2001, 2000 and 1999...........53 Notes to Consolidated Financial Statements................................54 Independent Auditors' Report..............................................93
2. Financial Statement Schedules Page No. Schedule I, Financial Statements of the Company (Parent Company only).....94
Schedule II, Consolidated Valuation and Qualifying Accounts...............97
(b) Reports on Form 8-K
None.
(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.
SELECTED CONSOLIDATED FINANCIAL DATA (In millions)
(1) Reflects the Northern Supply/Yorkshire Electric swap on September 21, 2001. (2) Reflects the Teton Transaction on March 14, 2000. (3) Reflects the MidAmerican acquisition on March 12, 1999, the disposition of Coso Joint Ventures on February 26, 1999 and the disposition of 50% owner- ship interest in CE Generation on March 3, 1999. (4) Reflects the acquisition of KDG on January 2, 1998. (5) Includes $81.5 million for non-recurring Indonesia gain on settlement, gains on sales of McLeod and qualified facilities, CE Electric UK Funding restructuring charges and Teton Transaction costs. (6) Includes $87 million non-recurring Indonesia asset impairment charge.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 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 Northern Supply/Yorkshire Electric swap and the Teton Transaction, the Company's future results will differ from the Company's historical results.
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, the financial condition of and relationships with customers and suppliers, the availability and price of fuel and other inputs, uncertainties relating to domestic and international 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.
Critical Accounting Policies
The preparation of financial statements and related documents in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the consolidated financial statements in this Annual Report on Form 10-K describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for revenue, contingent liabilities and impairment of long-lived assets. Actual results could differ from these estimates. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.
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.
The Company also records unbilled revenues representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. Accrued unbilled revenues are included in accounts receivable on the consolidated balance sheets.
SFAS No. 71 - Accounting for the Effects of Certain Types of Regulation
A possible consequence of deregulation in the utility industry is that SFAS No. 71 may no longer apply. SFAS No. 71 sets forth accounting principles for operations that are regulated and meet the stated criteria. For operations that meet the criteria, SFAS No. 71 allows, among other things, the deferral of expense or income that would otherwise be recognized when incurred. MidAmerican Energy's electric and gas utility operations currently meet the criteria required by SFAS No. 71, but its applicability is periodically reexamined. If portions of its utility operations no longer meet the criteria of SFAS No. 71, MidAmerican Energy 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 deregulation legislation. As of December 31, 2001, the Company had $221.1 million of regulatory assets and $62.4 million of regulatory liabilities on its consolidated balance sheet.
Impairment of Long-Lived Assets
The Company's long-lived assets consist primarily of property, plant and equipment, goodwill and intangible assets that were acquired in business acquisitions. The Company believes the useful lives assigned to these assets, which range from 3 to 40 years, are reasonable. The Company evaluates the long-lived assets for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. These computations utilize judgments and assumptions inherent in management's estimate of undiscounted future cash flows to determine recoverability of an asset. If management's assumptions about these assets change as a result of events or circumstances, and management believes the assets may have declined in value, then the Company may record impairment charges, resulting in lower profits.
Contingent Liabilities
The Company establishes reserves for estimated loss contingencies when it is management's assessment that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon management's assumptions and estimates, advice of legal counsel or other third parties regarding the probable outcomes of any matters. Should the outcomes differ from the assumptions and estimates, revisions to the estimated reserves for contingent liabilities would be required.
Results of Operations for the Year Ended December 31, 2001 and the Periods March 14, 2000 through December 31, 2000, and January 1, 2000 through March 13, 2000:
The following is a discussion of the historical results of the Company for the year ended December 31, 2001 and the period March 14, 2000 through December 31, 2000, and of its predecessor (referred to as "MEHC (Predecessor)") for the period January 1, 2000 through March 13, 2000. Results for the Company include the impact of the Teton Transaction beginning March 14, 2000 which are predominately the minority interest costs on issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trust and the effects of purchase accounting, including goodwill amortization and fair value adjustments to the carrying value of assets and liabilities. In order to provide comparability between periods, the Company has prepared pro forma results as if the Teton Transaction had occurred at the beginning of each year after giving effect to pro forma adjustments related to the acquisition, including the issuance of the 11% trust preferred securities. The discussion therefore will highlight any significant variances on a pro forma basis from the year ended December 31, 2000 to the year ended December 31, 2001.
Pro forma operating revenue for the year ended December 31, 2001 was $5,060.6 million compared with $5,235.0 million for the same period in 2000, a decrease of 3.3%. MidAmerican Energy operating revenue increased for the year ended December 31, 2001 to $2,752.5 million from $2,576.9 million for the same period in 2000, primarily due to increases in volumes of non-regulated gas sold and increases in volumes and prices on off-system electricity sales. CE Electric UK Funding operating revenue decreased for the year ended December 31, 2001 to $1,444.0 million from $1,997.9 million for the same period in 2000, primarily due to the Northern Supply/Yorkshire swap and changes in foreign exchange rates. The supply business that was sold is generally a high volume business that tends to operate at lower profitability levels than the distribution business. The remaining increase primarily relates to the increase of revenue at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and the commencement of operations of the Cordova Project in June 2001.
The following data represents sales from MidAmerican Energy:
Year Ended December 31, ---------------------------- 2001 2000 -------- ---------
Electricity Retail Sales (GWh)....... 17,207 16,715
Electricity Sales for Resale (GWh)... 7,755 6,941
Regulated and Non-Regulated Gas Supplied (Thousands of MMBtus)............................. 264,338 174,385
MidAmerican Energy electric retail sales increased for the year ended December 31, 2001 from the same period in 2000 due to the more extreme temperatures substantially offset by a decrease in non-weather related sales. Electric sales for resale increased for the year ended December 31, 2001 from the same period in 2000 due to higher production at the Cooper and Neal power plants and favorable market conditions. Regulated and non-regulated gas supplied increased due principally to growth in the non-regulated markets for the year ended December 31, 2001 compared to the same period in 2000.
The following data represents the supply and distribution operations in the U.K.:
Year Ended December 31, -------------------------------- 2001 2000 --------- --------
Electricity Supplied (GWh)............ 12,745 19,925
Electricity Distributed (GWh)......... 23,770 16,350
Gas Supplied (Thousands of MMBtus).... 40,738 51,035
The decrease in electricity supplied for the year ended December 31, 2001 is due to the sale of the Northern Supply business in September 2001. The increase in electricity distributed for the year ended December 31, 2001 is due to the addition of Yorkshire and changes in demand in the distribution area. The decrease in gas supplied in 2001 from 2000 reflects the sale of the Northern Supply business.
Pro forma interest and other income for the year ended December 31, 2001 was $96.7 million compared with $114.4 million for the same period in 2000. The decrease was due primarily to reduced interest income and lower income from equity investments.
The non-recurring gains in 2001 are comprised mainly of the pre-tax gain on the sale of the Northern Supply business of $196.7 million, the loss on the impair- ment of Teesside of $58.8 million, the gain on the sale of Telephone Flat, a geothermal development project, of $20.7 million, the gain on the transfer of shares of Bali, an indirect wholly owned subsidiary of the Company, of $10.4 million, and the gain on the sale of Western States Geothermal Company, an indirect wholly owned subsidiary of the Company, of $9.8 million. The after-tax gains and (losses) for the Northern Supply sale, the Teesside impairment, the Telephone Flat sale, the transfer of the Bali shares, and the Western States Geothermal sale were $10.8 million, ($20.7) million, $12.2 million, $6.5 million and $6.4 million, respectively.
Pro forma cost of sales for the year ended December 31, 2001 was $2,705.0 million compared with $3,029.7 million for the same period in 2000, a decrease of 10.7%. The decrease relates primarily to decreased cost of sales at CE Electric UK Funding due to the sale of the Northern Supply business, lower foreign exchange rate and lower electricity volumes and prices, partially offset by increased volumes and prices for both regulated and non-regulated gas at MidAmerican Energy, and acquisitions at HomeServices.
Pro forma operating expenses for the year ended December 31, 2001 were $1,176.4 million compared with $1,123.6 million for the same period in 2000. The increase was primarily due to higher costs at HomeServices due to acquisitions and the inclusion of a joint venture which was previously accounted for as an equity investment and higher costs at MidAmerican due to costs related to Cooper, accounts receivable discounts and bad debts, partially offset by lower costs at CE Electric UK Funding due to the sale of the Northern Supply business, lower pension costs and a lower exchange rate, partially offset by the addition of Yorkshire.
Pro forma depreciation and amortization for the year ended December 31, 2001 was $538.7 million compared with $479.6 million for the same period in 2000. This increase was due to higher depreciation at MidAmerican Energy due to inclusion of Iowa revenue sharing accrual and an increase in depreciation rates implemented in 2001 and amortization of intangible assets related to the HomeServices acquisitions, partially offset by lower depreciation at CE Electric UK Funding due to lower amortization of operational assets and lower exchange rate, partially offset by the addition of Yorkshire.
Pro forma interest expense, less amounts capitalized, for the year ended December 31, 2001 was $412.8 million compared with $398.1 million for the same period in 2000, an increase of 3.7%. This increase is due to increased interest expense associated with the debt acquired with Yorkshire and lower capitalized interest on the mineral extraction process, partially offset by lower average outstanding debt balances and lower foreign exchange rates at Northern.
The loss on non-recurring item of $7.6 million in the period from January 1, 2000 through March 13, 2000 represents the costs incurred related to the Teton Transaction.
Pro forma tax expense for the year ended December 31, 2001 was $250.1 million compared with $81.6 million for the same period in 2000. The increase is due primarily to the tax on the gain related to the sale of Northern Supply business and higher pre-tax income.
Pro forma minority interest for the year ended December 31, 2001 was $106.5 million compared with $104.3 million for the same period in 2000. The increase is primarily due to increased minority interest at HomeServices.
The cumulative effect of change in accounting principle of $4.6 million in 2001 represents the change in accounting for major maintenance and overhauls.
Pro forma net income for the year ended December 31, 2001 was $142.7 million compared with $124.9 million for the same period in 2000.
Results of Operations for the Periods March 14, 2000 through December 31, 2000, January 1, 2000 through March 13, 2000 and for the Year Ended December 31, 1999:
The following is a discussion of the historical results of the Company for the period March 14, 2000 through December 31, 2000, and of its predecessor (referred to as "MEHC (Predecessor)") for the period January 1, 2000 through March 13, 2000, and for the year ended December 31, 1999. Results for the Company include the results of MEHC (Predecessor) beginning March 14, 2000, in conjunction with the Teton Transaction. The impact of the transaction is reflected in the Company's results of operations, predominately minority interest costs on issuance of Company-obligated mandatorily redeemable preferred securities of subsidiary trust and the effects of purchase accounting, including goodwill amortization and fair value adjustments to the carrying value of assets and liabilities. In order to provide comparability between periods, the Company has prepared pro forma results as if the Teton Transaction and the MidAmerican acquisition had occurred at the beginning of each year after giving effect to pro forma adjustments related to the acquisitions, including the sales of the qualified facilities, the redemption of limited recourse notes, the redemption of the senior discount notes and the issuance of the 11% trust preferred securities. The discussion therefore will highlight any significant variances on a pro forma basis from the year ended December 31, 1999 to the year ended December 31, 2000.
Pro forma operating revenue for the year ended December 31, 2000 was $5,235.0 million compared with $4,572.8 million for the same period in 1999, an increase of 14.5%. MidAmerican operating revenue increased for the year ended December 31, 2000 to $2,576.9 million from $1,871.9 million for the same period in 1999, primarily due to increases in nonregulated gas sales and higher rates in regulated gas. CE Electric UK Funding operating revenue decreased for the year ended December 31, 2000 to $1,997.9 million from $2,072.2 million for the same period in 1999, primarily due to lower volumes of electricity supplied in the franchise area and lower foreign exchange rates partially offset by higher volumes of electricity supplied out of the franchise area and distribution revenue from access charges. The remaining increase primarily relates to the increase of revenue at HomeServices due to acquisitions in late 1999.
The following data represents sales from MidAmerican Energy:
Year Ended December 31, 2000 1999 -------- --------
Electricity Retail Sales (GWh)............. 16,715 16,007
Electricity Sales for Resale (GWh)......... 6,941 7,168
Regulated and Nonregulated Gas Supplied (Thousands of MMBTUs)...................... 174,385 138,387
MidAmerican Energy electricity retail sales increased for the year ended December 31, 2000 from the same period in 1999 due to increased customers and non-weather related sales partially offset by more moderate temperatures. Electricity sales for resale decreased for the year ended December 31, 2000 from the same period in 1999 due to a lower power plant output primarily from the Cooper facility which results in lower energy available for resale. Gas supplied increased due to an increase in customers, an increase in heating degree days and an increase in trading activity of nonregulated sales.
The following data represents the supply and distribution operations in the U.K.:
Year Ended December 31, 2000 1999 ---------- ----------
Electricity Supplied (GWh)............... 19,925 17,984
Electricity Distributed (GWh)............. 16,350 15,943
Gas Supplied (Thousands of MMBtus)...... 51,035 48,435
The increase in electricity supplied for the year ended December 31, 2000 is due primarily to the increase in volumes for customers outside of the franchise area. The increase in electricity distributed for the year ended December 31, 2000 is due to changes in demand in the franchise area. The increase in gas supplied in 2000 from 1999 reflects higher volume in the U.K. industrial and commercial markets.
Pro forma interest and other income for the year ended December 31, 2000 was $114.4 million compared with $145.4 million for the same period in 1999. The decrease was due primarily to the reduced interest income resulting from lower cash balances, lower dividends from Teesside and gains on other asset sales in 1999, partially offset by proceeds on Company-owned life insurance of $7.5 million received in 2000.
The 1999 gain on non-recurring items resulted from the sale of approximately 6.74 million shares of McLeod Class A common stock, through a secondary offering by McLeod, at $55.625 per share. Proceeds from the sale exceeded $375 million, with a resulting after-tax gain to the Company of approximately $47.1 million.
As a result of the sales of Coso and an interest in CE Generation, the Company recorded a gain of $20.2 million in the first quarter of 1999.
In the fourth quarter of 1999, the Company recorded a pre-tax gain of $40.3 million relating to insurance proceeds received from an arbitration settlement between Himpurna California Energy Ltd. and Patuha Power Ltd., former subsidiaries of the Company, and P.T. PLN (Persero), an Indonesian national electric utility.
Pro forma cost of sales for the year ended December 31, 2000 was $3,029.7 million compared with $2,398.6 million for the same period in 1999, an increase of 26.3%. The increase relates to increased sales at MidAmerican Energy and HomeServices.
Pro forma operating expense for the year ended December 31, 2000 was $1,123.6 million compared with $1,115.8 million for the same period in 1999. The increase primarily relates to the increase of operating expenses at HomeServices due to acquisitions in late 1999.
Pro forma depreciation and amortization for the year ended December 31, 2000 was $479.6 million compared with $462.0 million for the same period in 1999. The increase was primarily due to higher depreciation at CE Electric UK Funding primarily due to higher production at CE Gas.
Pro forma interest expense, less amounts capitalized, for the year ended December 31, 2000 was $398.1 million compared with $447.0 million for the same period in 1999, a decrease of 10.9%. This decrease was due to the repayment of the 9.5% Senior Notes in 1999 and other reduced indebtedness and an increase in capitalized interest related to the construction of Casecnan, Cordova and Zinc.
The loss on non-recurring items of $7.6 million in the period from January 1, 2000 through March 13, 2000 represents the costs related to the Teton Transaction.
Pro forma tax expense for the year ended December 31, 2000 was $81.6 million compared with $89.4 million for the same period in 1999. The decrease is due primarily to lower pretax income in 2000.
Pro forma minority interest for the year ended December 31, 2000 was $104.3 million compared with $101.9 million for the same period in 1999. Minority interest includes the dividends on the $455 million of Company-obligated mandatorily redeemable preferred securities of subsidiary trusts.
Pro forma net income for the year ended December 31, 2000 was $124.9 million compared with $138.3 million for the same period in 1999.
