Item 1. Business.
General
MidAmerican Energy Holdings Company (“MEHC”) is a holding company owning subsidiaries (together with MEHC, the “Company”) that are principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The balance of MEHC’s common stock is owned by a private investor group comprised of Mr. Walter Scott, Jr. (along with family members and related entities), who is a member of MEHC’s Board of Directors, Mr. David L. Sokol, MEHC’s Chairman and Chief Executive Officer, and Mr. Gregory E. Abel, MEHC’s President and Chief Operating Officer. As of December 31, 2006, Berkshire Hathaway, Mr. Scott (along with family members and related entities), Mr. Sokol and Mr. Abel owned 87.8%, 11.0%, 0.9% and 0.3%, respectively, of MEHC’s voting common stock and held diluted ownership interests of 86.6%, 10.8%, 1.6% and 1.0%, respectively.
On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC’s common equity upon any requests authorized from time to time by MEHC’s Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250 million pursuant to one or more drawings authorized by MEHC’s Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to us in exchange for additional shares of MEHC’s common stock. The Berkshire Equity Commitment will expire on February 28, 2011.
The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (which includes the subsidiaries owning the Malitbog and Mahanagdong projects (collectively, the “Leyte Projects”) and the Casecnan Project), CalEnergy Generation-Domestic (which includes the subsidiaries owning interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Refer to Note 24 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional segment information regarding the Company’s platforms. Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second-largest residential real estate brokerage firm in the United States.
MEHC’s energy subsidiaries generate, transmit, store, distribute and supply energy. Approximately 89% of the Company’s operating income in 2006 was generated from rate-regulated businesses. As of December 31, 2006, MEHC’s electric and natural gas utility subsidiaries served approximately 6.2 million electricity customers and end users and approximately 0.7 million natural gas customers. MEHC’s natural gas pipeline subsidiaries operate interstate natural gas transmission systems that transported approximately 8% of the total natural gas consumed in the United States in 2006. These pipeline subsidiaries have approximately 17,600 miles of pipeline in operation and a design capacity of 6.7 billion cubic feet of natural gas per day. As of December 31, 2006, the Company had interests in approximately 16,400 net owned MW of power generation facilities in operation and under construction, including approximately 15,000 net owned MW in facilities that are part of the regulated asset base of its electric utility businesses and approximately 1,400 net owned MW in non-utility power generation facilities. Substantially all of the Company’s non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.
MEHC’s principal executive offices are located at 666 Grand Avenue, PO Box 657, Des Moines, Iowa 50306-0657 and its telephone number is (515) 242-4300. MEHC was initially incorporated in 1971 under the laws of the state of Delaware and reincorporated in 1999 in Iowa, at which time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.
In this annual report, references to “U.S. dollars,” “dollars,” “$” or “cents” are to the currency of the United States, references to “pounds sterling,” “£,” “sterling,” “pence” or “p” are to the currency of Great Britain and references to “pesos” are to the currency of the Philippines. References to kW means kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatt hours, kV means kilovolts, MMcf means million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic feet and Dth means decatherms or one million British thermal units.
PacifiCorp
On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp, a public utility company, from a wholly owned subsidiary of Scottish Power plc (“ScottishPower”) for a cash purchase price of $5,120.1 million, which includes direct transaction costs. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.
In the first quarter of 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments. Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of these regulatory commitments.
General
PacifiCorp serves approximately 1.7 million regulated retail electric customers in its service territories in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No single segment of the economy dominates the service territory, which mitigates PacifiCorp’s exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture, technology and manufacturing, with forest products, food processing and primary metals being the largest industrial sectors. In addition to retail sales, PacifiCorp sells electric energy to other utilities, marketers and municipalities. These sales are referred to as wholesale sales.
PacifiCorp’s regulated electric operations are conducted under franchise agreements, certificates, permits and licenses obtained from state and local authorities. The average term of these franchise agreements is approximately 30 years, although their terms range from five-years to indefinite.
On May 10, 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. Therefore, in the following pages, the nine-month period ended December 31, 2006, information covers the transition period beginning April 1, 2006 and ending December 31, 2006.
Electric Operations
Customers
The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the total number of retail customers (in millions) as of and for the nine months ended December 31 and as of and for the years ended March 31 were as follows:
The percentages of retail electric operating revenue, by jurisdiction, for the nine months ended December 31 and for the years ended March 31 were as follows:
Customer demand is typically highest in the summer across PacifiCorp’s service territory when air-conditioning and irrigation systems are heavily used. Customer demand also peaks in the winter months primarily due to heating requirements in the western portion of PacifiCorp’s service territory as well as the eastern portion due to other electricity demands.
For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems are contributing to increased summer peak growth.
Power and Fuel Supply
The estimated percentages of PacifiCorp’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases for the nine months ended December 31 and for the years ended March 31 were as follows:
The percentage of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of coal and natural gas, weather including precipitation and snowpack levels, environmental considerations and the market price of electricity.
As of December 31, 2006, PacifiCorp had an estimated 241.7 million tons of recoverable coal reserves in mines owned or leased by it. During the nine months ended December 31, 2006, these mines supplied 31.1% of PacifiCorp’s total coal requirements, compared to 32.3% during the year ended March 31, 2006 and 28.6% during the year ended March 31, 2005. The remaining coal requirements are acquired through other long- and short-term contracts. PacifiCorp’s mines are located adjacent to many of its coal-fired generating plants, which significantly reduces overall transportation costs included in fuel expense. In an effort to lower costs and obtain better quality coal, the Jim Bridger mine is in the process of developing an underground mine to access 57.0 million tons of PacifiCorp’s coal reserves. Underground mine developments and limited coal production began during the year ended March 31, 2005 and sustained operations are expected to begin by March 31, 2007.
Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. Recoverable coal reserves at December 31, 2006, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):
(1)
These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of 21.4%.
(2)
These coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.
(3)
These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. (“PMI”) and a subsidiary of Idaho Power Company. PMI, a subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The Jim Bridger mine is in the process of converting from surface operation to primarily underground operation, while currently continuing production at its surface operations.
PacifiCorp believes that the coal reserves available to the Craig, Huntington, Hunter and Jim Bridger plants, together with coal available under both long- and short-term contracts with external suppliers, will be substantially sufficient to provide these plants with fuel for their current economically useful lives. Recoverability by surface mining methods typically ranges from 90.0% to 95.0%. Recoverability by underground mining techniques ranges from 50.0% to 70.0%. Most of PacifiCorp’s coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended only with the consent of the lessor and require payment of rents and royalties.
PacifiCorp also uses natural gas as fuel for intermediate and peak demand electric generation. Oil and natural gas are also used for igniter fuel, and to fuel generation for transmission support and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp’s needs.
PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC with terms of 30 to 50 years. Several of PacifiCorp’s long-term operating licenses have expired. Hydroelectric facilities operating under expired licenses operate under temporary licenses issued by the FERC annually until new long-term operating licenses are issued. The amount of electricity PacifiCorp is able to generate from its hydroelectric facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, plant availability and restrictions imposed by oversight bodies due to competing water management objectives. When these factors are favorable, PacifiCorp can generate more electricity using its hydroelectric facilities. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.