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 may from time to time seek to retire its outstanding debt through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
The Company's cash and cash equivalents were $386.7 million at December 31, 2001 compared to $38.2 million at December 31, 2000. The increase is primarily due to the addition of Yorkshire and the timing of cash receipts and disbursements at MidAmerican Energy. In addition, the Company recorded separately restricted cash and investments of $54.8 million and $90.9 million at December 31, 2001 and 2000, respectively. The restricted cash balance as of December 31, 2001 is comprised primarily of amounts deposited in restricted accounts from which the Company will fund the various projects under construction. Additionally, the Leyte Projects', Casecnan's and a portion of Cordova's restricted cash is reserved for the service of debt obligations.
On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85% Senior Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200 million of 6.75% Senior Secured Notes due March 1, 2011.
September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary of the Company, and Innogy Holdings, plc executed an agreement to exchange Northern's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern's supply business was initially valued at approximately $430 million ((pound)295 million), including working capital of approximately $53 million ((pound)37 million). 94.75% of Yorkshire's distribution business was initially valued at approximately $395 million ((pound)271 million), including working capital of approximately $48 million ((pound)33 million). The net cash received by Northern for the exchange was approximately $35 million ((pound)24 million). Working capital is subject to adjustment and is currently under review.
The Company paid $37.4 million, net of cash acquired of $362.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness.
Subsequent Events
Debt issuance
On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% medium-term notes due in 2031. The proceeds will be used to refinance existing debt and preferred securities and for other corporate purposes. MidAmerican Energy has redeemed its MidAmerican-obligated preferred securities of subsidiary trust on March 11, 2002 at 100% of the principal amount plus accrued interest.
Prudential California Acquisition
In February 2002, HomeServices completed its purchase of a majority interest in Prudential California Realty. The cash purchase price of Prudential California Realty was approximately $74 million, with an option to purchase the remaining interests. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million calculated based on certain 2002 financial performance measures. The purchase price was financed using the Company's corporate revolver for $40 million which was contributed to HomeServices as equity and the remaining funds were borrowed from available credit under the HomeServices's $65 million revolving credit facility. It is anticipated that the borrowings in connection with this acquisition will be repaid from HomeServices generated funds. The acquisition will be accounted for by the purchase method of accounting, and the Company is in the process of completing the allocation of the purchase price to the assets and liabilities acquired.
Kern River Acquisition
On March 7, 2002, the Company reached a definitive agreement with The Williams Companies, Inc. ("Williams") to acquire Williams' Kern River Gas Transmission Company ("Kern River"), a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah. The purchase price was $956 million, including $506 million of assumed debt. As part of the agreement, the Company will continue the planned expansion of the Kern River system, a project that will more than double the pipeline's capacity with expected capital expenditures of approximately $1.2 billion. The purchase was completed on March 27, 2002.
The Kern River pipeline is an important route for the transmission of natural gas from the vast reserves in the Rocky Mountain states to the rapidly growing markets in Utah, Nevada and California. Constructed in 1992, Kern River extends 926 miles from Opal, Wyoming, to the San Joaquin Valley near Bakersfield, California, and has a design capacity of 835 million cubic feet per day.
In August 2001, Williams filed with the Federal Energy Regulatory Commission to more than double the capacity on the Kern River system by adding approximately 900 million cubic feet per day of additional capacity from Wyoming to California and markets in between. Upon completion of the expansion project in May 2003, Kern River will be capable of transporting 1.7 billion cubic feet of natural gas per day. When converted to electricity, that is enough energy to power approximately 10 million homes.
In connection with the acquisition of Kern River, the Company issued $323 million of Trust Preferred Securities and $127 million of convertible preferred stock to Berkshire Hathaway.
In addition to the acquisition of Kern River, the Company also announced its investment of $275 million in Williams, in exchange for shares of 9-7/8 percent cumulative convertible preferred stock of Williams. In connection with this investment, the Company issued $275 million of convertible preferred stock to Berkshire Hathaway.
Construction
Zinc Recovery Project
CalEnergy Minerals LLC is constructing the Zinc Recovery Project. The Zinc Recovery Project is designed to have a capacity of approximately 30,000 metric tons per year and is scheduled to commence commercial operations in 2002. Total project costs of the Zinc Recovery Project are expected to be approximately $217.9 million, net of damages, which is being funded by $140.5 million of debt and the balance from funds provided by the parent company. The Zinc Recovery Project has incurred $158.8 million, net of damages, of such costs through December 31, 2001.
MidAmerican Energy
MidAmerican Energy's primary need for capital is utility construction expenditures. For the year ended December 31, 2001, utility construction expenditures totaled $250 million, including allowance for funds used during construction, or capitalized financing costs, and Quad Cities Station nuclear fuel purchases. All such expenditures were met with cash generated from utility operations, net of dividends.
Forecasted utility construction expenditures, including allowances for funds used during construction are $332 million for 2002 and $1.614 billion for 2003 through 2006. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Through 2007, MidAmerican Energy plans to develop and construct two electric generating plants in Iowa, requiring an investment of approximately $1.8 billion. Participation by others in a portion of the second plant is being discussed. The two plants will provide approximately 1,400 megawatts of generating capacity. The first project is a 540-megawatt natural gas-fired combined cycle unit with an estimated cost of $416 million. MidAmerican Energy expects to begin construction on the first project in Spring 2002 following receipt of all regulatory approvals. It is anticipated that the first phase of the project will be completed by 2003 with the remainder being completed in 2005. MidAmerican Energy presently expects that all utility construction expenditures for the next five years will be met with the issuance of long-term debt and cash generated from utility operations, net of dividends. The actual level of cash generated from utility operations is affected by, among other things, economic conditions in the utility service territory, weather and federal and state regulatory actions.
Obligations and Commitments
The Company has contractual obligations and commercial commitments that may affect its financial condition. Based on management's assessment of the underlying provisions and circumstances of the material contractual obligations and commercial commitments of the Company, including material off-balance sheet and structured finance arrangements, there is no known trend, demand, commitment, event or uncertainty that is reasonably likely to occur which would have a material effect on the Company's financial condition or results of operations. The following tables identify material obligations and commitments as of December 31, 2001 (in millions):
Off Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with generally accepted accounting principles. Accordingly, an amount is recorded on our balance sheet as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.
The companies which are accounted for under the equity method have an aggregate $1,120.7 million of debt on their combined, consolidated financial statements and $105.8 million in outstanding letters of credit. The Company's pro-rata share of the debt is $552.1 million and is non-recourse to the Company, except for $139.9 million which the Company has guaranteed on the Salton Sea Funding Notes and is included in the Company's consolidated balance sheet at December 31, 2001. (See Note 8 in the notes to the consolidated financial statements for further discussion). The Company's pro-rata share of the outstanding letters of credit is $52.9 million. The Company is generally not required to support the debt service obligations of these companies. However, default with respect to this non-recourse debt could result in a loss of invested equity.
Electric Rate Matters
In 1997, pursuant to a rate proceeding before the IUB, MidAmerican Energy, the Office of Consumer Advocate and other parties entered into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa retail electric rates. That settlement agreement expired on December 31, 2000.
On March 14, 2001, the Office of the Consumer Advocate filed a petition with the IUB to reduce Iowa retail electric rates by approximately $77 million annually. On June 11, 2001, MidAmerican Energy responded to that petition by filing a request with the IUB to increase MidAmerican Energy's Iowa retail electric rates by $51 million annually. On December 21, 2001, the IUB approved a settlement agreement that freezes the rates in effect on December 31, 2000, through December 31, 2005, and, with modifications, reinstates the revenue sharing provisions of the 1997 pricing plan settlement agreement. Under the 2001 settlement agreement, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and 83.33% of revenues associated with returns on equity above 14%, in each year will be recorded as a regulatory liability to be used to offset a portion of the cost of future generating plant investments.
Environmental Matters: Domestic
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. MidAmerican Energy 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 MidAmerican Energy has any responsibility for remedial action. MidAmerican Energy's estimate of the probable costs for these sites as of December 31, 2001, was $22 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.
In July 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 each state, the EPA will determine which states have areas that do not meet the air quality standards (i.e., areas that are classified as nonattainment). The standard were subjected to legal proceedings, and in February 2001, United States Supreme Court upheld the constitutionality of the standards, through remanding the issue of implementation of the ozone standard to the EPA. The impact of the new standards on MidAmerican Energy is currently unknown.
Environmental Matters: U.K.
The U.K. Government introduced new contaminated land legislation in April 2000 that requires companies to:
o Put in place a program for investigating the company's history to identify problem sites for which it is responsible; o make a clear commitment to meeting responsibilities for cleaning up those sites; o provide funding to make sure that this can happen; and o make commitments public.
CE Electric UK Funding is in the process of completing the evaluation work on the three sites that may be subject to the legislation. Exploratory work with an environmental remediation company is in progress on these sites.
The Environmental Protection Act (Disposal of PCB's and other Dangerous Substances) Regulations 2000 were introduced on May 5, 2000. The regulations required that transformers containing over 50 parts per million (PPM) be registered with the Environment Agency by July 31, 2000. Transformers containing 500 PPM must be de-contaminated by December 31, 2000. CE Electric UK Funding has registered 140 items above 50 PPM on 74 sites, decontaminated 18 items and informed the Environment Agency that it is continuing with its sampling, labeling and registration program.
The Groundwater Regulations seek to prevent List I and List II substances entering groundwater and strengthens the UK Environment Agencies powers to require additional protective measures, especially in areas of important groundwater supplies. Mineral oils and hydrocarbons are included in the more tightly controlled List I substances. This affects the high voltage fluid filled electricity cable network incorporating an insulating fluid currently in the List I category. Further research may result in recategorization because of the biodegradable qualities of the cable fluid. The existing voluntary Operating Code of Practice, as agreed between the Agency and the Electricity Supply Industries, is undergoing revision through the services of the Electricity Association to address the regulatory changes. Helpful discussions with the Environment Agency continue.
The Oil Storage Regulations come into force in 2002 and requires the introduction of secondary containment measures (bunding) for all above ground oil storage locations where the capacity is more than 200 litres. The primary containers must be in sound condition, leak free, and positioned away from vehicle traffic routes. The secondary containment must be impermeable to water and oil (without drainage valve) and be subject to routine maintenance. The capacity of the bund must be sufficient to hold up to 110% of the largest stored vessel or 25% of the maximum stored capacity, whichever is the greater. The full impact of the regulations will be phased in over the next three years. The Regulations come into effect as follows:
o March 1, 2002 for all new oil stores. o September 1, 2003 for existing stores at "significant risk" (i.e. within 10 metres of a water course). o September 1, 2005 for all remaining stores.
A detailed study of the impacts has been carried out and a plan of action prepared to ensure compliance.
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 $41 million during the period 2002 through 2006 to an external trust established for the investment of funds for decommissioning Quad Cities Station. Approximately 60% of the fair value 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.
Based on information presently available and assuming a September 2004 shutdown of Cooper, MidAmerican Energy expects to accrue approximately $54 million for Cooper decommissioning during the period 2002 through 2004. MidAmerican Energy's obligation, if any, for Cooper decommissioning will be affected by the actual plant shutdown date. In July 1997, NPPD filed a lawsuit in United States District Court for the District of Nebraska naming MidAmerican Energy as the defendant and seeking a declaration of MidAmerican Energy's rights and obligations in connection with Cooper nuclear decommissioning funding. See discussion in Item 3, Legal Proceedings.
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.
Cooper Nuclear Station
Under a long-term power purchase contract with NPPD, MidAmerican Energy purchases one-half of the output of Cooper. The Nuclear Regulatory Commission (NRC) has notified NPPD that, effective April 1, 2002, it will place Cooper in its "Multiple Repetitive Degraded Cornerstone" category of the NRC's Reactor Oversight Process Action Matrix. As a result, the NRC will conduct extensive diagnostic inspections at Cooper, which are currently anticipated to be completed during the month of June 2002. MidAmerican Energy cannot, at this time, predict the outcome of the NRC inspections and their impact on the operation of Cooper. NPPD has informed MidAmerican Energy that it is currently developing an improvement plan which it believes will address the issues that caused Cooper to be placed into this category.
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 sales contracts with other project participants, receipt of required governmental permits and consents and timely implementation of construction. There can be no assurance that development efforts on any particular project, or the Company's development efforts generally, will be successful.
The 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 Pronouncements
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting and reporting for business combinations. SFAS No. 141 requires all business combinations entered into subsequent to June 30, 2001, to be accounted for using the purchase method of accounting. SFAS No. 142 provides that goodwill and other intangible assets with indefinite lives will not be amortized but tested for impairment on an annual basis. SFAS No. 142 is effective for the Company beginning January 1, 2002. Under the current method of assessing goodwill for impairment, which uses an undiscounted cash flow approach, no material impairment existed at December 31, 2001. For 2002, the Company will begin to test goodwill for impairment under the new rules, applying a fair-value-based approach. The Company is in the process of quantifying the anticipated impact on its financial condition and results of operations of adopting the provisions of SFAS No. 142, which could be significant. The historical impact of not amortizing goodwill would have been to increase net income for the years ended December 31, 2001, 2000 and 1999 by $94.4 million, $92.4 million and $62.3 million, respectively. However, impairment reviews may result in future periodic write-downs.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which addresses the accounting for legal obligations associated with the retirement of tangible, long-lived assets, and the associated asset retirement costs. This pronouncement is effective for years beginning after June 15, 2002. The Company is evaluating the impact that adoption of this standard will have on its financial statements.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. This pronouncement is effective for years beginning after December 15, 2001. The Company is evaluating the impact that adoption of this standard will have on its financial statements, but does not believe it will have a material impact on its financial statements.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities. The Company uses hedge accounting for derivative instruments pertaining to its natural gas purchasing, wholesale electricity activities, financing activities and preferred stock investing operations. Refer to Note 16 in notes to consolidated financial statements for further discussion.
MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED BALANCE SHEETS (In thousands)
MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands)
MidAmerican Energy Holdings Company Notes To Consolidated Financial Statements
1. Business
MidAmerican Energy Holdings Company and its subsidiaries (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 five separate platforms: MidAmerican Energy, CE Electric UK Funding, CalEnergy Generation-Domestic, CalEnergy Generation-Foreign and HomeServices.
On March 14, 2000, the Company and an investor group comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the Company, David L. Sokol, Chairman and Chief Executive Officer of the Company, and Gregory E. Abel, Chief Operating Officer of the Company closed on a definitive agreement and plan of merger whereby the investor group acquired all of the outstanding common stock of the Company (the "Teton Transaction"). As a result of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and Mr. Abel own approximately 9.7%, 86%, 3% and 1% of the voting stock respectively.
MidAmerican Energy
MidAmerican Energy Company ("MidAmerican Energy") 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. MidAmerican Energy distributes electricity at the retail level in Iowa, Illinois and South Dakota. It also distributes natural gas at the retail level in Iowa, Illinois, South Dakota and Nebraska. As of December 31, 2001, MidAmerican Energy had approximately 673,000 retail electric customers and 652,000 retail natural gas customers.
In addition to retail sales, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities that 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.
A substantial portion 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'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.
CE Electric UK Funding
The business of CE Electric UK Funding, an indirect wholly owned subsidiary of the Company, consists of Northern Electric plc ("Northern"), an indirect wholly owned subsidiary of the Company, and Yorkshire Power Group Ltd. ("Yorkshire"), an indirect majority owned subsidiary of the Company, and CalEnergy Gas (Holdings) Limited ("CE Gas"), an indirect wholly owned subsidiary of the Company.
Northern's and Yorkshire's operations consist primarily of the distribution of electricity and other auxiliary businesses in the United Kingdom. Through September 21, 2001, Northern's operations also included the supply of electricity and natural gas and the related metering business.
Northern and Yorkshire receive electricity from the national grid transmission system and distribute it to customers' premises using their network of transformers, switchgear and cables. Substantially all of the customers in their distribution service areas are connected to their network and can only be delivered through their distribution system, thus providing Northern and Yorkshire with distribution volume that is stable from year to year. Northern and Yorkshire charge 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 was primarily involved in the bulk purchase of electricity, previously through a central pool and from March 27, 2001 on through the New Electricity Trading Agreements ("NETA"), and subsequent resale to individual customers throughout the U.K. The supply business generally is a high volume business that tends to operate at lower profitability levels than the distribution business. Northern also competed to supply gas inside and outside its authorized area. See Note 3.
CE Gas is a gas exploration and production company that 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. Also, CE Gas has been involved in certain gas development and exploration activities relating to a large gas field prospect in Poland, the EP389 concession in the Perth Basin in Australia and the Yolla discovery in the Bass Basin of Australia.
CalEnergy Generation-Domestic
The Company has a 50% ownership interest in CE Generation LLC ("CE Generation") that has interests in ten geothermal plants in the Imperial Valley, California and three natural gas-fired cogeneration plants. For purposes of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch), Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V plants (collectively the "Salton Sea Projects") are based on capacity amounts of 10, 20, 50, 40 and 49 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. 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 its 50% ownership interest in CE Generation, the Company accounts for CE Generation as an equity investment.
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned subsidiary of the Company, operates a 537 MW gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova Project commenced commercial operations on June 19, 2001. Cordova Energy has entered into a power purchase agreement with a unit of El Paso Energy Corporation ("El Paso") in which El Paso will purchase all of the capacity and energy from the project until December 31, 2019. Cordova Energy has exercised an option under the El Paso Power Purchase Agreement to callback 50% of the project output for sales to others for the contract years ending on or prior to May 14, 2004. Cordova Energy subsequently entered into a power purchase agreement with MidAmerican Energy whereby MidAmerican Energy will purchase 50% of the capacity and energy from the Cordova Project until May 14, 2004.
CalEnergy Generation-Foreign
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong Projects (collectively, the "Leyte Projects"), which are geothermal power plants located on the island of Leyte in the Philippines, and the Casecnan Project, a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines. The Casecnan Project commenced commercial operations on December 11, 2001. For purposes of consistent presentation, capacity amounts for Upper Mahiao, Malitbog, Mahanagdong and Casecnan are 119, 216, 165 and 150 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.
HomeServices
HomeServices.Com, Inc. ("HomeServices"), a wholly-owned subsidiary of the Company, is the second largest residential real estate brokerage firm in the United States based on aggregate closed transaction sides in 2000 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 in the following fourteen states: Minnesota, Iowa, California, Arizona, Kansas, Missouri, Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota, South Dakota and Georgia. HomeServices generally 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, 2001. HomeServices' major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa; Los Angeles and San Diego, California; Omaha, Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield, Missouri; Tucson, Arizona; Annapolis, Maryland and Atlanta, Georgia.
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 50% owned or less, 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 for purchase business combinations.
Cash Equivalents, Investments, and Restricted Cash and Investments
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 investments 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 investments 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.
Inventory
Inventory is primarily composed of materials and supplies, coal stocks, gas in storage and fuel oil. Materials and supplies, coal stocks and fuel oil are at average cost and gas in storage is accounted for under the LIFO method.
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 ten and thirty 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 three to fifteen years.
An allowance for the estimated annual decommissioning costs of the Quad Cities Generating Station ("Quad Cities Station") equal to the level of funding is included in depreciation expense. See Note 20 for additional information regarding decommissioning costs.
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 25 to 40 year period.
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 fair value models, whenever evidence exists that the carrying value is not recoverable.
Contingent Liabilities
The Company is subject to the possibility of various loss contingencies arising in the ordinary course of business. Management considers the likelihood of the loss or impairment of an asset or the incurrence of a liability as well as our ability to reasonably estimate the amount of loss in determining loss contingencies. An estimated loss contingency is accrued when it is probable that a liability has been incurred or an asset has been impaired and the amount of loss can be reasonably estimated. The Company regularly evaluates current information available to determine whether such accruals should be adjusted.
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.
The Company also records unbilled revenues representing the estimated amounts customers will be billed for services rendered between the meter reading dates in a particular month and the end of that month. Accrued unbilled revenues are included in accounts receivable on the consolidated balance sheets.
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 using the effective interest method.
Deferred Income Taxes
The Company recognizes deferred tax assets and liabilities based on the difference between the financial statement and tax basis 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 United States income taxes are not provided for retained earnings of international subsidiaries and corporate joint ventures unless the earnings are intended to be remitted.
Financial Instruments
The Company currently utilizes or had previously utilized swap agreements 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. Gains and losses related to gas forward contracts are deferred and included in the measurement of the related gas purchases. 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 and Transactions
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 (loss) 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 2000 and 1999 consolidated financial statements and supporting note disclosures have been reclassified to conform to the fiscal 2001 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 accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the 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, MidAmerican Energy purchases one-half of the output of the 778-megawatt Cooper Nuclear Station ("Cooper"). The consolidated balance sheets include a liability for MidAmerican Energy's fixed obligation to pay 50% of NPPD's Nuclear Facility Revenue Bonds and other fixed liabilities. A like amount representing MidAmerican Energy's right to purchase power is shown as an asset.
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 remaining 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. For jurisdictions other than Iowa, MidAmerican Energy began charging Cooper capital improvement costs to expense as incurred in January 1997.
The fuel cost portion of the power purchase contract is included in cost of sales. All other costs MidAmerican Energy incurs in relation to its long-term power purchase contract with NPPD are included in operating expense.
Accounting Principle Change
Effective January 1, 2001, the Company has changed its accounting policy regarding major maintenance and repairs for nonregulated gas projects, nonregulated plant overhaul costs and geothermal well rework costs to the direct expense method from the former policy of monthly accruals based on long-term scheduled maintenance plans for the gas projects and deferral and amortization of plant overhaul costs and geothermal well rework costs over the estimated useful lives. The cumulative effect of the change in accounting principle was $4.6 million, net of taxes of $.7 million. If the Company had adopted the policy as of January 1, 2000, income before extraordinary item and cumulative effect of change in accounting principle would have been $6.3 million lower in 2000 on a proforma basis.
Accounting for Derivatives
The Company is exposed to market risk, including changes in the market price of certain commodities and interest rates. To manage the price volatility relating to these exposures, the Company enters into various financial derivative instruments. Senior management provides the overall direction, structure, conduct and control of the Company's risk management activities, including the use of financial derivative instruments, authorization and communication of risk management policies and procedures, strategic hedging program guidelines, appropriate market and credit risk limits, and appropriate systems for recording, monitoring and reporting the results of transactional and risk management activities. The Company uses hedge accounting for derivative instruments pertaining to its natural gas purchasing, wholesale electricity activities, financing activities and preferred stock investing operations.
On January 1, 2001, the Company adopted Statement of Financial Accounting Standards Nos. 133 and 138 (SFAS Nos. 133/138) pertaining to the accounting for derivative instruments and hedging activities. SFAS Nos. 133/138 requires an entity to recognize all of its derivatives as either assets or liabilities in its statement of financial position and measure those instruments at fair value. If the conditions specified in SFAS Nos. 133/138 are met, those instruments may be designated as hedges. Changes in the value of hedge instruments would not impact earnings, except to the extent that the instrument is not perfectly effective as a hedge. At January 1, 2001, the Company recognized $44.9 million and $38.0 million of energy-related assets and liabilities, respectively, as being subject to fair value accounting pursuant to SFAS Nos. 133/138, all of which are accounted for as hedges. Additionally, on January 1, 2001, the Company's portfolio of preferred stock investments was transferred from the available for sale category to the trading category, as permitted by SFAS No. 133. Initial adoption of SFAS Nos. 133/138 did not have a material impact on the results of operations for the Company.
New Accounting Pronouncements
In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting and reporting for business combinations. SFAS No. 141 requires all business combinations entered into subsequent to June 30, 2001, to be accounted for using the purchase method of accounting. SFAS No. 142 provides that goodwill and other intangible assets with indefinite lives will not be amortized but tested for impairment on an annual basis. SFAS No. 142 is effective for the Company beginning January 1, 2002. Under the current method of assessing goodwill for impairment, which uses an undiscounted cash flow approach, no material impairment existed at December 31, 2001. For 2002, the Company will begin to test goodwill for impairment under the new rules, applying a fair-value-based approach. The Company is in the process of quantifying the anticipated impact on its financial condition and results of operations of adopting the provisions of SFAS No. 142, which could be significant. The historical impact of not amortizing goodwill would have been to increase net income for the years ended December 31, 2001, 2000 and 1999 by $94.4 million, $92.4 million and $62.3 million, respectively. However, impairment reviews may result in future periodic write-downs.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which addresses the accounting for legal obligations associated with the retirement of tangible, long-lived assets, and the associated asset retirement costs. This pronouncement is effective for years beginning after June 15, 2002. The Company is evaluating the impact that adoption of this standard will have on its financial statements.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. This pronouncement is effective for years beginning after December 15, 2001. The Company is evaluating the impact that adoption of this standard will have on its financial statements, but does not believe it will have a material impact on its financial statements.
3. Acquisitions/Dispositions
Yorkshire Swap
On September 21, 2001, CE Electric UK Ltd., an indirect wholly owned subsidiary of the Company, and Innogy Holdings, plc executed an agreement to exchange Northern's electricity and gas supply and metering assets for Innogy's 94.75% interest in Yorkshire's electricity distribution business. Northern's supply business was initially valued at approximately $430 million ((pound)295 million), including working capital of approximately $53 million ((pound)37 million). 94.75% of Yorkshire's distribution business was initially valued at approximately $395 million ((pound)271 million), including working capital of approximately $48 million ((pound)33 million). The net cash received by Northern for the exchange was approximately $35 million ((pound)24 million). Working capital is subject to adjustment and is currently under review.
The disposition of Northern's supply business created a pre-tax non-recurring gain of $196.7 million and an after-tax gain of $10.8 million. Included in the carrying value of the Northern supply business was $504.4 million of goodwill allocated based on the relative fair values of the Northern supply business. In connection with the sale of the Northern supply business, management intends to sell the associated Northern retail business.
The Company paid $37.4 million, net of cash acquired of $362.8 million and transaction costs, for 94.75% of the Yorkshire electricity distribution business and related indebtedness. The acquisition has been accounted for as a purchase business combination. The results of operations for Yorkshire are included in the Company's results beginning September 21, 2001.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions).
Cash $ 362.8 Property, plant and equipment 1,262.7 Excess of cost over fair value of net assets acquired 523.6 Other assets 11.6 -------- Total assets acquired 2,160.7 -------- Current liabilities (34.1) Long-term debt (1,503.3) Deferred income taxes (175.8) Minority interest (40.7) Other liabilities (6.6) -------- Total liabilities assumed (1,760.5) --------
Net assets acquired $ 400.2 ========
Teton Transaction
On October 24, 1999, the Company and an investor group comprised of Berkshire Hathaway, Walter Scott, Jr., and David L. Sokol, 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 "Teton Transaction"). The Teton 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 11% nontransferable trust preferred securities due March 14, 2010. 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 approximately 9.7% 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 merger has been accounted for as a purchase business combination. The purchase price has been allocated to assets acquired and liabilities assumed. The Company recorded goodwill of approximately $1.2 billion that is being amortized using the straight-line method over a 40-year period.
The Company incurred approximately $7.6 million and $6.7 million of non-recurring costs in 2000 and 1999 respectively, related to the Teton Transaction, which were expensed.
Unaudited pro forma combined revenue, income before cumulative effect of change in accounting principle and net income of the Company and MEHC (Predecessor) for the years ended December 31, 2001 and 2000, as if the Yorkshire swap and the Teton Transaction had occurred at the beginning of each year after giving effect to pro forma adjustments related to the acquisitions, including the sale of the Northern Supply business and the issuance of the 11% trust preferred securities, were $4,401.0 million, $149.1 million and $144.5 million, respectively, compared to $4,084.0 million, $113.3 million and $113.3 million, respectively.
HomeServices
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%.
On April 14, 2000, the Company purchased 500,000 shares of HomeServices' common stock for $4.2 million, increasing the Company's ownership percentage to approximately 70%.
In October 2000, HomeServices repurchased 1.7 million shares of treasury stock for $17.9 million. This transaction increased the Company's ownership percentage to approximately 83%.
On August 27, 2001, the Company commenced a tender offer to purchase the remaining outstanding shares of common stock of HomeServices for a cash purchase price of $17 per share. On September 25, 2001, the Company announced that it had successfully completed the tender offer for all outstanding shares of the common stock of HomeServices for $29.3 million. As a result, the Company owns 100% of the outstanding HomeServices common stock, although options entitling employees to purchase HomeServices common stock remain outstanding.
4. Property, Plant, Contracts and Equipment, Net
Property, plant, contracts and equipment, net comprise the following at December 31 (in thousands):
2001 2000 ---- ---- Operating assets: Utility generation and distribution system................................ $7,574,339 $6,132,867 Independent power plants .............. 1,398,179 694,615 Utility non-operational assets......... 354,366 344,576 Power sales agreements................. 48,185 82,231 Realty company assets.................. 51,150 37,936 Other assets........................... 47,863 53,590 ---------- ---------- Total operating assets................. 9,474,082 7,345,815 Less accumulated depreciation and amortization...................... (3,650,862) (3,300,237) ---------- ---------- Net operating assets................... 5,823,220 4,045,578 Mineral and gas reserves and exploration assets, net............... 387,697 378,495 Construction in progress: Zinc recovery project............. 163,366 165,585 Utility generation and distribution system............. 149,225 143,261 Casecnan.......................... - 387,274 Cordova........................... - 224,514 Other............................. 3,940 3,940 ---------- ----------
Total $6,527,448 $5,348,647 ========== ==========
Zinc Recovery Project
The Company 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. A pilot plant has successfully produced commercial quality zinc at the Company's Imperial Valley Projects.
CalEnergy 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"). Facilities are being installed near the Imperial Valley Project's 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 operations in 2002. 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 was being constructed by Kvaerner U.S. Inc. ("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering, procure, construct and manage contract (the "Zinc Recovery Project EPC Contract"). On June 14, 2001, CalEnergy Minerals LLC issued notices of default, termination and demand for payment of damages to Kvaerner under the Zinc Recovery Project EPC Contract due to failure to meet performance obligations. As a result of Kvaerner's failure to pay monetary obligations under the Zinc Recovery Project EPC Contract, CalEnergy Minerals LLC drew $29.6 million under the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals LLC has entered into a time and materials reimbursable engineer, procure and construction management contract with AMEC E&C Services, Inc. to complete the Zinc Recovery Project.
On July 11, 2001, Kvaerner filed an Amended Demand For Arbitration against CalEnergy Minerals LLC characterizing the nature of the dispute as concerns regarding change orders and performance penalties. Kvaerner did not state the amount of its claim.
On August 7, 2001, CalEnergy Minerals LLC filed an Answering Statement and Counterclaim against Kvaerner. CalEnergy Minerals LLC denied all material allegations in Kvaerner's Amended Demand for Arbitration, and asserted a counterclaim against Kvaerner for breach of contract and specific performance. CalEnergy Minerals LLC alleged that its total estimated damage for Kvaerner's breach of contract are in excess of approximately $60 million; however, CalEnergy Minerals LLC has offset approximately $42.5 million of these damages by exercising its rights under the EPC Contract to claim the retainage and by drawing on a letter of credit. Therefore, CalEnergy Minerals LLC has asked for a judgment in excess of approximately $20 million. The arbitration is scheduled for June 2002.