In addition to its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail load and long-term wholesale obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long-term. PacifiCorp enters into wholesale purchase and sale transactions to balance its supply when actual retail loads are higher or lower than expected, subject to pricing and transmission constraints. Generation varies with the levels of outages, hydroelectric conditions and transmission constraints. Retail load varies with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own plants. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.
Historically, PacifiCorp has been able to purchase electricity from utilities in the Western United States for its own requirements. These purchases are conducted through PacifiCorp and third-party transmission systems, which connect with market hubs in the Pacific Northwest to provide access to primarily hydroelectric generation and in the Southwestern United States to provide access to primarily fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements.
PacifiCorp manages certain risks relating to its natural gas supply requirements and its wholesale transactions by entering into various financial derivative instruments, including forward purchases and sales, futures, swaps and options. Refer to Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a discussion of commodity price risk and derivative instruments.
The following table sets out certain information concerning PacifiCorp’s power generating facilities as of December 31, 2006:
(1)
Facility Net Capacity (MW) represents the total capability of a generating unit as demonstrated by actual operating experience, or test experience, less power generated and used for auxiliaries and other station uses, and is determined using average annual temperatures. Net MW Owned indicates current legal ownership.
(2)
Facility Net Capacity (MW) and Net MW Owned for projects under construction each represent the estimated nameplate ratings. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer. The expected in-service dates for the Lake Side and Marengo Plants are June 2007 and August 2007, respectively.
Future Generation
As required by state regulators, PacifiCorp uses Integrated Resource Plans (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. Each state commission that has IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines at the time the IRP is filed. If the IRP is found to be adequate, then it is formally “acknowledged.” The IRP can then be used as evidence by parties in rate-making or other regulatory proceedings. PacifiCorp files an IRP on a biennial basis and expects to file its 2006 plan in early 2007.
In November 2005, PacifiCorp released an update to its 2004 IRP. The updated IRP identified a need for approximately 2,113 MW of additional resources by summer 2014, to be met with a combination of thermal generation (1,936 MW) and load-control programs (177 MW). PacifiCorp also planned to implement energy conservation programs of 450 MW, to continue to seek procurement of 1,400 MW of economic renewable resources and to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources.
In July 2006, PacifiCorp filed its 2012 draft request for proposals under its updated 2004 IRP with the Utah Public Service Commission (“UPSC”) and the Oregon Public Utility Commission (“OPUC”). The draft request for proposals is for generation resources of between 840 MW and 915 MW to be available in 2012 and 2013. The scope of this draft request for proposals is focused on resources capable of delivering energy and capacity in or to PacifiCorp’s network transmission system in PacifiCorp’s eastern service territory. All transaction and resource decisions will be evaluated on a comparable least-cost and risk-balanced approach. In response to issues and concerns from stakeholders, PacifiCorp filed a revised version of the 2012 draft request for proposals in October 2006.
In January 2007, the OPUC issued an order denying the 2012 request for proposals. This denial does not preclude the issuance of the request for proposals. PacifiCorp is analyzing the order and will develop its strategy for its next steps. In December 2006, the UPSC issued an order suggesting modifications to the request for proposals. In February 2007, PacifiCorp filed the 2012 request for proposals in Utah for final approval.
Transmission and Distribution
PacifiCorp operates one control area on the western portion of its service territory and one control area on the eastern portion of its service territory. A control area is a geographic area with electric systems that control generation to maintain schedules with other control areas and ensure reliable operations. In operating the control areas, PacifiCorp is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the control area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries over its transmission system in accordance with FERC requirements.
PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electric Coordinating Council. PacifiCorp’s transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements.
PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s Open Access Transmission Tariff (“OATT”). In accordance with the OATT, PacifiCorp offers several transmission services to wholesale customers:
·
Network transmission service (guaranteed service that integrates generating resources to serve retail loads);
·
Long- and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt points); and
·
Non-firm point-to-point service (“as available” service with fixed delivery and receipt points).
These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from the generating and marketing business in accordance with the FERC Standards of Conduct. Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in retail rates approved by state regulatory commissions.
The electric transmission system of PacifiCorp as of December 31, 2006, included approximately 15,800 miles of transmission lines. As of December 31, 2006, PacifiCorp owned approximately 900 substations.
MidAmerican Energy
General
MidAmerican Energy, an indirect wholly owned subsidiary of MEHC, is a public utility company, headquartered in Iowa, which serves approximately 0.7 million regulated retail electric customers and approximately 0.7 million regulated retail and transportation natural gas customers. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a number of adjacent communities and areas. It also distributes natural gas at retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of adjacent communities and areas. Additionally, MidAmerican Energy transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities. These sales are referred to as wholesale sales.
MidAmerican Energy’s regulated electric and gas operations are conducted under franchise agreements, certificates, permits and licenses obtained from state and local authorities. The franchise agreements, which represent the most important of these government authorizations, have various expiration dates but are typically for 25-year terms.
MidAmerican Energy has a diverse customer base consisting of residential, agricultural, and a variety of commercial and industrial customer groups. Among the primary industries served by MidAmerican Energy are those that 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.
MidAmerican Energy also has non-regulated business activities in addition to its traditional regulated electric and natural gas services, including unregulated sales of electricity and natural gas in Illinois, Michigan, Ohio, Maryland and the District of Columbia.
MidAmerican Energy’s operating revenues were derived from the following business activities during the years ended December 31:
Electric Operations
Customers
The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the total number of retail customers (in millions) as of and for the years ended December 31 were as follows:
The percentages of retail electric operating revenue, by jurisdiction, for the years ended December 31 were as follows:
There are seasonal variations in MidAmerican Energy's electric business that are principally related to the use of electricity for air conditioning. Typically, 35-40% of MidAmerican Energy's regulated electric revenues are reported in the months of June, July, August and September.
The annual hourly peak demand on MidAmerican Energy’s electric system usually occurs as a result of air conditioning use during the cooling season. On July 31, 2006, retail customer usage of electricity caused a new record hourly peak demand of 4,136 MW on MidAmerican Energy’s electric system, an increase of 137 MW from the previous record set in 2005.
Power and Fuel Supply
The estimated percentages of MidAmerican Energy’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases for the years ended December 31 were as follows
The share of MidAmerican Energy’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of fuels, weather, environmental considerations and the market price of electricity.
MidAmerican Energy is exposed to fluctuations in energy costs relating to retail sales in Iowa and Illinois as it does not have a fuel adjustment clause. Under its South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in the cost of purchased energy and all fuels used for retail electric generation through a fuel cost adjustment clause. In November 2006, the Illinois Commerce Commission (“ICC”) approved a proposal to eliminate MidAmerican Energy’s monthly fuel adjustment clause. Base rates were adjusted to include recoveries at average 2004/2005 cost levels on January 1, 2007. Rate case approval required for any base rate changes. MidAmerican Energy may not petition for reinstatement of the Illinois fuel adjustment clause for five years.
All of the coal-fired generating stations operated by MidAmerican Energy are fueled by low-sulfur coal from the Powder River Basin in Wyoming. MidAmerican Energy’s coal supply portfolio includes multiple suppliers and mines under agreements of varying terms and quantities. MidAmerican Energy’s coal supply portfolio has 96% of its 2007 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market, looking for opportunities to enhance its coal supply portfolio. Well-publicized operational delays in rail transportation out of the Powder River Basin during 2005 and 2006 have resulted in the reduction of coal inventories to suboptimum levels. MidAmerican Energy believes the transportation issues have been largely resolved and that its coal inventories will be restored to their target ranges during 2007.