5. Equity Investment in CE Generation
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 equity investment in CE Generation at December 31, 2001 and 2000 was approximately $233.6 million and $220.0 million, respectively. The following is summarized financial information for CE Generation as of and for the years ended December 31 (in thousands):
2001 2000 1999 ---- --- ----
Revenues.............................. $ 565,838 $ 510,796 $ 340,683 Income before extraordinary item and cumulative effect of change in accounting principle.... 74,194 73,535 61,970 Net income............................ 58,808 73,535 44,492
Current assets........................ 211,635 188,234 Total assets.......................... 1,932,119 1,984,445 Current liabilities................... 155,808 138,751 Long-term debt, including current portion................... 1,096,256 1,163,729 Total liabilities..................... 1,404,910 1,477,066
6. Short-Term Debt
Short-term debt comprises the following at December 31 (in thousands):
2001 2000 ---- ---- Corporate revolving credit facilities......... $153,500 $ 85,000 MidAmerican Energy short-term debt............ 91,780 81,600 HomeServices revolving credit facility........ 9,000 10,000 Other......................................... 1,732 85,056 -------- -------- $256,012 $261,656 ========= ========
Corporate Revolving Credit Facilities
The Company has available $400 million in revolving credit facilities with $150 million expiring in June 2002 and $250 million expiring in June 2003. The facilities are unsecured and are available to fund working capital requirements and finance future business expansion opportunities. The facilities carry a variable interest rate based on LIBOR and ranging from 2.8125% to 8.5% in 2001 (weighted average interest rate of 2.93% at December 31, 2001).
MidAmerican Energy Short-Term Debt
MidAmerican Energy has authority from the Federal Energy Regulatory Commission ("FERC") to issue short-term debt in the form of commercial paper and bank notes aggregating $500 million. As of December 31, 2001, MidAmerican Energy had in place a $370.4 million revolving credit facility that supports its $250 million commercial paper program and its variable rate pollution control revenue obligations. In addition, MidAmerican Energy has a $5 million line of credit. As of December 31, 2001, commercial paper and bank notes totaled $89.4 million for MidAmerican Energy.
MHC Inc., an indirect wholly owned subsidiary of the Company, has a $4.0 million line of credit under which $2.4 million was outstanding at December 31, 2001. The commercial paper, bank notes and outstanding line of credit have a weighted average interest rate of 1.9% at December 31, 2001.
HomeServices Revolving Credit Facilities
HomeServices has available a $65 million senior secured revolving credit facility of which HomeServices had drawn down approximately $9 million as of December 31, 2001. 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, 2001, the blended average interest rate on the senior secured revolving credit facility borrowings was 3.20%.
7. Parent Company Debt
Parent company debt is unsecured senior obligations of the Company and comprises the following at December 31 (in thousands):
2001 2000 ---- ----
7.63% Senior Notes due 2007.......... $ 350,000 $ 350,000 6.96% Senior Notes due 2003.......... 215,000 215,000 7.23% Senior Notes due 2005.......... 260,000 260,000 7.52% Senior Notes due 2008.......... 450,000 450,000 8.48% Senior Notes due 2028.......... 475,000 475,000 7.52% Senior Notes due 2008.......... 101,680 101,888 Fair value adjustments and other..... (17,182) (21,917) ---------- ---------- $1,834,498 $1,829,971 ========== ==========
Interest on the 7.63% Senior Notes is payable semiannually on April 15 and October 15 of each year. Interest on the remaining parent company debt is payable semiannually on March 15 and September 15 of each year.
8. Subsidiary and Project Debt
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 CE Electric UK Funding, MidAmerican Funding, HomeServices, CE Generation, 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.
Project loans held by subsidiaries and projects comprise the following at December 31 (in thousands):
2001 2000 ---- ---- MidAmerican Funding, LLC Senior Notes and Bonds $ 700,000 $ 700,000
MidAmerican Energy Mortgage Bonds 340,570 340,570 MidAmerican Energy Pollution Control Bonds 157,185 158,625 MidAmerican Energy Notes 322,240 422,240 CE Electric UK Funding Eurobonds 291,643 299,580 CE Electric UK Funding Company Senior Notes and Sterling Bonds 646,500 653,750 Yorkshire Electric Debt 1,491,597 - CE Gas Loan 70,180 73,162 Casecnan Notes and Bonds 320,138 346,439 Philippine Term Loans 313,221 392,625 Cordova Funding Senior Secured Bonds 225,000 225,000 Salton Sea Bonds 139,896 140,528 MidAmerican Capital 8.52% Notes 23,333 46,667 HomeServices 7.12% Senior Notes and Other 36,780 37,607 Other, including fair value adjustments (6,292) (9,119) ---------- ---------- $5,071,991 $3,827,674 ========== ==========
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 acquisition in 1999.
On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85% Senior Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued $200 million of 6.75% Senior Secured Notes due March 1, 2011.
MidAmerican Energy Mortgage Bonds, Pollution Control Bonds and Notes
The components of MidAmerican Energy's Mortgage Bonds, Pollution Control Bonds and Notes at December 31 are as follows (in thousands):
2001 2000 ---- ---- Mortgage bonds: 7.125% Series, due 2003.............. $100,000 $100,000 7.70% Series, due 2004............... 55,630 55,630 7% Series, due 2005.................. 90,500 90,500 7.375% Series, due 2008.............. 75,000 75,000 7.45% Series, due 2023............... 6,940 6,940 6.95% Series, due 2025............... 12,500 12,500 -------- -------- $340,570 $340,570 ======== ======== Pollution control revenue obligations: 5.75% Series, due periodically through 2003......................... $ 5,760 $ 7,200 5.95% Series, due 2023 (secured by general mortgage bonds)........... 29,030 29,030 6.7% Series, due 2003................ 1,000 1,000 6.1% Series, due 2007................ 1,000 1,000 Variable rate series - Due 2016 and 2017, 1.77% and 4.56% respectively............ 37,600 37,600 Due 2023 (secured by general mortgage bond, 1.77% and 4.56%, respectively)..................... 28,295 28,295 Due 2023, 1.77% and 4.56% respectively...................... 6,850 6,850 Due 2024, 1.77% and 4.56% respectively...................... 34,900 34,900 Due 2025, 1.77% and 4.56% respectively...................... 12,750 12,750 -------- -------- $157,185 $158,625 ======== ========
Notes: 8.75% Series, due 2002............... $ 240 $ 240 7.375% Series, due 2002.............. 162,000 162,000 6.5% Series, due 2001................ - 100,000 6.375% Series, due 2006.............. 160,000 160,000 -------- -------- $322,240 $422,240 ======== ========
CE Electric UK Funding Eurobonds
The balances at December 31, 2001 and 2000 consists of the following (in thousands):
2001 2000 ---- ---- 8.625% Bearer bonds due 2005 $145,879 $149,865 8.875% Bearer bonds due 2020 145,764 149,715 -------- -------- $291,643 $299,580 ======== ========
CE Electric UK Funding Company Senior Notes and Sterling Bonds
The balances at December 31 are comprised of the following (in thousands):
2001 2000 ---- ---- 6.853% Senior Notes due 2004 $124,613 $124,503 6.995% Senior Notes due 2007 235,937 235,804 7.25% Sterling Bonds due 2022 285,950 293,443 -------- -------- $646,500 $653,750 ======== ========
The CE Electric UK Funding Company Senior Notes and Sterling Bonds prohibit distributions to any of its stockholders unless certain financial ratios are met by the CE Electric UK Funding Company or the long-term debt rating falls below a prescribed level.
Yorkshire Electric Debt
In connection with the Yorkshire/Northern supply swap on September 21, 2001, the Company assumed approximately $1.5 billion in debt. The balance at December 31, 2001 is comprised of the following (in thousands):
---- 9.250% Eurobond due 2020 $ 383,576 7.250% Eurobond due 2028 311,427 Variable rate Trust Securities due 2020 (5.19% at December 31, 2001) 235,313 8.080% Trust Securities due 2038 261,082 6.496% Yankee Bonds due 2008 300,199 ---------- $1,491,597 ==========
The Yorkshire Electric Debt prohibits distributions to any of its stockholders unless certain financial ratios are met by Yorkshire or the long-term debt rating falls below a prescribed level.
CE Gas Loan
CE Gas borrowed $70.2 million and $73.2 million on a (pound) 70 million revolving facility at December 31, 2001 and 2000, respectively. The amount carries a variable interest rate based on LIBOR (4.87% at December 31, 2001). The revolving facility had utilized (pound) 48.3 million and (pound) 49.0 million at December 31, 2001 and 2000, respectively.
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. The balances at December 31 consist of the following (in thousands):
2001 2000 ---- ---- Senior Secured Floating Rate Notes (FRNs) due in 2002 $ 23,638 $ 49,939 11.45% Senior Secured Series A Notes due in 2005 125,000 125,000 11.95% Senior Secured Series B Bonds due in 2010 171,500 171,500 -------- -------- $320,138 $346,439 ======== ========
The Company held $3.0 million and $6.3 million of the FRNs at December 31, 2001 and 2000, respectively.
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
The Overseas Private Investment Corporation ("OPIC") provided term loan financing for the Company's Malitbog geothermal power project of $46.8 million that was fixed 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 (4.295% at December 31, 2001). The loans have scheduled repayments through June 2005.
Export-Import Bank of the United States ("Ex-Im Bank") provided term loan financing for the Company's Upper Mahiao geothermal power project 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 (5.130% at December 31, 2001). The loans have scheduled repayments through June 2006.
Ex-Im Bank provided term loan financing for the Company's Mahanagdong geothermal power project of $154.6 million at a fixed rate of 6.92%. OPIC is providing term loan financing of $34.3 million at a fixed interest rate of 7.6%. The loans have scheduled repayments through June 2007.
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. The proceeds were loaned to Cordova Energy and comprise the following (in thousands):
MidAmerican Energy Holdings Company has guaranteed a specified portion of the scheduled debt service on the Cordova Funding Senior Secured Bonds equal to $37 million.
Salton Sea Bonds
Salton Sea Funding Corporation, an indirect wholly owned subsidiary of CE Generation, had a debt balance of $520.3 million at December 31, 2001. CalEnergy Minerals LLC is one of several guarantors of the Salton Sea Funding Corporation's debt. As a result of a note allocation agreement, CalEnergy Minerals LLC is primarily responsible for $139.9 million of the 7.475% Senior Secured Series F Bonds due November 30, 2018. MidAmerican Energy Holdings Company has guaranteed a specified portion of the scheduled debt service on the Series F Bonds equal to this current principal amount of $139.9 million and associated interest.
Annual Repayments of Subsidiary and Project Debt
The annual repayments of the subsidiary and project debt for the years beginning January 1, 2002 and thereafter are as follows (in thousands):
9. Income Taxes
Provision for (benefit from) income taxes was comprised of the following (in thousands): MEHC (Predecessor) ------------------ Year Ended March 14, 2000 January 1, 2000 Year Ended December 31, through through December 31, 2001 December 31, 2000 March 13, 2000 1999 ------------ ----------------- -------------- ------------ Current: State.......... $ 2,669 $10,527 $(1,886) $ 7,337 Federal........ 51,025 17,387 9,147 128,839
Foreign........ 43,450 40,823 16,012 13,889 -------- ------ ------- -------- 97,144 68,737 23,273 150,065 -------- ------ ------- --------
Deferred: State.......... 22,095 (1,933) 834 1,791 Federal........ (36,441) (32,469) 1,854 (75,510) Foreign........ 167,266 18,942 5,047 17,129 -------- ------- ------- -------- 152,920 (15,460) 7,735 (56,590) -------- ------- ------- -------- Total.......... $250,064 $53,277 $31,008 $ 93,475 ======== ======= ======= ========
A reconciliation of the federal statutory tax rate to the effective tax rate applicable to income before provision for income taxes follows:
* Dividends on preferred securities of subsidiary trusts are included in minority interest.
Deferred tax liabilities (assets) are comprised of the following at December 31 (in thousands):
2001 2000 ---------- ---------- Property, plant, contracts and equipment.................................... $1,245,140 $ 866,678 Income taxes recoverable through future rates................................. 185,222 186,427 Fuel cost recoveries............................ 20,272 14,598 Reacquired debt................................. 7,544 10,256 --------- --------- 1,458,178 1,077,959
Nuclear reserve and decommissioning............. (17,898) (20,690) Deferred income................................. (24,732) (8,883) Deferred contract costs......................... (65,145) (51,703) Revenue sharing accurals........................ (24,769) (3,742) Accruals not currently deductible for tax purposes............................. (35,221) (40,563) Other........................................... (6,145) (7,350) ---------- --------- (173,910) (132,931) Net deferred income taxes....................... $1,284,268 $ 945,028 ========== =========
10. Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts
The Company has organized special purpose Delaware business trusts (collectively, the "Trusts") pursuant to their respective amended and restated declarations of trusts (collectively, the "Declarations"). The Company, through these Trusts, issued Company-obligated mandatorily redeemable preferred securities (collectively, the "Trust Securities") as follows (in thousands):
During 2001 and 2000, CalEnergy Capital Trust II redeemed 10,000 and 477,000 shares, respectively, of preferred securities at an aggregate cost of approximately $.4 million and $19.5 million, respectively.
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 Subordinated Debentures due February 25, 2012, September 1, 2027, and March 14, 2010, respectively, in outstanding aggregate principal amounts of approximately $155.5 million, $270 million and $454.8 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 Teton Transaction, each Trust Security issued by CalEnergy Capital Trust II and III 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 Teton 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.
Distributions on the Trust Securities (and Junior Debentures) are cumulative, accrue from the date of initial issuance and are payable quarterly in arrears. The Junior Debentures are subordinated in right of payment to all senior indebtedness of the Company and the Junior Debentures are subject to certain covenants, events of default and optional and mandatory redemption provisions, all as described in the Junior Debenture indentures.
Pursuant to Preferred Securities Guarantee Agreements (collectively, the "Guarantees"), between the Company and a preferred guarantee trustee, the Company has agreed irrevocably to pay to the holders of the Trust Securities, to the extent that the Trustee has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the Trust Securities. Considered together, the undertakings contained in the Declarations, Junior Debentures, Indentures and Guarantees constitute full and unconditional guarantees by the Company of the Trusts' obligations under the Trust Securities.
11. Subsidiary-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust
In December 1996, MidAmerican Energy Financing I, a wholly owned statutory business trust of MidAmerican Energy, issued 4,000,000 shares of 7.98% Series MidAmerican Energy-obligated mandatorily redeemable preferred securities. The sole assets of MidAmerican Energy Financing are $103.1 million of MidAmerican Energy 7.98% Series A Debentures due 2045 (the "Debentures"). There is a full and unconditional guarantee by MidAmerican Energy of MidAmerican Energy Financing's obligations under the preferred securities. MidAmerican Energy 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 continue to accrue with interest thereon, and MidAmerican Energy may not declare or pay any dividend or other distribution on, or redeem or purchase, any of its capital stock.
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 a 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. See Note 21.
12. Preferred Stock
In connection with the Teton Transaction, the Company issued 34.6 million shares of no par, zero coupon convertible preferred stock valued at $1,211.4 million. Each share of preferred stock is convertible at the option of the holder into one share of the Company's common stock subject to certain adjustments as described in the Company's Amended and Restated Articles of Incorporation.
13. Stock Options
The Company had 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 allowed options to be granted at 85% of their fair market value of the common stock at the date of grant. Generally, options were issued at 100% of fair market value of the common stock at the date of grant. Options granted under the 1996 plan became exercisable over a period of two to five years and expired if not exercised within ten years from the date of grant or, in some instances, a lesser term.
As a result of the Teton Transaction, the majority of the options were cashed out at $35.05 per share. The remaining options of 2,145,000 were reissued under the new MidAmerican Energy Holdings Company and an additional 703,329 options were issued. The old options are fully vested and the additional options vest monthly over three years. The options are exercisable until the end of the term on March 14, 2008 at exercise prices ranging from $15.94 to $35.05 per share.
14. 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 that the Company could realize in a current transaction.
The methods and assumptions used to estimate fair value are as follows:
Short-term debt - Due to the short-term nature of the short-term debt, the fair value approximates the carrying value.
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 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.
Interest Rate Risk
At December 31, 2001, the Company had fixed-rate long-term debt, Company-obligated mandatorily redeemable preferred securities of subsidiary trusts, and subsidiary-obligated mandatorily redeemable preferred securities of subsidiary trusts of $7,678.0 million in principal amount and having a fair value of $7,808.2 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 $355.7 million if interest rates were to increase by 10% from their levels at December 31, 2001. 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, 2001, the Company had floating-rate obligations of $281.4 million that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. These obligations are not hedged. If the floating rates were to increase by 10% from December 31, 2001 levels, the Company's consolidated interest expense for unhedged floating-rate obligations would increase by approximately $75,000 each month in which such increase continued based upon December 31, 2001 principal balances.