MidAmerican Energy has a long-term coal transportation agreement with Union Pacific Railroad Company (“Union Pacific”). Under this agreement, Union Pacific delivers contractually specified amounts of coal directly to MidAmerican Energy’s Neal and Council Bluffs Energy Centers and to an interchange point with the Iowa, Chicago & Eastern Railroad Corporation for delivery to the Louisa and Riverside Energy Centers. MidAmerican Energy has the ability to use The Burlington Northern and Santa Fe Railway Company for delivery of a small amount of coal to the Council Bluffs, Louisa and Riverside Energy Centers should the need arise.
MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy’s needs. MidAmerican Energy manages a portion of its natural gas supply requirements by entering into various financial derivative instruments, including forward purchases and sales, futures, swaps and options. Refer to Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a discussion of commodity price risk and derivative instruments.
MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and (“Quad Cities Station”), a nuclear power plant. Exelon Generation Company, LLC (“Exelon Generation”), the 75% joint owner and the operator of Quad Cities Station, is a subsidiary of Exelon Corporation. Approximately one-third of the nuclear fuel assemblies in the core at Quad Cities Station are replaced every months. MidAmerican Energy has been advised by Exelon Generation that its uranium requirements for Quad Cities Station through 2009 and part of the requirements through 2015 can be met under existing supplies or commitments. Additionally, under existing supplies and commitments, uranium conversion requirements can be met through 2009 and part of 2010 and enrichment requirements can be met through 2011. Commitments for fuel fabrication have been obtained for the next eight years. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate that it will have difficulty in contracting for uranium, conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during this time.
The following table sets out certain information concerning MidAmerican Energy’s power generating facilities as of December 31, 2006:
(1)
Facility Net Capacity (MW) represents total plant accredited net generating capacity from the summer 2006 as approved by the Mid-Continent Area Power Pool (“MAPP”), except for wind-powered generation facilities, which are nameplate ratings. Net MW Owned indicates MidAmerican Energy’s ownership of Facility Net Capacity. The 2006 summer accreditation of the Intrepid and Century facilities totaled 59 MW and is considerably less than the nameplate ratings due to the varying nature of wind. Additionally, the Victory wind-powered generation facility was placed in service in the fourth quarter of 2006, which was after the 2006 summer accreditation.
(2)
Facility Net Capacity (MW) and Net MW Owned represents the expected accredited generating capacity for the coal-fired generation project under construction (MW) and the estimated nameplate ratings (MW) for wind-powered generation projects under construction. The expected in-service date for the Council Bluffs Unit No. 4 facility is June 2007 and the Pomeroy project is planned to be completed by the end of 2007.
Future Generation
On April 18, 2006, the Iowa Utilities Board (“IUB”) approved a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate (“OCA”) regarding rate-making principles for up to 545 MW (nameplate ratings) of wind-powered generation capacity in Iowa to be installed in 2006 and 2007. In the second half of 2006, MidAmerican Energy placed in service 99 MW (nameplate ratings) of wind-powered generation facilities and is constructing the 123 MW (nameplate ratings) Pomeroy wind-powered generation project which is planned to be completed by the end of 2007. MidAmerican Energy continues to pursue additional cost effective wind-powered generation.
Transmission and Distribution
MidAmerican Energy is interconnected with utilities in Iowa and neighboring states. MidAmerican Energy is also a party to an electric generation reserve sharing pool and regional transmission group administered by 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 performs functions including administration of its short-term regional OATT, coordination of regional planning and operations, and operation of the generation reserve sharing pool.
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 has adequate capacity to deliver energy to MidAmerican Energy’s distribution system and to export and import energy with other interconnected systems. The electric transmission system of MidAmerican Energy at December 31, 2006, included approximately 1,000 miles of 345-kV lines and approximately 1,100 miles of 161-kV lines. MidAmerican Energy's electric distribution system included approximately 400 substations at December 31, 2006.
Natural Gas Operations
MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in the Midwest. MidAmerican Energy purchases natural gas from various suppliers, transports it from the production areas to its service territory under contracts with interstate pipelines, stores it in various storage facilities to manage fluctuations in system demand and seasonal pricing, and delivers it to customers through its distribution system.
MidAmerican Energy sells natural gas and transportation services to end-use customers and natural gas to other utilities, marketers and municipalities. MidAmerican Energy also transports through its distribution system natural gas purchased independently by a number of end-use customers. During 2006, 47.2% of total natural gas delivered through MidAmerican Energy’s system for end use customers was under natural gas transportation service.
There are seasonal variations in MidAmerican Energy’s natural gas business that are principally due to the use of natural gas for heating. Typically, 45-55% of MidAmerican Energy’s regulated natural gas revenue is reported in the months of January, February, March and December.
The percentages of regulated natural gas revenue, excluding transportation throughput, by class of customer, for the years ended December 31 were as follows:
(1)
Small and large general service customers are classified primarily based on the nature of their business and natural gas usage. Small general service customers are business customers whose natural gas usage is principally for heating. Large general service customers are business customers whose principal natural gas usage is for their manufacturing processes.
(2)
Wholesale generally includes other utilities, marketers and municipalities to whom natural gas is sold at wholesale for eventual resale to ultimate end-use customers.
The percentages of regulated natural gas revenue, excluding transportation throughput, by jurisdiction, for the years ended December 31 were as follows:
MidAmerican Energy purchases natural gas supplies from producers and third-party marketers. To enhance system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the natural gas supplies. MidAmerican Energy attempts to optimize the value of its regulated assets by engaging in wholesale sales transactions. IUB and South Dakota Public Utilities Commission (“SDPUC”) rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on wholesale sales of natural gas, with the remaining 50% being returned to customers through the purchased gas adjustment clauses discussed below.
MidAmerican Energy has rights to firm pipeline capacity to transport natural gas to its service territory through direct interconnects to the pipeline systems of Northern Natural Gas (an affiliate company), Natural Gas Pipeline Company of America (“NGPL”), Northern Border Pipeline Company (“Northern Border”) and ANR Pipeline Company (“ANR”). At times, the capacity available through MidAmerican Energy’s firm capacity portfolio may exceed the demand on MidAmerican Energy’s distribution system. Firm capacity in excess of MidAmerican Energy’s system needs can be resold to other companies to achieve optimum use of the available capacity. Past IUB and SDPUC rulings have allowed MidAmerican Energy to retain 30% of the respective jurisdictional margins earned on the resold capacity, with the remaining 70% being returned to customers through the purchased gas adjustment clauses.
MidAmerican Energy is allowed to recover its cost of natural gas from all of its regulated natural gas customers through purchased gas adjustment clauses. Accordingly, as long as MidAmerican Energy is prudent in its procurement practices, MidAmerican Energy’s regulated natural gas customers retain the risk associated with the market price of natural gas. MidAmerican Energy uses several strategies to reduce the market price risk for its natural gas customers, including the use of storage gas and peak-shaving facilities, sharing arrangements to share savings and costs with customers and short-term and long-term financial and physical gas purchase agreements.