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):
The proceeds and gross realized gains and losses on the disposition of available-for-sale and held-to-maturity investments are shown in the following table (in thousands). Realized gains and losses are determined by specific identification.
15. Non-recurring Items
Teesside
In December 2001, the Company recorded a non-recurring charge of $20.7 million representing an asset valuation impairment charge under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets," relating to the Company's 15.4% interest in Teesside Power Ltd. ("Teesside"). Teesside owns and operates an 1,875 MW combined cycle gas-fired power plant. Enron Corp. ("Enron"), through its subsidiaries, owned a 42.5% interest, operated the plant, and purchased 668MW of capacity. Enron's subsidiary, who owns and operates Teesside, is now in administration and administrators have been appointed to run its business and are attempting to find a buyer. As a result of Enron's subsidiary being in administration, Teesside is in discussion with its lenders over restructuring of the (pound)650 million debt still outstanding. It is anticipated that there will be no further dividends arising from the investment in Teesside and subsequently, the Company has determined the investment in Teesside to be of negligible value.
Telephone Flat Sale
On October 16, 2001, the Company closed on a transaction that transferred all properties and rights of the Telephone Flat Project, a geothermal development project in northern California to Calpine Corp. The Company recorded a pre-tax gain of $20.7 million and an after-tax gain of $12.2 million on the sale of the Telephone Flat Project.
Western States Sale
On June 30, 2001, the Company closed on a transaction in which the Company sold Western States Geothermal, an indirect wholly owned subsidiary of the Company, to Ormat. The Company recorded a pre-tax gain of $9.8 million and an after-tax gain of $6.4 million on the sale of Western States Geothermal.
Qualified Facilities Dispositions
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 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.
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.
Indonesia
On December 2, 1994, former 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.
In 1997 and 1998 a series of Indonesian government decrees and other actions created significant uncertainty as to whether 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.
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. On November 18, 1999, the Company transferred the Indonesian Subsidiaries to OPIC and 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.
On September 13, 2001, the Company transferred shares of Bali Energy Ltd., an indirect wholly owned Indonesian subsidiary of the Company, to PT Tenaga Burni Bali. The Company recorded a pre-tax gain of $10.4 million and an after-tax gain of $6.5 million on the transfer of the shares.
16. Accounting for Derivatives
Interest Rate Risk
MidAmerican Energy has entered into a two-year, $162 million fixed-to-floating interest rate swap agreement in conjunction with its $162 million, 7.375% series of medium-term notes due August 1, 2002. The floating rate of the swap is based on a three-month LIBOR rate and the effective interest rate after the swap was 4.46% in 2001. As of December 31, 2001, the fair value of this swap was $9.1 million.
Currency Exchange Rate Risk
CE Electric UK Funding entered into certain currency 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 at December 31, 2001 is approximately $44.8 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to receive if these agreements were terminated. It is the Company's intention to hold these swap agreements to maturity.
Yorkshire entered into certain currency rate swap agreements for the Trust Securities and the Yankee Bonds with five 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 $255 million of Trust Securities, the agreements extend until June 30, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 9.4758% to 9.715%. For the $300 million of Yankee Bonds, the agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed Sterling rate ranging from 7.3175% to 7.345%. The estimated fair value of these swap agreements at December 31, 2001 is approximately $8.4 million based on quotes from the counterparty to these instruments and represents the estimated amount that the Company would expect to receive if these agreements were terminated. It is the Company's intention to hold these swap agreements to maturity.
A decrease of 10% in the December 31, 2001 rate of exchange of Sterling to dollars would increase the amount received if these swap agreements were terminated by approximately $106.4 million.
Energy Commodity Price Risk
Under the current regulatory framework, MidAmerican Energy is allowed to recover in revenues the cost of gas sold from all of its regulated gas customers through a purchased gas adjustment clause. Because the majority of MidAmerican Energy's firm natural gas supply contracts contain pricing provisions based on a daily or monthly market index, MidAmerican Energy's regulated gas customers, although ensured of the availability of gas supplies, retain the risk associated with market price volatility.
MidAmerican Energy enters into natural gas futures and swap agreements to mitigate a portion of the market risk retained by its regulated gas customers through the purchased gas adjustment clause. These financial derivative activities are recorded as hedge accounting transactions, with net amounts exchanged or accrued under swap agreements and realized gains or loses on futures contracts included in the cost of gas sold and recovered in revenues from regulated gas customers.
MidAmerican Energy also derives revenues from nonregulated sales of natural gas. Pricing provisions are individually negotiated with these customers and may include fixed prices or prices based on a daily or monthly market index. MidAmerican Energy enters into natural gas futures and swap agreements to offset the financial impact of variations in natural gas commodity prices for physical delivery to nonregulated customers. These financial derivative activities are also recorded as hedge accounting transactions.
MidAmerican Energy uses natural gas derivative instruments for trading purposes pursuant to EITF 98-10 under strict value-at-risk guidelines outlined by senior management. Derivative instruments held for trading purposes are recorded at fair value and any unrealized gains or losses are reported in earnings. Trading revenues and costs are reported gross on the consolidated statements of operations.
MidAmerican Energy is exposed to variations in the price of fuel for generation and the price of purchased power in its Iowa jurisdiction comprising 89% of 2001 electric operating revenues. Fuel price risk is mitigated through forward contracts. Under typical operating conditions, MidAmerican Energy has sufficient generation to supply its retail electric needs. A loss of such generation at a time of high market prices could subject MidAmerican Energy to losses on its energy sales. MidAmerican Energy uses electricity forward contracts to hedge anticipated sales of wholesale electric power.
MidAmerican Energy and its customers are exposed to the effect of variations in weather conditions on sales and purchased, respectively, of electricity and natural gas. For the 2001-2002 heating season, MidAmerican Energy entered into several degree-day swaps to offset a portion of the financial impact of those variations on MidAmerican Energy and its customers.
MidAmerican Energy had the following financial derivative instruments for its natural gas and electric operations as of December 31:
MidAmerican Energy derivative instruments used for other than trading purposes-
A $1.00 decrease in underlying natural gas prices would decrease unrealized gains on the futures contracts held at December 31, 2001, by approximately $0.6 million and would decrease unrealized losses on the above swap contracts by approximately $7.0 million. A $5.00 increase in underlying electricity prices would decrease unrealized gains on the forward contracts held at December 31, 2001, by approximately $3.6 million. The weighted average maturity for all derivative instruments used for hedging purposes is under one year.
Unrealized gains and losses on cash flow hedges of future transactions are recorded in other comprehensive income. Only hedges that are highly effective in offsetting the risk of variability in future cash flows are accounted for in this manner. Future transactions include purchases of gas for resale to regulated and nonregulated customers, purchases of gas for storage, and purchases and sales of wholesale electric energy. When the associated hedged future transaction occurs or if a hedging relationship is no longer appropriate, the unrealized gains and losses are reversed from other comprehensive income and recognized in net income. Realized gains on cash flow hedges are recorded in either cost of sales or operating revenues, depending upon the nature of the physical transaction being hedged.
For 2001, a net loss of $408,000 and a net gain of $36,000, representing the ineffectiveness of cash flow hedges, are reflected in cost of sales. During the twelve months beginning January 1, 2002, it is anticipated that $3.4 million of the $3.5 million after-tax, net unrealized gains on cash flow hedges presently recorded as accumulated other comprehensive income will be realized and recorded in earnings. MidAmerican Energy has hedged a portion of its exposure to the variability of cash flows for future transactions through December 2003.
Unrealized gains and losses on fair value hedges are recognized in income as either operating revenues or cost of sales depending upon the nature of the item being hedged. Purchase and sales commitments hedged by fair value hedges are recorded at fair value, with the changes in values also recognized in income and substantially offsetting the impact of the hedges on earnings. For 2001, a net pre-tax gain of $18,000, representing the ineffectiveness of fair value hedges, is included in operating revenues.
MidAmerican Energy derivative instruments used for trading purposes -
2001 2000 ------------- --------------- Natural Gas Futures Contracts - NYMEX: Net Contract Volumes- (Short) 120,000 MMBtu (20,000) MMBtu Unrealized (Loss), in thousands $(224) $(79) Weighted Average Settlement Price $1.69 $(15.92)
Natural Gas Swap Contracts: Contract Volumes - Pay Fixed 17,519,581 MMBtu 1,000,000 MMBtu Contract Volumes - Receive Fixed 17,850,372 MMBtu 1,010,000 MMBtu Unrealized Gain (Loss), in thousands $2,045 $(261) Weighted Average Pay Fixed Price $(0.99) $0.92 Weighted Average Receive Fixed Price $1.09 $(1.17)
A change in underlying natural gas prices would not materially affect unrealized losses on the above future and swap contracts.
17. Securitization of Accounts Receivable
In December 1998, CE Electric UK Funding entered into a revolving receivable purchase agreement with Kitty Hawk Funding Corporation ("Kitty Hawk"), an unaffiliated special purpose entity established to purchase accounts receivable. In October 2000, the facility was transferred to Mont Blanc Capital Corp, administered by ING Barings, which allowed CE Electric UK Funding 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, CE Electric UK Funding received $161 million in cash associated with the agreement. In connection with the Northern Supply/Yorkshire swap on September 21, 2001, CE Electric UK Funding repaid the outstanding balance of this purchase agreement and ended their arrangement with Mont Blanc Capital Corp. CE Electric UK Funding does not have any amounts outstanding at December 31, 2001.
In 1997, MidAmerican Energy entered into a revolving agreement, which expires in October 2002, to sell all of its right, title and interest in the majority of its billed accounts receivable to MidAmerican Energy Funding Corporation, a special purpose entity established to purchase accounts receivable from MidAmerican Energy. MidAmerican Energy Funding Corporation in turn sells receivable interests to outside investors. In consideration of the sale, MidAmerican Energy received cash and a subordinated note, bearing interest at 8%, from MidAmerican Energy Funding Corporation. As of December 31, 2001, the revolving cash balance was $44 million, down $26 million from December 31, 2000, and the amount outstanding under the subordinated note was $28.7 million. The agreement is structured as a true sale under which the creditors or MidAmerican Energy Funding Corporation will be entitled to be satisfied out of the assets of MidAmerican Energy Funding Corporation prior to any value being returned to MidAmerican Energy or its creditors. Therefore, the accounts receivable sold are not reflected on the consolidated balance sheets. At December 31, 2001, $71.5 million of accounts receivable, net of reserves, was sold under the agreement.
18. Regulatory Matters
CE Electric UK Funding
Most revenue of each Distribution License Holder ("DLH") is controlled by a distribution price control formula. The current formula requires that regulated distribution income per unit is increased or decreased each year by RPI-Xd where the Retail Price Index ("RPI") 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 adjustment factor ("Xd") which was established by the regulatory body, the Office of Gas and Electricity Markets ("Ofgem"), at the last price control review (and continues to be 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. This formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a DLH is entitled to charge. The distribution price control formula permits DLHs 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 DLH from year to year. It is a control on revenue that operates independently of most of the DLH's costs. During the lifetime of the price control, additional cost savings therefore contribute directly to profit.
MidAmerican Energy
In 1997, pursuant to a rate proceeding before the Iowa Utilities Board ("IUB"), MidAmerican Energy, the Office of Consumer Advocate and other parties entered into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa retail electric rates. That settlement agreement expired on December 31, 2000.
On March 14, 2001, the Office of the Consumer Advocate filed a petition with the IUB to reduce Iowa retail electric rates by approximately $77 million annually. On June 11, 2001, MidAmerican Energy responded to that petition by filing a request with the IUB to increase MidAmerican Energy's Iowa retail electric rates by $51 million annually. On December 21, 2001, the IUB approved a settlement agreement that freezes the rates in effect on December 31, 2000, through December 31, 2005, and, with modifications, reinstates the revenue sharing provisions of the 1997 pricing plan settlement agreement. Under the 2001 settlement agreement, an amount equal to 50% of revenues associated with returns on equity between 12% and 14%, and 83.33% of revenues associated with returns on equity above 14%, in each year will be recorded as a regulatory liability to be used to offset a portion of the cost of future generating plant investments. An amount equal to the regulatory liability will be recorded as depreciation expense. As of December 31, 2001, MidAmerican Energy has recorded a $47.1 million regulatory liability that is reflected in other long-term accrued liabilities on the consolidated balance sheet.
Under an Illinois restructuring law enacted in 1997, a sharing mechanism is in place for MidAmerican Energy's Illinois regulated retail electric operations whereby earnings above a computed threshold will be shared equally between customers and shareholders. A two-year average return on common equity greater than a two-year average benchmark will trigger an equal sharing of earnings on the excess. MidAmerican Energy's computed level of return on common equity is based on a rolling two-year average of the 30-year Treasury bond rates plus a premium of 5.50% for 1998 and 1999 and a premium of 8.5% for 200 through 2004. The two-year average above which sharing must occur for 2001 was 14.33%. The law allows MidAmerican Energy to mitigate the sharing of earnings above the threshold return on common equity through accelerated recovery of regulatory assets.
On September 21, 2001, MidAmerican Energy filed a petition with the South Dakota Public Utilities Commission ("SDPUC") to increase its South Dakota natural gas rates. On February 20, 2002, the SDPUC approved a settlement agreement allowing increased rates of $3.1 million annually.
On October 19, 2001, MidAmerican Energy filed a petition with the Illinois Commerce Commission to increase its Illinois natural gas rates by $3.2 million annually. A final decision on the petition is required within eleven months of the date of filing.
On March 15, 2002, MidAmerican Energy made a filing with the IUB requesting an increase in rates of approximately $26.6 million for its Iowa retail natural gas customers. As part of the filing, MidAmerican Energy requested an interim rate increase of approximately $20.4 million annually. The IUB may adjust the requested interim amount and delay its implementation for up to ninety days. MidAmerican Energy expects the final rates, which may differ from the requested amount, to be implemented in the fourth quarter.
19. Pension Commitments
United Kingdom Operations
CE Electric UK Funding 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, 2001, 2000 and 1999 assumed interest rates of 5.75%, 6.0% and 6.0% respectively, an expected return on plan assets of 7.0%, 6.5% and 6.5%, respectively, and annual compensation increases of 2.5%, 3.0% and 3.0%, 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.
The following table details the funded status and the amount recognized in the Company's consolidated balance sheets for CE Electric UK Funding's plan as of December 31, 2001 and 2000 (in thousands):
2001 2000 --------- ---------- Change in benefit obligation: Benefit obligation at beginning of year......... $ 951,553 $ 940,600 Service cost.................................... 7,854 8,660 Interest cost................................... 51,926 50,765 Participant contributions....................... 5,236 4,927 Benefits paid................................... (49,453) (49,272) FAS 88 curtailment.............................. 7,127 6,570 Northern Supply/Yorkshire swap net effect....... 44,216 - Experience gain and change of assumptions....... (44,381) (10,697) --------- --------- Benefit obligation at end of the year........... 974,078 951,553 --------- ---------
Change in plan assets: Fair value of plan assets at beginning of the year................................... 1,166,111 1,283,600 Actual return on plan assets.................... (98,799) (73,741) Net asset transfer resulting from Northern Supply/Yorkshire Swap....................... 46,980 - Employer contributions.......................... 582 597 Participant contributions....................... 5,236 4,927 Benefits paid................................... (49,453) (49,272) --------- ---------- Fair value of plan assets at end of the year.... 1,070,657 1,166,111 --------- ----------
Funded status................................... 96,579 214,558 Unrecognized net loss........................... (196,648) (77,193) --------- ---------- Prepaid benefit cost............................ $ 293,227 $ 291,751 ========= ==========
Net periodic pension cost (benefit) for CE Electric UK Funding's plan for 2001, 2000 and 1999 included the following components (in thousands):
MEHC (Predecessor) ------------------ March 14, 2000 January 1, 2000 through through 2001 December 31, 2000 March 13, 2000 1999 ---- ----------------- -------------- ---- Service cost - benefits earned during the period............. $ 7,854 $ 6,933 $ 1,727 $10,200 Interest cost on projected benefit obligation............ 51,926 40,640 10,125 48,500 Expected return on plan assets........................ (78,979) (50,800) (12,657) (59,500) Curtailment loss................. 7,127 5,260 1,310 38,300 ------- ------- ------- ------- Net periodic pension (benefit) cost..........................$(12,072) $ 2,033 $ 505 $37,500 ======== ======= ====== =======
As a result of the distribution price reviews in 1999, CE Electric UK Funding implemented a review of staffing requirements primarily in its distribution business. Following discussions with the trade unions, CE Electric UK Funding put in place a workforce reduction program. In 1999, the Company recorded a non-recurring pre-tax loss of approximately $47.7 million that included a pension curtailment of $38.3 million. In 2000, the pension curtailment related to this workforce reduction program was $6.6 million. The curtailment loss in 2001 of $7.1 million is a result of the Northern Supply/Yorkshire swap.