MidAmerican Energy utilizes leased gas storage to meet peak day requirements and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season. In addition, MidAmerican Energy also utilizes three liquefied natural gas (“LNG”) plants and two propane-air plants to meet peak day demands in the winter. The storage and peak shaving facilities reduce MidAmerican Energy’s dependence on natural gas purchases during the volatile winter heating season. MidAmerican Energy can deliver approximately 50% of its design day sales requirements from its storage and peak shaving supply sources.
In 1995, the IUB gave initial approval of MidAmerican Energy’s Incentive Gas Supply Procurement Program. In December 2006, the IUB extended the program through October 31, 2010. Under the program, as amended, MidAmerican Energy is required to file with the IUB every six months a comparison of its natural gas procurement costs to a reference price. If MidAmerican Energy’s cost of natural 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 currently in effect in South Dakota through October 31, 2010. Since the implementation of the program, MidAmerican Energy has successfully achieved and shared savings with its natural gas customers.
On February 2, 1996, MidAmerican Energy had its highest peak-day delivery of 1,143,026 Dth. This peak-day delivery consisted of 88% traditional sales service and 12% transportation service of customer-owned gas. As of March 1, 2007, MidAmerican Energy’s 2006/2007 winter heating season peak-day delivery of 1,071,380 Dth was reached on February 5, 2007. This peak-day delivery included 68% traditional sales service and 32% transportation service.
Natural gas property consists primarily of natural gas mains and services pipelines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The gas distribution facilities of MidAmerican Energy at December 31, 2006, included approximately 22,000 miles of gas mains and services pipelines.
Interstate Pipeline Companies
Northern Natural Gas
Northern Natural Gas, an indirect wholly owned subsidiary of MEHC acquired in 2002, owns one of the largest interstate natural gas pipeline systems in the United States. It reaches from Texas to Michigan’s Upper Peninsula and is engaged in the transmission and storage of natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas owns and operates approximately 15,900 miles of natural gas pipelines, consisting of approximately 6,900 miles of mainline transmission pipelines and approximately 9,000 miles of branch and lateral pipelines, with a Market Area design capacity of 4.9 Bcf per day. Based on a review of relevant industry data, the Northern Natural Gas system is believed to be the largest single pipeline in the United States as measured by pipeline miles and the eighth-largest as measured by throughput. Northern Natural Gas’ revenue is derived from the interstate transportation and storage of natural gas for third parties. Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. Northern Natural Gas’ transportation and storage operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow it an opportunity to recover its costs and generate a regulated return on equity.
Northern Natural Gas’ pipeline system, which is interconnected with many interstate and intrastate pipelines in the national grid system, consists of two distinct but operationally integrated markets. Its traditional end-use and distribution market area is at the northern part of the system, including delivery points in Michigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which Northern Natural Gas refers to as the Market Area. Its natural gas supply and delivery service area is at the southern part of the system, including Kansas, Oklahoma, Texas and New Mexico, which Northern Natural Gas refers to as the Field Area.
Northern Natural Gas’ pipeline system provides its customers access to natural gas from key production areas, including the Hugoton, Permian, Anadarko and Rocky Mountain basins in its Field Area and, through interconnections, the Rocky Mountain and Canadian basins in our Market Area. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points.
Northern Natural Gas transports natural gas primarily to end-user and local distribution markets in the Market Area. In 2006, 68% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer transportation contracts. Its market area customers consist of local distribution companies (“LDCs”), utilities, other pipeline companies, gas marketers and end-users. Northern Natural Gas directly serves approximately 75 utilities and LDCs, with six large LDCs accounting for the majority of its Market Area revenues in 2006. In turn, these large LDCs serve numerous small communities. In 2006, over 86% of Northern Natural Gas’ transportation and storage revenue for the Field and Market Areas was generated from reservation charges under firm transportation and storage contracts and 73% of that revenue was from LDCs.
A majority of Northern Natural Gas’ capacity in the Market Area is dedicated to Market Area customers under firm transportation contracts. As of December 31, 2006, approximately 61% of Northern Natural Gas’ contracted firm transportation capacity in the Market Area is contracted beyond 2008, and approximately 39% is contracted beyond 2015.
As part of Northern Natural Gas’ Northern Lights project, Northern Natural Gas has applied to the FERC for facilities to deliver approximately 440,000 Dthd throughout its Market Area. This load is concentrated primarily in the Twin Cities area of Minnesota. Northern Lights currently consists of three phases. Almost all of the service for these three phases is expected to begin by November 1, 2007, although some smaller projects are scheduled to be in service by June 2007 and November 2008. Phase 1 of Northern Lights consists of 374,225 Dthd, representing $26.5 million of annual revenue. Phases 2 and 3 consist of service primarily for new ethanol plants in Northern Natural Gas’ Market Area. Northern Natural Gas is geographically well situated to serve the expanding ethanol industry and now serve approximately one-third of the nation’s ethanol manufacturing capacity. Entitlement for Phases 2 and 3 of the Northern Lights project is approximately 44,200 Dthd and 24,000 Dthd, respectively, which are expected to generate annual revenues of $5.1 million and $2.7 million, respectively. All of the Northern Lights entitlement except 31,400 Dthd in Phase 1 and 6,200 Dthd in Phase 3 is associated with new service. All three phases of Northern Lights are entirely supported by executed contracts, the majority of which (87% by volume) have terms ranging from five to twenty years. In total, the current Northern Lights expansion projects are expected to require approximately $156.0 million in capital expenditures.
In the Field Area, customers holding transportation capacity consist of LDCs, marketers, producers, and end-users. The majority of Northern Natural Gas’ Field Area firm transportation is currently conducted under long-term firm transportation contracts that expire on October 31, 2007, with such volumes supplemented by volumes transported on an interruptible basis. The majority of this entitlement is expected to be recontracted as of November 1, 2007 by LDCs, marketers, or producers, although in the near term the contracts may be for shorter terms. Northern Natural Gas expects recontracting to occur since Market Area customers are expected to need to purchase gas connected to its Field Area in order to meet their growing demand levels. Market Area demand cannot presently be met without the purchase of supplies from the Field Area. In 2006, 21% of Northern Natural Gas’ transportation and storage revenue was generated from Field Area customer transportation contracts.
Northern Natural Gas’ storage services are provided through the operation of one underground storage field in Iowa, two underground storage facilities in Kansas and one LNG storage peaking unit each in Garner, Iowa and Wrenshall, Minnesota. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service cycle capacity of approximately 65 Bcf and over 1.9 Bcf per day of FERC-certificated peak delivery capability. These storage facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and provide services to customers to meet their winter peaking and year-round loadswing requirements. In 2006, 11% of Northern Natural Gas’ transportation and storage revenue was generated from storage services.
Northern Natural Gas’ system experiences significant seasonal swings in demand, with the highest demand occurring during the months of November through March. This seasonality provides Northern Natural Gas opportunities to deliver value-added services, such as firm and interruptible storage services, as well as no-notice services, particularly during the lower demand months. Because of its location and multiple interconnections with other interstate and intrastate pipelines, Northern Natural Gas is able to access natural gas from both traditional production areas, such as the Hugoton, Permian and Anadarko basins, and growing supply areas, such as the Rocky Mountains, through Trailblazer Pipeline Company, Pony Express Pipeline, Cheyenne Plains Pipeline and Colorado Interstate Gas Pipeline Company (“Colorado Interstate”), as well as from Canadian production areas through Northern Border, Great Lakes Gas Transmission Limited Partnership (“Great Lakes”) and Viking Gas Transmission Company (“Viking”). As a result of Northern Natural Gas’ geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas augments its steady end-user and LDC revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnections.