Domestic Operations
The Company has primarily noncontributory cash balance defined benefit pension plans covering substantially all domestic 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.
MidAmerican Energy currently provides certain postretirement health care and life insurance benefits for retired employees. Under the plans, substantially all of MidAmerican Energy's employees may become eligible for these benefits if they reach retirement age while working for MidAmerican Energy. However, MidAmerican Energy retains the right to change these benefits anytime at its discretion. MidAmerican Energy 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 MidAmerican Energy. 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.
MidAmerican Energy also maintains noncontributory, nonqualified supplemental executive retirement plans for active and retired participants.
During 2000, MidAmerican Energy adopted a market-related valuation of its pension assets for purposes of calculating net periodic pension costs. This change conforms MidAmerican Energy's accounting practices for pension costs to that of the Company. Net periodic pension, supplemental retirement and postretirement benefit costs included the following components for the Company:
The pension plan assets are in external trusts and are comprised of corporate equity securities, United States government debt, corporate bonds 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, 2001, MidAmerican Energy has Rabbi trusts which hold corporate-owned life insurance and other investments 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 Rabbi trust investments was $50.4 million and $44.7 million at December 31, 2001 and 2000, respectively.
During 1999 certain participants in the supplemental executive retirement plan left MidAmerican Energy reducing the future service of active employees by 28%. As a result, a curtailment loss of $5.3 million was recognized by the Company in 1999. Additionally, termination benefits provided to the participants, totaling $3.5 million, were expensed by MidAmerican Energy during 1999.
The projected benefit obligation and accumulated benefit obligation for the supplemental executive retirement plans were $91.2 million and $88.2 million, respectively, as of December 31, 2001 and $82.7 million and $77.5 million, respectively, as of December 31, 2000.
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 MidAmerican Energy's plans to the net amounts recognized in the consolidated balance sheet as of December 31 (dollars in thousands):
Pension and Postretirement Assumptions MEHC (Predecessor) ---- 2001 2000 1999 ---- ---- ---- Assumptions used were: Discount rate...................................... 6.50% 7.00% 7.75% Rate of increase in compensation levels............ 5.00% 5.00% 5.00% Weighted average expected long-term rate of return on assets.......................... 7.00% 9.00% 9.00%
For purposes of calculating the postretirement benefit obligation, it is assumed health care costs for all covered individuals will increase by 11.25% in 2002 and that the rate of increase thereafter will decrease to an ultimate rate of 5.25% by the year 2006.
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 2001 would increase by $3.0 million, and the postretirement benefit obligation at December 31, 2001, would increase by $30.6 million. If the assumed health care trend rates were to decrease by 1.0%, the total service and interest cost for 2001 would decrease by $2.3 million and the postretirement benefit obligation at December 31, 2001, would decrease by $24.2 million.
20. Commitments and Contingencies
A. Financial Condition of Edison
Southern California Edison Company ("Edison"), a wholly-owned subsidiary of Edison International, is a public utility primarily engaged in the business of supplying electric energy to retail customers in Central and Southern California, excluding Los Angeles. The Company is aware that there have been public announcements that Edison's financial condition has deteriorated as a result of reduced liquidity. Following Edison's recent financing, Edison's senior unsecured debt obligations were upgraded to Ba3 by Moody's and BB by S&P.
Edison failed to pay approximately $119 million due under the power purchase agreement with CE Generation affiliates for power delivered in November and December 2000 and January, February and March 2001, although the Power Purchase Agreements provide for billing and payment on a schedule where payments would have normally been received in early January, February, March, April and May 2001.
On February 21, 2001, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) filed a lawsuit against Edison in California's Imperial County Superior Court seeking a court order requiring Edison to make the required payments under the Power Purchase Agreements. The lawsuit also requested, among other things, that the court order permit the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) to suspend deliveries of power to Edison and to permit the Imperial Valley Projects to sell such power to other purchasers in California.
On March 22, 2001, the Imperial County Superior Court granted the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the Power Purchase Agreements, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) have the right to temporarily suspend deliveries of capacity and energy to Edison, 2) such Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) are entitled to resell the energy and capacity to other purchasers and 3) the interim suspension of deliveries to Edison shall not in any respect result in the modifications or termination of the Power Purchase Agreements, and the Power Purchase Agreements shall in all respects continue in full force and effect other than the temporary suspension of deliveries to Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley Projects (excluding the Salton Sea V and Turbo Projects) suspended deliveries of energy to Edison and entered into a transaction agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) available power was sold to EPME based on percentages of the Dow Jones SP-15 Index. On June 18, 2001 the Superior Court prospectively vacated its order authorizing the Imperial Valley Projects' (excluding the Salton Sea V and Turbo Projects) right to resell power pursuant to the Declaratory Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and Payment Issues with Edison ("Settlement Agreements") and, as a result, resumed power sales to Edison on June 22, 2001. The Settlement Agreements required that Edison make an initial payment to repay the past due balances under the Power Purchase Agreements (the "stipulated amounts"). The initial payment of approximately $11.6 million, which represented 10% of the stipulated amounts, was received June 22, 2001. On October 2, 2001, the California Public Utilities Commission announced an agreement with Edison that allowed Edison to recover in retail electric rates its past due obligations. On November 30, 2001, the Settlement Agreements were amended to reflect when Edison would be required to make the final payment on past due amounts. On March 1, 2002, Edison obtained $1.8 billion in secured financing that, when combined with cash on hand, enabled Edison to pay off its past due debts. The final payment of approximately $104.6 million, representing the remaining stipulated amounts, was received March 1, 2002. In addition to these payments, Edison was required to make monthly interest payments calculated at a rate of 7% per annum on the outstanding stipulated amounts. The amended Settlement Agreements provide a revised energy pricing structure, whereby Edison elects to pay the Imperial Valley Projects a fixed energy price in lieu of the Commission-approved Avoided Cost of Energy Methodology under the Power Purchase Agreements. The fixed energy price is 3.25 cents/kWh from December 2001 through April 30, 2002 and 5.37 cents/kWh commencing May 1, 2002 for a five year period. Following the five year period, the energy payments revert back to the Commission-approved Avoided Cost of Energy Methodology under the Power Purchase Agreements. Estimates of Edison's future Avoided Cost of Energy vary substantially from year to year.
As a result of Edison's failure to make the payments due under the Power Purchase Agreements and the downgrades of Edison's credit rating, Moody's downgraded the ratings for the Salton Sea Funding Corporation (the "Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded the ratings for the Funding Corporation Securities to BBB- and placed the Securities on "credit watch negative." Moody's downgraded the ratings for the CE Generation Securities to B1 from Baa3 (review for possible downgrade). Following the execution of the Settlement Agreements, Moody's placed the Salton Sea Funding and CE Generation securities on "credit watch positive." The Funding Corporation Securities are currently rated Ba3 by Moody's and BBB- by S&P. CE Generation Securities are currently Ba2 by Moody's and BBB- by S&P.
B. Casecnan
The Casecnan Project was initially being constructed pursuant to a fixed-price, date-certain, turnkey construction contract (the "Hanbo Contract") on a joint and several basis by Hanbo Corporation ("Hanbo") and Hanbo Engineering and Construction Co., Ltd. ("HECC"), both of which are South Korean corporations. As of May 7, 1997, the Company terminated the Hanbo Contract due to defaults by Hanbo and HECC including the insolvency of both companies. On the same date, the Company entered into a new fixed-price, date certain, turnkey engineering, procurement and construction contract to complete the construction of the Casecnan Project (the "Replacement Contract"). The work under the Replacement Contract is being conducted by a consortium consisting of Cooperativa Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C. Spa., working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and Colenco Power Engineering Ltd. (collectively, the "Contractor").
On November 20, 1999, the Replacement Contract was amended to extend the Guaranteed Substantial Completion Date for the Casecnan Project to March 31, 2001. This amendment was approved by the lender's independent engineer under the Casecnan Indenture.
On February 12, 2001, the Contractor filed a Request for Arbitration with the International Chamber of Commerce seeking an extension of the Guaranteed Substantial Completion Date by up to 153 days through August 31, 2001 resulting from various alleged force majeure events. In a March 20, 2001 Supplement to Request for Arbitration, the Contractor also seeks compensation for alleged additional costs of approximately $4 million it incurred from the claimed force majeure events to the extent it is unable to recover from its insurer. On April 20, 2001, the Contractor filed a further supplement seeking an additional approximately $62 million in damages for the alleged force majeure event (and geologic conditions) related to the collapse of the surge shaft. The Contractor alleged that the circumstances surrounding the placing of the Casecnan Project into commercial operation on December 11, 2001 amounted to a termination of the Replacement Contract and filed a claim for unspecified quantum meruit damages. CE Casecnan believes such allegations and claims are without merit and is vigorously defending the Contractor's claims. The arbitration is being conducted applying New York law and pursuant to the rules of the International Chamber of Commerce.
On June 25, 2001, the arbitration tribunal temporarily enjoined CE Casecnan from making calls on the demand guaranty posted by Banca di Roma in support of the Contractor's obligations to CE Casecnan for delay liquidated damages. Hearings on the force majeure claims were held in London from July 2 to 14, 2001, and hearings on the Contractor's April 20, 2001 supplement were held in London from September 24 to October 3, 2001. Further hearings were held from January 2 to February 1, 2002 and additional hearings were held from March 14 to 19, 2002.
As of December 31, 2001 the Company has received approximately $6.0 million of liquidated damages from demands made or the demand guarantees posted by Commerzbank on behalf of the Contractor. Although the outcome of the arbitration is difficult to assess, CE Casecnan believes it will prevail and receive substantial additional liquidated damages in the arbitration.
Under the Project Agreement, if NIA is able to accept delivery of water into the Pantabangan Reservoir and NPC has completed the Project's related transmission line, the Company is liable to pay NIA $5,500 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. NIA completed the installation of the transmission line on August 13, 2001. Accordingly, the Company accrued $1.6 million liquidated damages payable to NIA for 120 days of delay.
The Company'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. Except to the extent expressly provided for in the Shareholder Support Letters, no shareholders, partners or affiliates of the Company, including MidAmerican, and no directors, officers or employees of the Company will guarantee or be in any way liable for payment of the Company's obligations. As a result, payment of the Company's obligations depends upon the availability of sufficient revenues from the Company's business after the payment of operating expenses.
C. Decommissioning Costs
Expected decommissioning costs for Quad Cities Station and Cooper have been developed based on site-specific decommissioning studies that include decontamination, dismantling, site restoration, dry fuel storage cost and assumed shutdown dates. In Illinois, Cooper nuclear decommissioning costs are recovered through a rate rider on customer billings that permits annual adjustments. Quad Cities Station and Cooper decommissioning costs are reflected as base rates in Iowa tariffs.
MidAmerican Energy's share of expected decommissioning costs for Quad Cities Station, in 2001 dollars, is $278 million. MidAmerican Energy has established external trusts for the investment of funds for decommissioning the Quad Cities Station. The total accrued balance as of December 31, 2001, was $158.3 million and is included in other long-term accrued liabilities, and a like amount is reflected in Investments and represents the fair value of the assets held in the trusts.
MidAmerican Energy's depreciation expense included costs for Quad Cities Station nuclear decommissioning of $8.3 million, $8.3 million, and $10.4 million for 2001, 2000 and 1999, respectively. The provision charged to depreciation expense is equal to the funding that is being collected in rates. The decommissioning funding component of MidAmerican Energy's Illinois and Iowa tariffs assumes decommissioning costs, related to the Quad Cities Station, will escalate at an annual rate of 4.5% and the assumed annual return on funds in the trust is 6.9%. Realized income (loss), net of investment fees, on the assets in the trust fund was $(0.6) million, $1.9 million and $1.9 million for 2001, 2000 and 1999, respectively.
MidAmerican Energy's contribution toward payment of Cooper's projected decommissioning costs have been based on the NPPD decommissioning funding plan for Cooper. Total expected decommissioning costs for Cooper, in 2001 dollars, are $577 million. For purposes of developing a decommissioning funding plan for Cooper, the 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, 2001, total funds set aside in the internal and external accounts for Cooper decommissioning that are maintained by the NPPD were $291.3 million. In addition, the funding plan for Cooper also assumes various funds and reserves currently held to satisfy the NPPD bond resolution requirements will be available for plant decommissioning, which is to begin with the assumed plant shutdown in September 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. Earnings from the internal account and external trust fund, which are recognized by the NPPD as the owner of the plant, are tax exempt and serve to reduce future funding requirements.
Beginning in December 2000, MidAmerican Energy ceased contributing to the accounts maintained by NPPD and began contributing funds to a separate MidAmerican Energy bank account based on the NPPD decommissioning funding plan for Cooper. A liability equal to the amount of funds contributed, plus the earnings on those funds, is reflected in other long-term accrued liabilities on the consolidated balance sheets. MidAmerican Energy records expense equal to the funds contributed to the separate account plus investment fees paid to the NPPD for funds in the accounts they maintain. MidAmerican Energy's expense for Cooper decommissioning was $11.6 million, $11.5 million and $11.3 million for the years 2001, 2000 and 1999, respectively, and is included in other operating expenses.
MidAmerican Energy is currently involved in litigation with NPPD in part related to the determination of MidAmerican Energy's obligation, if any, for costs of decommissioning Cooper. Refer to Note (20)(E) for a discussion of the proceedings.
D. Nuclear Insurance
MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station and Cooper through a combination of insurance purchased by NPPD (the owner and operator of Cooper) and Exelon Generation Company, LLC (the operator and joint owner of Quad Cities Station), insurance purchased directly by MidAmerican Energy, 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.
NPPD and Exelon Generation 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 the 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, MidAmerican Energy'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, Exelon Generation purchases primary and excess property insurance protection for the combined interests in Quad Cities Station, with coverage limits totaling $2.1 billion. For Cooper, MidAmerican Energy and 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 MidAmerican Energy and NPPD are covered for their respective 50% obligation in the event of a loss totaling up to $2.75 billion. MidAmerican Energy 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 MidAmerican Energy, and the property coverages purchased by Exelon Generation, which includes the interests of MidAmerican Energy, 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 MidAmerican Energy from industry mutual policies for its obligations associated with Cooper and Quad Cities Station combined, total $20.5 million.
The master nuclear worker liability coverage, which is purchased by NPPD and Exelon Generation 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 in nuclear-related industries.
E. Cooper Litigation
On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a complaint, in the United States District Court for the District of Nebraska, naming MidAmerican Energy as the defendant and seeking declaratory judgment as to three issues under the parties' long-term power purchase agreement for Cooper capacity and energy. More specifically, the NPPD sought a declaratory judgment in the following respects:
(1) that MidAmerican Energy is obligated to pay 50% of all costs and expenses associated with decommissioning Cooper, and that in the event NPPD continues to operate Cooper after expiration of the power purchase agreement (September 2004), MidAmerican Energy is not entitled to reimbursement of any decommissioning funds it has paid to date or will pay in the future;
(2) that the current method of allocating transition costs as a part of the decommissioning cost is proper under the power purchase agreement; and
(3) that the current method of investing decommissioning funds is proper under the power purchase agreement.