Kern River
Kern River, an indirect wholly owned subsidiary of MEHC acquired in 2002, owns an interstate natural gas transportation pipeline system consisting of approximately 1,700 miles of pipeline, with an approximate design capacity of 1,755,575 Dth per day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. On May 1, 2003, Kern River placed into service an approximately 700-mile expansion project (the “2003 Expansion Project”), which increased the design capacity of Kern River’s pipeline system by 885,575 Dth per day to its current capacity. Except for quantities of natural gas owned for system operations, Kern River does not own the natural gas that is transported through its system. Kern River’s transportation operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow it an opportunity to recover its costs and generate a regulated return on equity.
Kern River’s pipeline consists of two sections: the mainline section and the common facilities. Kern River owns the entire mainline section, which extends from the pipeline’s point of origination near Opal, Wyoming through the Central Rocky Mountains area into Daggett, California. The mainline section consists of the original approximately 700 miles of 36-inch diameter pipeline, approximately miles of 36-inch diameter loop pipeline related to the 2003 Expansion Project and approximately 100 miles of various laterals that connect to the mainline.
The common facilities consist of an approximately 200-mile section of original pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California and an additional approximately 100 miles related to the 2003 Expansion Project. The common facilities are jointly owned by Kern River (approximately 76.8% as of December 31, 2006) and Mojave Pipeline Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation, (approximately 23.2% as of December 31, 2006), as tenants-in-common. Kern River’s ownership percentage in the common facilities will increase or decrease pursuant to the capital contributions made by the respective joint owners. Kern River has exclusive rights to approximately 1,570,500 Dth per day of the common facilities’ capacity, and Mojave has exclusive rights to 400,000 Dth per day of capacity. Operation and maintenance of the common facilities are the responsibility of Mojave Pipeline Operating Company, an affiliate of Mojave.
As of December 31, 2006, Kern River had long-term firm natural gas transportation service agreements for 1,661,575 Dth per day of capacity. Pursuant to these agreements, the pipeline receives natural gas on behalf of shippers at designated receipt points, transports the natural gas on a firm basis up to each shipper’s maximum daily quantity and delivers thermally equivalent quantities of natural gas at designated delivery points. Each shipper pays Kern River the aggregate amount specified in its long-term firm natural gas transportation service agreement and Kern River’s tariff, with such amount consisting primarily of a fixed monthly reservation fee based on each shipper’s maximum daily quantity and a commodity charge based on the actual amount of natural gas transported.
These long-term firm natural gas transportation service agreements expire between September 30, 2011, and April 30, 2018, and have a weighted-average remaining contract term of nearly ten years. Shippers on the pipeline include major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies, and natural gas distribution utilities which provide services in Utah, Nevada and California. As of December 31, 2006, over 95% of the firm capacity has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah. Kern River has an additional 94,000 Dth per day of available long-term firm capacity that was sold to a number of shippers at a discounted daily demand rate for the period of April 2006 through September 2008 on a short-term basis. Kern River will continue to market this capacity or use it for any future expansion needs for any period beyond September 2008.
Calpine Corp., including Calpine Energy Services, L.P. (“Calpine”), filed for Chapter 11 bankruptcy protection on December 20, 2005. Calpine holds two 50,000 Dth per day incremental 2003 Expansion Project firm transportation contracts that have termination dates of April 30, 2018. Pursuant to Kern River’s credit requirements, Calpine provided approximately $19 million as cash security for the transportation contracts, with approximately $3 million being applied against Calpine’s pre-petition invoices. Post-petition, to date, Calpine has continued to nominate on its transportation contracts and pay its post-petition invoices; however, Calpine has not yet determined whether it will assume or reject the transportation contracts.
Kern River and Northern Natural Gas Competition
Pipelines compete on the basis of cost (including both transportation costs and the relative costs of the natural gas they transport), flexibility, reliability of service and overall customer service. Industrial end-users often have the ability to choose from alternative fuel sources, such as fuel oil and coal, in addition to natural gas. Natural gas competes with other forms of energy, including electricity, coal and fuel oil, primarily on the basis of price. Legislation and governmental regulations, the weather, the futures market, production costs and other factors beyond the control of Kern River and Northern Natural Gas influence the price of natural gas.
Historically, Northern Natural Gas has been able to provide competitively priced services because of its access to a variety of relatively low cost supply basins, its cost control measures and its relatively high load factor throughput, which lowers the per unit cost of transportation. To date, Northern Natural Gas has avoided any significant pipeline system bypasses. In recent years, Northern Natural Gas has retained and signed long-term contracts with customers such as CenterPoint, Xcel Energy and Metropolitan Utilities District, which in some cases, because of competition, resulted in lower reservation charges relative to the contracts being replaced.
Northern Natural Gas’ major competitors in the Market Area include ANR, Northern Border and NGPL. Other competitors of Northern Natural Gas include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of pipeline companies. Particularly in the Field Area, a significant amount of Northern Natural Gas’ capacity is used for transportation services provided on a short-term or interruptible basis. Historically in summer months, Northern Natural Gas’ Market Area customers often release significant amounts of their unused firm entitlement to other shippers. This released entitlement competes with Northern Natural Gas’ short-term and interruptible services. Northern Natural Gas attempts to maintain its competitive position through selective discounting of firm transportation to keep delivered natural gas prices in line with delivered prices for alternative fuels and by using flexible short-term and interruptible transportation services that are contracted for on an as-needed basis.
Although it needs to compete aggressively to retain and build load, Northern Natural Gas believes that current and anticipated changes in its competitive environment have created opportunities to serve its existing customers more efficiently and to meet certain growing supply needs. While peak day delivery growth of LDCs is driven by population growth and alternative fuel replacement, new baseload or off-peak demand growth is being driven primarily by power and ethanol plant expansion. This baseload or off-peak demand growth is important to Northern Natural Gas as this demand provides revenues year round and allows Northern Natural Gas to utilize facilities on a year-round basis. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to the construction of new power and ethanol plants.
Kern River competes with various interstate pipelines and its shippers in order to market any unutilized or unsubscribed capacity serving the southern California, Las Vegas, Nevada and Salt Lake City, Utah market areas. Kern River provides its customers with supply diversity through pipeline interconnections with Northwest Pipeline, Colorado Interstate, Overland Trail Pipeline, Questar Pipeline Company and Questar Overthrust Pipeline Company. These interconnections, in addition to the direct interconnections to natural gas processing facilities, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.
Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin to end users in the California market. This enables direct connect customers to avoid paying a “rate stack” (i.e., additional transportation costs attributable to the movement from one or more interstate pipeline systems to an intrastate system within California). Kern River believes that its historic levelized rate structure and access to upstream pipelines/storage facilities and to economic Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it has an advantage relative to other competing interstate pipelines because its relatively new pipeline can be economically expanded and will require significantly less capital expenditures to comply with the Pipeline Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s levelized rate structure has been challenged in its 2004 general rate case. Certain parties have advocated converting the system to a traditional declining rate base rate structure. Kern River’s favorable market position is tied to the availability and relatively favorable price of gas reserves in the Rocky Mountain area, an area that in recent years has attracted considerable expansion of pipeline capacity serving markets other than California and Nevada. In addition, Kern River’s 2003 Expansion Project relies substantially on long-term transportation service agreements with several electric generation companies, which face significant competitive and financial pressures due to, among other things, the financial stress of energy markets and the build-up of electric generation capacity in California and other markets. This condition is improving as demand for electric generation in Kern River’s market territory increases and older, less efficient power plants in the region are retired.
In 2006, Northern Natural Gas had two customers who each accounted for greater than 10% of its revenue and its six largest customers accounted for 56.5% of its transportation and storage revenues. Northern Natural Gas has agreements to retain the vast majority of its two largest customers’ volumes through at least 2017. Kern River also had two customers who each accounted for greater than 10% of its revenue. The loss of any of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas’ and Kern River’s respective businesses.
CE Electric UK
General
CE Electric UK, an indirect wholly owned subsidiary of MEHC, is a holding company which owns, primarily, two companies that distribute electricity in Great Britain, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity operate in the north-east of England from North Northumberland through Durham, Tyne and Wear, Tees Valley and Yorkshire to North Lincolnshire, an area covering approximately 10,000 square miles, and serves approximately 3.8 million end users.
The principal function of Northern Electric and Yorkshire Electricity is to build and maintain the electricity distribution network to serve the end user. The service territory geographically features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a wide range of customer base from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough and Leeds.
The price controlled revenues of the regulated distribution companies are agreed with the regulator based around 5-year price control periods, with the current price control period commencing April 1, 2005.
In addition to building and maintaining the electricity distribution network, CE Electric UK also owns a utility contracting business and a gas exploration business.
Electricity Distribution
Northern Electric’s and Yorkshire Electricity’s operations consist primarily of the distribution of electricity in the Great Britain. Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to their customers’ premises using their network of transformers, switchgear and distribution lines and cables. Substantially all of the end users in Northern Electric’s and Yorkshire Electricity’s distribution service areas are connected to the Northern Electric and Yorkshire Electricity networks and electricity can only be delivered through their distribution system, thus providing Northern Electric and Yorkshire Electricity with distribution volume that is relatively stable from year to year. Northern Electric and Yorkshire Electricity charge fees for the use of the distribution system to the suppliers of electricity. The suppliers, which purchase electricity from generators and sell the electricity to end-user customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to an industry standard “Distribution Connection and Use of System Agreement,” which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution service areas. One such supplier, RWE Npower PLC and certain of its affiliates, represented approximately 42% of the total combined distribution revenues of Northern Electric and Yorkshire Electricity in 2006. The fees that may be charged by Northern Electric and Yorkshire Electricity for use of their distribution systems are controlled by a formula prescribed by the United Kingdom’s electricity regulatory body that limits increases (and may require decreases) based upon the rate of inflation, other factors and other regulatory action.
Electricity distributed (in GWh) to end users and the total number of end users (in millions) as of and for the years ended December 31 were as follows:
As of December 31, 2006, Northern Electric’s and Yorkshire Electricity’s electricity distribution network (excluding service connections to consumers) on a combined basis included approximately 34,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition, as of December 31, 2006, Northern Electric’s and Yorkshire Electricity’s distribution facilities included approximately 700 major substations. Substantially all substations are owned, with the balance being leased from third parties and mostly having remaining terms of at least 10 years.
Utility Services
Integrated Utility Services Limited, CE Electric UK’s indirect wholly-owned subsidiary, is an engineering contracting company providing electrical infrastructure contracting services to third parties.
Gas Exploration and Production
CalEnergy Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly owned subsidiary, is a gas exploration and production company that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and Poland. Its upstream gas business consists of full or partial ownership in exploration, construction and production projects, which, if successful, result in the sale of gas and other hydrocarbon products to third parties.
CalEnergy Generation-Foreign
The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Leyte Projects, which are two geothermal power plants located on the island of Leyte in the Philippines, and a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines (the “Casecnan Project”).
The following table sets out certain information concerning CalEnergy Generation-Foreign’s non-utility power projects in operation as of December 31, 2006:
(1)
Separate sovereign performance undertakings of the Republic of the Philippines (“ROP”) support PNOC-Energy Development Corporation’s (“PNOC-EDC”) obligations for the Leyte Projects. The ROP has also provided a performance undertaking under which National Irrigation Administration (“NIA”)’s obligations under the Casecnan Project agreement, as supplemented by the Supplemental Agreement, are guaranteed by the full faith and credit of the ROP. NIA also pays CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) for the delivery of water and electricity by CE Casecnan. All projects carry political risk insurance.
(2)
Contract Capacity (MW) represents the contract capacity for the facility. Net MW Owned indicates legal ownership of Contract Capacity.
(3)
Net MW Owned of approximately 150 MW is subject to repurchase rights of up to 15% of the project by an initial minority shareholder and a dispute with the other initial minority shareholder regarding an additional 15% of the project. Refer to Item 3. Legal Proceedings for additional information.
PNOC-EDC’s and NIA’s obligations under the project agreements are substantially denominated in U.S. dollars and are the Leyte Projects’ and Casecnan Project’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreements and any material failure of the ROP to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations of the relevant project company, including obligations pertaining to the outstanding project debt.
On July 25, 2007, the Mahanagdong and the Malitbog Projects’ separate 10-year cooperation periods will end and the Mahanagdong and the Malitbog Projects will each be transferred by the Company to PNOC-EDC at no cost on an “as-is” basis. The Mahanagdong and the Malitbog Projects take geothermal steam and fluid, provided at no cost by PNOC-EDC, and convert their thermal energy into electrical energy which is sold to PNOC-EDC, which in turn sells the power to the National Power Corporation (“NPC”), the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines, for distribution on the islands of Cebu and Luzon. Payments under the Mahanagdong and Malitbog agreements are primarily denominated in U.S. dollars, or computed in U.S. dollars and paid in pesos at the then-current exchange rate.
The Casecnan Project is a combined irrigation and hydroelectric power generation project. CE Casecnan owns and operates the Casecnan Project under the terms of the Project Agreement between CE Casecnan and NIA, which was modified by a Supplemental Agreement between CE Casecnan and NIA effective on October 15, 2003 (the “Supplemental Agreement”). CE Casecnan will own and operate the project for a 20-year cooperation period which commenced on December 11, 2001, the start of the Casecnan Project’s commercial operations, after which ownership and operation of the project will be transferred to NIA at no cost on an “as-is” basis. The Casecnan Project is dependent upon sufficient rainfall to generate electricity and deliver water. Rainfall varies within the year and from year to year, which is outside the control of CE Casecnan, and will impact the amounts of electricity generated and water delivered by the Casecnan Project. Rainfall has historically been highest from June through December and lowest from January through May. The contractual terms for water delivery fees and variable energy fees (described below) can produce significant variability in revenue between reporting periods.