MidAmerican Energy filed its answer and counterclaims. The counterclaims filed by MidAmerican Energy are generally as follows:
(1) that MidAmerican Energy has no duty under the power purchase agreement to reimburse or pay 50% of the decommissioning costs unless conditions to reimbursement occur;
(2) that the term "monthly power costs" as defined in the power purchase agreement does not include costs and expenses associated with decommissioning the plant;
(3) that NPPD violated MidAmerican Energy's directions for application of payments;
(4) that transition costs are not included in any decommissioning costs and are not any kind of costs that MidAmerican Energy is obligated to pay;
(5) that NPPD has the duty to repay all amounts that MidAmerican Energy has prefunded for decommissioning in the event the Nebraska Public Power District operates the plant after the term of the power purchase agreement;
(6) that NPPD is equitably estopped from continuing to operate the plant after the term of the power purchase agreement so long as NPPD does not repay all amounts MidAmerican Energy has prefunded for estimated decommissioning costs together with other amounts in certain funds and accounts and for so long as NPPD fails to provide MidAmerican Energy with certain requested accountings and information;
(7) that certain funds, accounts, and reserves are excessive and are required to be paid to MidAmerican Energy or credited to MidAmerican Energy's pre-2004 monthly power costs;
(8) that MidAmerican Energy has no duty to pay for nuclear fuel, operations and maintenance projects or capital improvements that have useful lives after the term of the power purchase agreement;
(9) that NPPD has mismanaged the plant in numerous described transactions resulting in damage to MidAmerican Energy;
(10) that NPPD has breached its contractual and other duties to MidAmerican Energy by not joining certain litigation and by failing to credit or agree to credit MidAmerican Energy with any recovery for low-level radioactive waste; and
(11) that NPPD has breached its duty to MidAmerican Energy in making invest- ments of decommissioning funds;
On October 6, 1999, the court rendered summary judgment for NPPD on the above-mentioned issue concerning liability for decommissioning (issue one in the first paragraph above) and the related contingent counterclaims filed by MidAmerican Energy (issues one and two in the second paragraph above). The court referred all remaining issues in the case to mediation, and cancelled the November 1999 trial date.
MidAmerican Energy appealed the court's summary judgment ruling. On December 12, 2000, the United States Court of Appeals for the Eighth Circuit reversed the ruling of the district court and granted summary judgment in favor of MidAmerican Energy on issues one and five in the second paragraph above. Additionally, it remanded the case for trial on all other claims and counterclaims.
Since the remand to the District Court from the Eighth Circuit Court of Appeals, NPPD has been granted permission, over MidAmerican Energy's objections, to file a second amended complaint. The second amended complaint asserts that even though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no liability under the power purchase agreement to reimburse or pay NPPD a 50% share of decommissioning costs unless certain conditions occur, MidAmerican Energy has unconditional liability for a 50% share based on agreements other than the power purchase agreement as originally written. NPPD's post-remand contentions -- all strongly disputed by MEC -- are that MidAmerican Energy has unconditional liability for a 50% share of decommissioning based on any of the following alternative theories: (i) the parties without written amendment either modified the power purchase agreement or made a separate agreement that imposes unconditional liability on MidAmerican Energy for decommissioning costs; (ii) absent unconditional liability for a 50% share of decommissioning costs, MidAmerican Energy would be unjustly enriched; (iii) MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs based on promissory estoppel; or (iv) NPPD is entitled to have the power purchase agreement reformed to provide that MidAmerican Energy has unconditional liability for a 50% share of decommissioning costs. In response to NPPD's second amended complaint, MidAmerican Energy filed its first amended answer and third amended counterclaims containing denials, several affirmative defenses, and the counterclaims summarized above. In the course of discovery, NPPD has contended that MidAmerican Energy has some responsibility for some costs of storage of spent fuel resulting from the operation of the plant during the term of the power purchase agreement. MidAmerican Energy disputes this. MidAmerican Energy recently filed a mandamus petition with Eighth Circuit Court of Appeals seeking an order of that court directing the District Court not to permit NPPD to pursue the above alternative theories at trial, since the above alternative theories appear to be contrary to the December 12, 2000 Eighth Circuit Court of Appeals decision. If such relief is not granted, MidAmerican Energy will strongly dispute at trial these contentions and theories put forth by NPPD. Trial in these matters has been recently rescheduled to being on September 9, 2002.
F. Coal and Natural Gas Contract Commitments
MidAmerican Energy has supply and related transportation contracts for its fossil fueled generating stations. The contracts, with expiration dates ranging from 2002 to 2007, require minimum payments of $80.3 million, $70.6 million, $36.2 million, $34.0 million and $2.6 million for the years 2002 through 2006, respectively, and $2.6 million for the total of the years thereafter. MidAmerican Energy expects to supplement these coal contracts with additional contracts and spot market purchases to fulfill its future fossil fuel needs.
MidAmerican Energy has contracts with various companies to purchase electric capacity. The contracts, with expiration dates ranging from 2002 to 2011, require minimum payments of $27.0 million, $30.5 million, $15.3 million, $2.9 million and $2.2 million for the years 2002 through 2006, respectively, and $11.0 million for the total of the years thereafter.
MidAmerican Energy has various natural gas supply and transportation contracts for its gas operations. The minimum commitments under these contracts are $56.6 million, $41.3 million, $13.4 million, $13.2 million and $13.0 million for the years 2002 through 2006, respectively, and $26.7 million for the total of the years thereafter.
21. Subsequent Events
Debt issuance
On February 8, 2002, MidAmerican Energy issued $400 million of 6.75% medium-term notes due in 2031. The proceeds will be used to refinance existing debt and preferred securities and for other corporate purposes. On March 11, 2002, MidAmerican Energy redeemed its MidAmerican-obligated mandatorily redeemable preferred securities of subsidiary trust at 100% of the principal amount plus accrued interest.
Prudential California Acquisition
In February 2002, HomeServices completed its purchase of a majority interest in Prudential California Realty. The cash purchase price of Prudential California Realty was approximately $74 million, with an option to purchase the remaining interests. Additionally, HomeServices is obligated to pay a maximum earnout of $18.5 million calculated based on certain 2002 financial performance measures. The purchase price was financed using the Company's corporate revolver for $40 million which was contributed to HomeServices as equity and the remaining funds were borrowed from available credit under the HomeServices's $65 million revolving credit facility. It is anticipated that the borrowings in connection with this acquisition will be repaid from HomeServices generated funds. The acquisition will be accounted for by the purchase method of accounting, and the Company is in the process of completing the allocation of the purchase price to the assets acquired and liabilities assumed.
Kern River Acquisition
On March 7, 2002, the Company reached a definitive agreement with The Williams Companies, Inc. ("Williams") to acquire Williams' Kern River Gas Transmission Company, a 926-mile interstate pipeline transporting Rocky Mountain and Canadian natural gas to markets in California, Nevada and Utah. The purchase price was $956 million, including $506 million of assumed debt. As part of the agreement, the Company will continue the planned expansion of the Kern River system, a project that will more than double the pipeline's capacity with expected capital expenditures of approximately $1.2 billion. The purchase was completed on March 27, 2002.
The Kern River pipeline is an important route for the transmission of natural gas from the vast reserves in the Rocky Mountain states to the rapidly growing markets in Utah, Nevada and California. Constructed in 1992, Kern River extends 926 miles from Opal, Wyoming, to the San Joaquin Valley near Bakersfield, California, and has a design capacity of 835 million cubic feet per day.
In August 2001, Williams filed with FERC to more than double the capacity on the Kern River system by adding approximately 900 million cubic feet per day of additional capacity from Wyoming to California and markets in between. Upon completion of the expansion project in May 2003, Kern River will be capable of transporting 1.7 billion cubic feet of natural gas per day. When converted to electricity, that is enough energy to power approximately 10 million homes.
In connection with the acquisition of Kern River, the Company issued $323 million of Trust Preferred Securities and $127 million of convertible preferred stock to Berkshire Hathaway.
In addition to the acquisition of Kern River, the Company also announced its investment of $275 million in Williams, in exchange for shares of 9-7/8 percent cumulative convertible preferred stock of Williams. In connection with this investment, the Company issued $275 million of convertible preferred stock to Berkshire Hathaway.
22. Segment Information:
The Company has identified five reportable operating segments principally based on management structure: CalEnergy Generation-Domestic, CalEnergy Generation-Foreign (primarily the Philippines), MidAmerican Energy (domestic utility operations), CE Electric UK Funding (foreign utility operations) and HomeServices (real estate operations). Information related to the Company's reportable operating segments are shown below (in thousands).
MEHC (Predecessor) As of December 31, As of December 31, 2001 2000 1999 ----------- ---------- ---------- Total assets: CalEnergy Generation-Domestic... $ 725,716 $ 663,125 $ 538,598 CalEnergy Generation-Foreign.... 925,825 965,913 1,115,661 MidAmerican Energy.............. 5,023,584 5,324,921 5,072,788 CE Electric UK Funding.......... 3,973,457 2,414,394 2,953,288 HomeServices.................... 226,588 169,470 166,658 ----------- ----------- ---------- Segment assets.................. 10,875,170 9,537,823 $9,846,993 ========== Corporate/other................. 1,740,163 2,073,116 ----------- ----------- $12,615,333 $11,610,939 =========== ===========
Long-lived assets: CalEnergy Generation-Domestic... $ 441,603 $ 434,523 $ 222,357 CalEnergy Generation-Foreign.... 802,092 790,077 809,506 MidAmerican..................... 4,050,285 4,079,250 3,995,763 CE Electric UK Funding.......... 3,302,560 1,884,951 2,438,877 HomeServices.................... 165,689 125,894 129,649 ----------- ----------- ---------- Segment long-lived assets....... 8,762,229 7,314,695 $7,596,152 =========== Corporate....................... 1,404,307 1,707,102 ----------- ----------- $10,166,536 $ 9,021,797 =========== ===========
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, intersegment eliminations, unallocated goodwill and fair value adjustments relating to acquisitions.
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 (successor to MidAmerican Energy Holdings Company (Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the "Company") as of December 31, 2001 and 2000 for the Company, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year ended December 31, 2001 for the Company, for the period January 1, 2000 to March 13, 2000 for MEHC (Predecessor), for the period March 14, 2000 to December 31, 2000 for the Company, and for the year ended December 31, 1999 for MEHC (Predecessor). Our audits also included the financial statement schedules listed in the Index at Item 14. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2001 and 2000, and the results of their operations and their cash flows for the above stated periods in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, in 2001 the Company changed its accounting policy for major maintenance, overhaul and well workover costs.
DELOITTE & TOUCHE LLP Des Moines, Iowa January 17, 2002
(March 27, 2002 as to Notes 20.A. and 21)
MidAmerican Energy Holdings Company Schedule I Parent Company Only Condensed Balance Sheets As of December 31, 2001 and 2000 (In thousands)
2001 2000 ---------- -------- ASSETS Current Assets: Cash and cash equivalents............ $ 2,524 $ 8,223 ---------- ---------- Total current assets............... 2,524 8,223
Investments in and advances to subsidiaries and joint ventures....... 3,432,528 3,125,487 Equipment, net.......................... 17,605 17,228 Excess of cost over fair value of net assets acquired, net.............. 1,211,814 1,216,550 Deferred charges and other assets....... 129,501 127,966 ---------- ----------
Total Assets............................ $4,793,972 $4,495,454 ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable and other accrued liabilities................ $ 68,445 $ 54,073 Short term debt...................... 153,500 85,000 ---------- ---------- Total current liabilities.......... 221,945 139,073
Non-current liabilities................. 6,480 6,435 Notes payable - affiliate............... 197,153 122,177 Parent company debt..................... 1,834,498 1,829,971 ---------- -----------
Total liabilities.................... 2,260,076 2,097,656 ---------- -----------
Deferred income......................... 37,578 34,874 Company-obligated mandatorily redeemable preferred securities of subsidiary trusts.................. 788,151 786,523
Stockholders' Equity: Zero coupon convertible preferred stock authorized 50,000 shares, no par value 34,563 shares issued and outstanding at December 31, 2001 and 2000......... - - Common stock -authorized 60,000 shares, no par value; 9,281 shares issued and outstanding at December 31, 2001 and 2000.................................. - - Additional paid in capital.............. 1,553,073 1,553,073 Retained earnings....................... 223,926 81,257 Accumulated other comprehensive loss, net................................... (68,832) (57,929) ---------- ---------- Total stockholders' equity.............. 1,708,167 1,576,401 ---------- ----------
Total Liabilities and Stockholders' Equity................................ $4,793,972 $4,495,454 ========== ==========
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
MidAmerican Energy Holdings Company Schedule I Parent Company Only (continued) Condensed Statements of Operations For the three years ended December 31, 2001 (In thousands)
SCHEDULE II
MIDAMERICAN ENERGY HOLDINGS COMPANY CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31, 2001 (In Thousands)
Column A Column B Column C Column D Column E -------- -------- -------- -------- -------- Balance at Additions Balance at Beginning Charged Other End Description of Year to Income Accounts Deductions of Year - ----------- ---------- --------- -------- ---------- -------
Reserves Deducted From Assets To Which They Apply:
Reserve for uncollectible accounts receivable:
Year ended 2001......... $ 32,685 $ 17,061 $ - $(42,427) $ 7,319 ======== ======== ======= ======== =======
Year ended 2000......... $ 18,666 $ 40,024 $ - $(26,005) $32,685 ======== ======== ======= ======== =======
Year ended 1999 ........ $ 11,994 $ 14,483 $ - $ (7,811) $18,666 ======== ======== ======= ======== =======
Reserves Not Deducted From Assets (1):
Year ended 2001......... $25,063 $ 5,046 $ - $(16,478) $13,631 ======= ======== ======= ======== =======
Year ended 2000......... $17,696 $10,832 $ - $ (3,465) $25,063 ======= ======= ======= ======== =======
Year ended 1999 ........ $ 5,660 $15,112 $ 2,148 $ (5,224) $17,696 ======= ======= ==-==== ======== =======
(1) Reserves not deducted from assets include estimated liabilities for losses retained by MHC for workers compensation, public liability and property damage claims.
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
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 2002.
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, 2002 David L. Sokol Chairman of the Board, Chief Executive Officer, and Director
/s/ Gregory E. Abel* - --------------------- March 30, 2002 Gregory E. Abel President, Chief Operating Officer and Director
/s/ Patrick J. Goodman* - ------------------------ March 30, 2002 Patrick J. Goodman Senior Vice President and Chief Financial Officer
/s/ Edgar D. Aronson* - --------------------- March 30, 2002 Edgar D. Aronson Director
/s/ Stanley J. Bright * - ------------------------ March 30, 2002 Stanley J. Bright Director
/s/ Walter Scott, Jr.* - ---------------------- March 30, 2002 Walter Scott, Jr. Director
/s/ Marc D. Hamburg * - --------------------- March 30, 2002 Marc D. Hamburg Director
/s/ Warren Buffett* - -------------------- March 30, 2002 Warren Buffett Director
/s/ John Boyer* - ---------------- March 30, 2002 John Boyer Director
/s/ W. David Scott* - ------------------- March 30, 2002 W. David Scott Director
/s/ Richard R. Jaros* - ------------------- March 30, 2002 Richard R. Jaros Director
*By:/s/ Douglas L. Anderson - ---------------------------- March 30, 2002 Douglas L. Anderson Attorney-in-Fact
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of the Company in effect until March 6, 2002.
3.2 Bylaws of the Company.
3.3 Amended and Restated Articles of Incorporation of the Company effective March 6, 2002.
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 reference 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.
4.11 Indenture, dated as of March 12, 2002 among the Company and the Bank of New York, as Trustee.
4.12 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 7, 2002.
4.13 Subscription Agreement executed by Berkshire Hathaway Inc. dated as of March 12, 2002.
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 and Steven A. McArthur, dated May 10, 1999.
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 Agreement dated February 18, 1994 and the Fourth Amendment to 125 MW Power Plant - Upper Mahiao Agreement dated as of March 7, 1994 (incorporated by reference to Exhibit 10.95 to the Company's 1994 Form 10-K).