Under the Supplemental Agreement, CE Casecnan is paid a fee for the delivery of water and a fee for the generation of electricity. With respect to water deliveries, the water delivery fees are recorded each month pro-rated to a minimum threshold of water delivered per month until such minimum threshold has been reached for the contract year. Subsequent water delivery fees within the contract year are based on actual water delivered. With respect to electricity, CE Casecnan is paid a guaranteed energy delivery fee each month. The guaranteed energy delivery fee is payable regardless of the amount of energy actually generated and delivered by CE Casecnan in any month. NIA also pays CE Casecnan an excess energy delivery fee, which is a variable amount based on actual electrical energy, if any, delivered in each month in excess of a minimum threshold. Within each contract year, no variable energy fees are payable until energy in excess of the cumulative minimum threshold per month for the contract year to date has been delivered. If the Casecnan Project is not dispatched up to 150 MW whenever water is available, NIA will pay for energy that could have been generated but was not as a result of such dispatch constraint.
CalEnergy Generation-Domestic
The subsidiaries comprising the Company’s CalEnergy Generation-Domestic platform own interests in 15 non-utility power projects in the United States. The following table sets out certain information concerning CalEnergy Generation-Domestic’s non-utility power projects in operation as of December 31, 2006:
(1)
Facility Net or Contract Capacity (MW) represents total plant accredited net generating capacity from the summer 2006 as approved by MAPP for Cordova and contract capacity for most other projects. Net MW Owned indicates legal ownership of the Facility Net Capacity or Contract Capacity.
(2)
Constellation Energy Commodities Group, Inc. (“Constellation”); Hawaii Electric Company (“HELCO”); New York State Electric & Gas Corporation (“NYSE&G”); and San Diego Gas & Electric Company (“SDG&E”).
(3)
MEHC has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose affiliates currently operate ten geothermal plants in the Imperial Valley of California (the “Imperial Valley Projects”) and three natural gas-fired power generation facilities.
(4)
Approximately 80% of the Company’s interests in the Imperial Valley Projects’ Contract Capacity (MW) is sold to Southern California Edison under long-term power purchase agreements expiring in 2016 through 2026.
Electric Transmission Texas LLC
In January 2007, MEHC and American Electric Power (“AEP”) reached an agreement to form Electric Transmission Texas LLC (“ETT”), as a joint venture to build transmission facilities in Texas principally within the Electricity Reliability Council of Texas (“ERCOT”) market. Later in January, ETT filed with the Public Utility Commission of Texas for approval to operate as an electric transmission utility in Texas and establish initial rates. In its filing, ETT also requests approval for the transfer of transmission assets currently under construction by a subsidiary of AEP, AEP Texas Central Company, to the joint venture company valued at approximately $76 million.
Upon receipt of all required regulatory approvals and other standard closing conditions, AEP Utilities, a wholly-owned subsidiary of AEP, and MEHC Texas Transco, LLC, a wholly-owned subsidiary of MEHC each will acquire a 50% interest in the joint venture.
MEHC and AEP expect ETT to invest in additional transmission projects in ERCOT, which could exceed $1 billion during the next several years. The anticipated utility capitalization structure of ETT is targeted at 40% equity and 60% debt. The joint venture is expected to be operational by the end of the year.
HomeServices
HomeServices is the second largest full-service residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations and mortgage banking, primarily through joint ventures, title and closing services and other related services. HomeServices’ real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices’ operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices currently operates in 19 states under the following brand names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty Home Services, Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, Harry Norman Realtors, HOME Real Estate, Huff Realty, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential California Realty, Prudential Carolinas Realty, RealtySouth, Rector-Hayden REALTORS, Reece & Nichols, Roberts Brothers, Inc., Semonin REALTORS and Woods Bros. Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides. HomeServices’ major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Kansas City and Springfield, Missouri; Des Moines, Iowa; Atlanta, Georgia; Omaha and Lincoln, Nebraska; Birmingham, Auburn and Mobile, Alabama; Tucson, Arizona; Winston-Salem and Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Cincinnati, Ohio; and Miami, Florida. The U.S. residential real estate brokerage business is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.
Employees
As of December 31, 2006, the Company employed approximately 17,800 people, of which approximately 7,800 are covered by union contracts. The majority of the union employees are employed by PacifiCorp and MidAmerican Energy and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America. These collective bargaining agreements have expirations dates ranging from April 2007 to September 2009. HomeServices’ residential real estate agents are independent contractors and not employees.
General Regulation
MEHC’s energy subsidiaries are subject to comprehensive governmental regulation which significantly influences their operating environment, prices charged to customers, capital structure, costs and their ability to recover costs.
Domestic Regulated Public Utility Subsidiaries
MEHC’s domestic regulated public utility subsidiaries, PacifiCorp and MidAmerican Energy, are subject to comprehensive regulation by state utility commissions, federal agencies, and other state and local regulatory agencies. The more significant aspects of this regulatory framework are described below.
State Regulation
Historically, state utility commissions have established service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. A utility’s cost-of-service generally reflects its allowed operating expenses, including operation and maintenance expense, depreciation expense and taxes. Some portion of margins earned on wholesale sales for electricity and capacity and gas transmission service has historically been included as a component of retail cost of service upon which retail rates are based. State utility commissions may adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. State utility commissions typically have the authority to review and change service rates on their own initiative. Some states may initiate reviews at the request of a utility customer, a governmental agency or a representative of a group of customers. The utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.
The electric rates of PacifiCorp and MidAmerican Energy are generally based on the cost of providing traditional bundled service, including generation, transmission and distribution services. Historically, the state regulatory framework in the service areas of PacifiCorp’s and MidAmerican Energy’s systems reflected specified power and fuel costs as part of bundled rates or incorporated power or fuel adjustment clauses in the utility’s rates and tariffs. Power and fuel adjustment clauses permit periodic adjustments to cost recovery from customers and therefore provide protection against exposure to cost changes.
Except for Oregon, Washington and Illinois, PacifiCorp and MidAmerican Energy have an exclusive right to serve electricity customers within their service territories and, in turn, have the obligation to provide electric service to those customers. Under Oregon law, certain commercial and industrial customers have the right to choose alternative electric suppliers. The impact of these programs on the Company’s financial results has not been and is not expected to be material. In Washington, the state statute does not provide for exclusive service territory allocation. PacifiCorp’s service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the state commission. In Illinois, all customers are free to choose their electricity supplier and MidAmerican Energy has an obligation to serve customers at regulated rates that leave MidAmerican Energy’s system, but later choose to return. To date, there has been no significant loss of customers in Illinois.
In connection with the 2006 acquisition of PacifiCorp, MEHC and PacifiCorp have made commitments to the state commissions that limit the dividends PacifiCorp can pay to MEHC or its affiliates. As of December 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates without prior state regulatory approval to the extent PacifiCorp’s common stock equity would be reduced below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. As of December 31, 2006, PacifiCorp’s ratio, as calculated pursuant to the requirements of the applicable commitment, exceeded the minimum threshold.
In conjunction with the March 1999 acquisition of MidAmerican Energy by MEHC, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain a common equity to total capitalization ratio above 42%, except under circumstances beyond its control. MidAmerican Energy’s common equity to total capitalization ratio is not allowed to decline below 39% for any reason. If the ratio declines below the defined threshold, MidAmerican Energy must seek the approval of a reasonable utility capital structure from the IUB. MidAmerican Energy’s ability to issue debt could also be restricted. As of December 31, 2006, MidAmerican Energy’s common equity to total capitalization ratio, computed on a basis consistent with the commitment, was 53.6%.