10.10 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 (incorporated 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 reference 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 Savings Association 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 Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to the Company's 1994 Form 10-K).
10.17 Finance Agreement dated as of June 30, 1994 between CE Luzon Geothermal Power Company, Inc. and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.103 to the Company's 1994 Form 10-K).
10.18 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 Geothermal 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).
10.20 231 MW Power Plant - Malitbog Agreement ("Malitbog ECA") dated September 10, 1993 between PNOC-EDC and Magma Power Company and the First and Second Amendments thereto dated December 8, 1993 and March 10, 1994, respectively (incorporated by reference to Exhibit 10.106 to the Company's 1994 Form 10-K).
10.21 Credit Agreement dated as of November 10, 1994 among Visayas Power Capital Corporation, the Banks parties thereto and Credit Suisse Bank Agent (incorporated by reference to Exhibit 10.107 to the Company's 1994 Form 10-K).
10.22 Finance Agreement dated as of November 10, 1994 between Visayas Geothermal Power Company and Overseas Private Investment Corporation (incorporated by reference to Exhibit 10.108 to the Company's 1994 Form 10-K).
10.23 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. (incorporated 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 reference 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 the 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 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 Company's 1996 Form 10-K).
10.33 Gas Suppliers License dated February 21, 1996 (incorporated by reference to Exhibit 10.135 to the Company's 1996 Form 10-K).
10.34 Acquisition Agreement by and between CalEnergy Company, Inc. and Kiewit Diversified Group Inc. dated as of September 10, 1997 (incorporated by reference to Exhibit 2 to the Company's Current Report on Form 8-K dated September 11, 1997).
10.35 Agreement and Plan of Merger dated as of August 11, 1998 by and among CalEnergy Company, Inc., Maverick Reincorporation Sub, Inc., MidAmerican 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, between 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.)
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. (incorporated 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. (incorporated by reference to Iowa-Illinois as Exhibit 4.B.30 to Commission File No. 33-39211.)
10.48 Twenty-Eighth Supplemental Indenture dated as of May 15, 1992. (incorporated 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. (incorporated 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 MidAmerican 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, Registration 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.)
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, Commission 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 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.)
10.73 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-Q for the quarter ended September 30, 1997, Commission File Nos. 1-12459 and 1-11505, respectively.)
21.0 Subsidiaries of Registrant.
24.0 Power of Attorney.
Exhibit 21
MIDAMERICAN ENERGY HOLDINGS COMPANY
SUBSIDIARIES AND JOINT VENTURES
Subsidiaries:
MidAmerican Energy Holdings Company Iowa MidAmerican Funding, LLC Iowa MHC Inc. Iowa MidAmerican Energy Company Iowa MidAmerican Energy Financing I Delaware MidAmerican Energy Funding Corporation Delaware CBEC Railway Inc. Iowa MidAmerican Capital Company Delaware AmGas Inc. Iowa Cimmred Leasing Company South InterCoast Capital Company South Dakota InterCoast Energy Company Delaware InterCoast Global Management, Inc Delaware InterCoast Power Company Delaware InterCoast Power Marketing Company Delaware IWG Co. 8 Delaware MHC Investment Company South Dakota MidAmerican Rail Inc Iowa MWR Capital Inc. South Dakota TTP, Inc. of South Dakota South Dakota Edge Technologies, Inc. Iowa Micro-Generation Technology Fund, LLC Delaware Tenaska III Texas Partners Texas Utech Venture Capital Corporation Delaware Midwest Capital Group, Inc. Iowa Dakota Dunes Development Company Iowa Two Rivers Inc. South Dakota Northgate Park Associates Iowa MidAmerican Services Company Iowa MEC Construction Services Co. Iowa HomeServices.Com Inc. Delaware CBS Brokerage Systems Inc. Nebraska CBSHome Real Estate Company Nebraska Champion Realty, Inc. Maryland Chancellor Mortgage Services, Inc. Maryland Chancellor Title Services, Inc. Maryland Edina Corporate Services, Inc. Minnesota Edina Financial Services, Inc. Minnesota Edina Realty Franchise Associates, Inc. Minnesota Edina Realty, Inc. Minnesota Edina Realty Insurance Agency, Inc. Minnesota Edina Realty of Wisconsin, Inc. Wisconsin Edina Realty Title, Inc. Minnesota First Realty, Ltd. Iowa For Rent, Inc. Arizona HMSV Financial Services, Inc. Delaware HMSV Technologies, Inc. Delaware HomeServices of California, Inc. Delaware IMO Co., Inc. Missouri Iowa Realty Co., Inc. Iowa Iowa Realty Insurance Agency, Inc. Iowa Iowa Title Company Iowa Iowa Title Linn County LLC Iowa JC Nichols Residential Inc. Iowa J. C. Nichols Residential Peculiar, LLC Missouri J. P. & A., Inc. Georgia Jenny Pruitt & Associates, Inc. Georgia Kansas City Title, Inc. Missouri Kentucky Residential Referral Service, LLC Kentucky MidAmerican Commercial Real Estate Services, Inc. Kansas Midland Escrow Services, Inc. Iowa MRSCT, Inc. Kentucky Nebraska Land Title and Abstract Company Nebraska Paul Semonin Company Kentucky Plaza Financial Services, LLC Kansas Plaza Mortgage Services, LLC Kansas Professional Referral Organization, Inc. Maryland Reece & Nichols Realtors Inc. Kansas The Referral Company Iowa RHL Referral Company, LLC Arizona Roy H. Long Realty Co., Inc. Arizona Select Relocation Services, Inc. Nebraska Semonin Mortgage Services, Inc. Kentucky Southwest Relocation, LLC Arizona Trinity Mortgage Partners, Inc. Georgia Carol Jones Company Missouri Carol Jones Properties, LTD Missouri Cendant Home Funding-Nebraska, LLC Delaware Edina Realty Mortgage, LLC Delaware HomeServices Lending, LLC Delaware Iowa Title Linn County II, LLC Iowa Jenny Pruitt Insurance Services, LLC Georgia Long Title Agency, LLC Arizona Meridian Title Services, LLC Georgia MidAmerican Home Services Mortgage, LLC Iowa Real Estate Links, LLC Illinois Service Mortgage Group, LLC Kentucky United Settlement Services, LC Iowa CE Electric UK Funding Company England and Wales Avonmouth CHP Limited England and Wales CalEnergy Gas (Holdings) Limited England and Wales CalEnergy Gas Limited England and Wales CalEnergy Gas (Australia) Limited England and Wales CalEnergy Gas (UK) Limited England and Wales CalEnergy Gas (Polska) Sp. z.o.o. Poland CalEnergy Gas (Pipelines) Limited England and Wales CalEnergy Power (Polska) SP. z.o.o. Poland CE Electric (Ireland) Ltd. Republic of Ireland CE Electric UK Holdings England and Wales CE Electric UK Ltd. England and Wales CE Insurance Services Isle of Man CE UK Gas Holdings Limited England and Wales Electra Brands Limited England and Wales Electralink Limited England and Wales Electricity Pensions Trustee Limited England and Wales Empire Oil & Gas NL Australia Integrated Utility Services Limited England and Wales Northern Electric plc England and Wales Northern Electric Distribution Limited England and Wales Northern Electric Finance plc England and Wales Northern Electric & Gas Limited England and Wales Northern Electric Generation Limited England and Wales Northern Electric Generation (TPL) Limited England and Wales Northern Electric Generation (Peaking) Limited England and Wales Northern Electric Genco Limited England and Wales Northern Electric Insurance Services Limited Isle of Man Northern Electric (Overseas Holdings) Limited England and Wales Northern Electric Properties Limited England and Wales Northern Electric Retail Limited England and Wales Northern Electric Supply Limited England and Wales Northern Infocom Limited England and Wales Northern Metering Services Limited England and Wales Northern Tracing & Collection Services Limited England and Wales Northern Transport Finance Limited England and Wales Ryhope Road Developments Ltd England and Wales Stamfordham Road Developments Ltd. England and Wales Kings Road Developments Limited England and Wales REC Collect England and Wales Selectusonline England and Wales Teesside Power Limited England and Wales Vehicle Lease and Service Limited England and Wales Viking Power Ltd. England and Wales Yorkshire Cayman Holding Limited Cayman Islands Yorkshire Electricity Distribution plc England and Wales Yorkshire Electricity Distribution Services Limited England and Wales Yorkshire Electricity Group plc England and Wales Yorkshire Holdings plc England and Wales Yorkshire Power Finance Limited Cayman Islands Yorkshire Power Finance 2 Limited Cayman Islands Yorkshire Power Group Limited England and Wales YPG Holdings LLC Delaware CE Generation, LLC Nebraska CalEnergy Operating Corporation Delaware California Energy Development Corporation Delaware California Energy Yuma Corporation Utah CE Salton Sea Inc. Delaware CE Texas Energy LLC Delaware CE Texas Gas LP Delaware CE Texas Fuel, LLC Delaware CE Texas Pipeline, LLC Delaware CE Texas Power, LLC Delaware CE Texas Resources, LLC Delaware CE Turbo LLC Delaware Conejo Energy Company California Del Ranch, L. P. California Desert Valley Company California Elmore, L.P. California Falcon Power Operating Company Texas Falcon Seaboard Oil Company Texas Falcon Seaboard Pipeline Corporation Texas Falcon Seaboard Power Corporation Texas Fish Lake Power LLC Delaware FSRI Holdings, Inc Texas Imperial Magma LLC Delaware Leathers, L.P. California Magma Land Company I Nevada Magma Power Company Nevada Niguel Energy Company California Power Resources, Ltd. Texas Salton Sea Brine Processing L. P. California Salton Sea Funding Corporation Delaware Salton Sea Power Company Nevada Salton Sea Power Generation L. P. California Salton Sea Power L.L.C. Delaware Salton Sea Royalty LLC Delaware San Felipe Energy Company California Saranac Energy Company, Inc. Delaware SECI Holdings, Inc. Delaware VPC Geothermal LLC Delaware Vulcan Power Company Nevada. Vulcan/BN Geothermal Power Company Nevada. Yuma Cogeneration Associates Arizona North Country Gas Pipeline Corporation New York Saranac Power Partners, L. P. Delaware American Pacific Finance Company Delaware Aurora 2000, LLC Delaware CalEnergy Capital Trust II Delaware CalEnergy Capital Trust III Delaware CalEnergy Company Inc. Delaware CalEnergy Generation Operating Company Delaware CalEnergy Holdings, Inc. Delaware CalEnergy International Ltd. Bermuda CalEnergy International Services, Inc. Delaware CalEnergy Investments C.V. Netherlands CalEnergy Minerals, LLC Delaware CalEnergy Minerals Development LLC Delaware CalEnergy Pacific Holdings Corp. Delaware CalEnergy U.K. Inc. Delaware CE Aurora I, Inc. Delaware CE Casecnan Ltd. Bermuda CE Cebu Geothermal Power Company, Inc. Philippines CE (Bermuda) Financing Ltd. Bermuda CE Electric, Inc. Delaware CE Electric (NY), Inc. Delaware CE Exploration Company Delaware CE Geothermal, Inc. Delaware CE Geothermal LLC Delaware CE Indonesia Geothermal, Inc. Delaware CE Insurance Services Limited Isle of Man CE International, Inc. Delaware CE International (Bermuda) Ltd Bermuda CE International Investments, Inc. Delaware CE Mahanagdong Ltd. Bermuda CE Mahanagdong II, Inc. Philippines CE Obsidian Energy LLC Delaware CE Philippines Ltd. Bermuda CE Philippines II, Inc. Philippines CE Power, Inc. Delaware CE Power LLC Delaware CE Resources LLC Delaware Cordova Energy Company, LLC Delaware Cordova Funding Corporation Delaware Fox Energy Company LLC Delaware Intermountain Geothermal Company Delaware Tongonan Power Investment, Inc. Philippines Magma Netherlands B.V. Netherlands MidAmerican Capital Trust I Delaware Northern Aurora, Inc. Delaware Quad Cities Energy Company Iowa Salton Sea Minerals Corp. Delaware Visayas Geothermal Power Company Philippines CE Casecnan Water and Energy Company, Inc. Philippines CE Luzon Geothermal Power Company, Inc. Philippines
American Pacific Finance Company II California Arizona Home Services LLC Arizona Big Springs Pipeline Company Texas Bioclean Fuels, Inc. Delaware CalEnergy BCF, Inc. Delaware CalEnergy Capital Trust I Delaware CalEnergy Capital Trust IV Delaware CalEnergy Capital Trust V Delaware CalEnergy Capital Trust VI Delaware CalEnergy Europe Ltd. England and Wales CalEnergy Imperial Valley Company, Inc. Delaware CalEnergy Power Ltd. England and Wales CalEnergy Power Ventures Ltd. England and Wales California Energy Management Company Delaware California Energy Retail Company, Inc. Delaware CBE Engineering Co. California CEABC Co. Delaware CEXYZ Co. Delaware CE Administrative Services, Inc. Delaware CE Alberta Bioclean, Inc. Delaware CE Argo Energy, Inc. Delaware CE Argo Power LLC Delaware CE Asia Ltd. Bermuda CE Bali, Ltd. Bermuda CE CIS-FSU, Inc. Delaware CE Indonesia Ltd. Bermuda CE Latin America Ltd Bermuda CE Overseas Ltd. Bermuda CE Singapore Ltd. Bermuda CE/TA LLC Delaware DCCO Inc. Minnesota Direct Energy Ltd. England and Wales Electric & Gas UK Ltd. England and Wales Electricity & Gas UK Ltd. England and Wales Electricity North East Ltd. England and Wales Electricity North Ltd. England and Wales Gas & Electricity UK Ltd. England and Wales Gas UK Ltd. England and Wales Gilbert/CBE Indonesia L.L.C. Nebraska Gilbert/CBE L. P. Nebraska Integrated Utility Services (UK) Ltd. England and Wales IPP Co. Delaware IPP Co. LLC Delaware InterCoast Sierra Power Company Delaware LW Technical (Northern) Ltd. England and Wales Magma Generating Company I Nevada Magma Generating Company II Nevada MidAmerican Energy Financing II Delaware Midwest Gas Company Iowa NEEB Ltd. England and Wales Neptune Power Ltd. England and Wales NorCon Holdings, Inc. Delaware NorCon Power Partners L.P. Delaware Norming Investments B.V. Netherlands North Eastern Electricity Ltd. England and Wales Northern Aurora Limited England and Wales Northern Billing and Customer Information Services Ltd. England and Wales Northern Cablevision Ltd. England and Wales Northern Cogen Ltd. England and Wales Northern Consolidated Power, Inc. Delaware Northern Electric Building Services Ltd. England and Wales Northern Electric Computer Services Ltd. England and Wales Northern Electric Consultants Ltd. England and Wales Northern Electric Contracting Ltd. England and Wales Northern Electric & Gas Distribution Ltd. England and Wales Northern Electric Generation (NPL) Limited England and Wales Northern Electric Generation (CPS) Limited England and Wales Northern Electric Investments Ltd. England and Wales Northern Electric Power Ltd. England and Wales Northern Electric Share Scheme Trustee Ltd. England and Wales Northern Electrics Ltd. England and Wales Northern Electric Telecom Limited England and Wales Northern Electric (TPL) Holdings Ltd. England and Wales Northern Electric Training Limited England and Wales Northern Electric Transport Limited England and Wales Northern Energy Distribution Ltd. England and Wales Northern Gas & Electricity Ltd. England and Wales Northern Gas & Electric Ltd. England and Wales Northern Gas Marketing Ltd. England and Wales Northern Power Distribution Ltd. England and Wales Northern Utilities Ltd. England and Wales Northern Utility Services Ltd. England and Wales NUSL International Ltd. England and Wales Ormoc Cebu Ltd. Bermuda Real Estate Referral Network, Inc. Nebraska Seal Sands Network Ltd. England and Wales Slupo I B.V. Netherlands UK Electric & Gas Ltd. England and Wales UK Electricity & Gas Ltd. England and Wales UK Gas & Electricity Ltd. England and Wales Yorkshire Electricity Distribution Holdings Ltd England and Wales