PacifiCorp
The following table illustrates the current rate case status in each state jurisdictions in which PacifiCorp operates:
Jurisdiction
State Regulator
Base Rate (1)
Power Costs (1)
Test Period
% of Retail Revenue (2)
Utah
Utah Public Service Commission (“UPSC”)
December 2006 stipulation calls for an annual increase of $115.0 million with $85.0 million effective in December 2006 and the remaining $30.0 million effective in June 2007 (3).
No separate power cost recovery mechanism.
Forecasted test year.
41.9%
Oregon
Oregon Public Utility Commission (“OPUC”)
September 2006 settlement agreement resulted in an annual increase for non-power costs of $33.0 million effective in January 2007 (4).
Uses an annual transition adjustment mechanism, resulting in a $10.0 million increase in January 2007. After 2007, PacifiCorp's power costs will be updated annually.
Forecasted test year.
28.5%
Wyoming
Wyoming Public Service Commission (“WPSC”)
In March 2006, the WPSC approved the settlement of the general rate case. The settlement agreement provided for an annual rate increase of $15.0 million effective in March 2006, and an additional annual increase of $10.0 million effective in July 2006.
Power cost adjustment mechanism, subject to sharing and collars, was approved in March 2006 with an implementation date effective July 1, 2006.
Typically uses a historical test year with known and measurable changes. Key parties have agreed to allow PacifiCorp to file a forecasted test year in the next general rate case application.
13.4%
Washington
Washington Utilities and Transportation Commission (“WUTC”)
General rate increase of $23.2 million requested in October 2006. The WUTC decision is expected in June 2007.
Currently, no separate power cost recovery mechanism; Power cost recovery mechanism proposed in general rate case filing.
Historical with known and measurable changes.
7.7%
Idaho
Idaho Public Utilities Commission (“IPUC”)
In December 2006, the IPUC approved an $8.3 million rate increase for certain customers effective January 2007.
No separate power cost recovery mechanism.
Typically uses a historical test year with known and measurable changes.
6.2%
California
California Public Utilities Commission (“CPUC”)
In December 2006, the CPUC settled the general rate case, which provided for a $7.3 million annual increase.
The settlement also provides for a post-test year adjustment mechanism that provides for inflation-based increases in rates in 2008 and 2009, the ability to seek recovery of the California-allocable portion of major plant additions exceeding $50.0 million, and scheduled increases under the terms of the transition plan for Klamath irrigators.
In December 2006, the CPUC approved a dollar-for-dollar energy cost adjustment clause that allows for annual changes in the level of net power costs.
Forecasted test year.
2.3%
100.0%
(1)
Margins earned on net wholesale sales for energy and capacity have historically been included as a component of retail cost of service upon which retail rates are based.
(2)
Represents the geographic distribution of PacifiCorp’s retail electric operating revenue for the nine months ended December 31, 2006.
(3)
PacifiCorp has agreed that another rate case will not be filed in Utah until after December 11, 2007.
(4)
PacifiCorp has agreed that another rate case will not be filed in Oregon until after September 1, 2007. Also, refer to Note 6 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding Oregon Senate Bill 408.
MidAmerican Energy
Iowa
Under a series of electric settlement agreements between MidAmerican Energy, the OCA and other interveners approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2013, unless its Iowa jurisdictional electric return on equity in any year falls below 10%. Prior to filing for a general increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith negotiations with the signatories to the settlement agreements to attempt to avoid a general increase in rates. As a party to the settlement agreements, the OCA has agreed not to seek any decrease in MidAmerican Energy’s Iowa electric base rates prior to January 1, 2013. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost of service rate changes that could result in changes to rates for specific customers as long as such changes do not result in an overall increase in revenues for MidAmerican Energy. Additionally, under the incentive regulation aspects of the settlements, earnings exceeding a return on equity of 11.75% are shared with customers. Refer to Note 6 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional discussion regarding these settlements.
MidAmerican Energy does not have an electric fuel and purchased power adjustment clause in Iowa. A monthly purchased gas cost adjustment clause combined with an Incentive Gas Supply Procurement Plan provides protection from market changes in gas costs while offering financial incentives for MidAmerican Energy to minimize the cost of its gas supply portfolio.
Illinois
In December 1997, Illinois enacted a law to restructure Illinois’ electric utility industry. The law changed how and what electric services are regulated by the ICC and transitioned portions of the traditional electric services to a competitive environment. Electric base rates in Illinois were generally frozen until January 1, 2007, and are now subject to cost-based ratemaking.
Effective January 2007, MidAmerican Energy and the ICC have eliminated the monthly adjustment clause for recovery of fuel for electric generation and purchased power costs in Illinois. Base rates have been adjusted to include recoveries at average 2004/2005 cost levels. The elimination of the fuel adjustment clause exposes MidAmerican Energy to monthly market price changes for fuel and purchased power costs in Illinois, with rate case approval required for any base rate changes. With the elimination of the fuel adjustment clause, MidAmerican Energy may not petition for its reinstatement until November 2011. A monthly adjustment clause remains in effect for MidAmerican Energy’s purchased gas costs.
Federal Regulation
The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act and the Energy Policy Act. MidAmerican Energy is also subject to regulation by the Nuclear Regulatory Commission (“NRC”) pursuant to the Atomic Energy Act of 1954, as amended, with respect to the operation of the Quad Cities Station.
Federal Power Act
Under the Federal Power Act, the FERC regulates rates for interstate sales of electricity at wholesale, transmission of electric power, accounting, securities issuances and other matters, including construction and operation of hydroelectric projects. Margins earned on wholesale sales for electricity and capacity and transmission service have historically been included as a component of retail cost of service upon which retail rates are based.
Wholesale Electricity and Capacity
The FERC regulates PacifiCorp’s and MidAmerican Energy’s rates charged to wholesale customers for electricity, and capacity and transmission services. Most of PacifiCorp’s and MidAmerican Energy’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility. A December 2006 decision of the United States Court of Appeals for the Ninth Circuit changed the interpretation of the relevant standard which the FERC should apply when reviewing wholesale contracts for electricity or capacity. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. Parties to this proceeding are seeking review before the U.S. Supreme Court. Whether the U.S. Supreme Court will hear the case or the outcome of its ruling, should it decide to consider the matter, cannot be predicted at this time. All sellers subject to the FERC’s jurisdiction, including PacifiCorp and MidAmerican Energy, are currently subject to increased risk as a result of this decision.
The FERC conducts a triennial review of PacifiCorp’s and MidAmerican Energy’s market-based pricing authority. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and capacity in their respective control areas. In June 2006, the FERC ruled at the conclusion of its most recent review that PacifiCorp does not have market power and may continue to charge market-based rates. A change in filing status relating to new generation was confirmed by FERC in February 2007, reaching the same conclusion. Unless a current FERC rulemaking proceeding revises the triennial review requirement, PacifiCorp’s next triennial review will occur in 2009. MidAmerican Energy’s most recent review, which began in October 2004, is complete pending the FERC’s final ruling on certain sales made within MidAmerican Energy’s control area for delivery outside the control area. MidAmerican Energy has FERC authorization to sell at market-based rates outside of its control area. Based on its estimate of MidAmerican Energy’s potential refund obligation, the Company does not believe the ultimate resolution of this issue will have a material impact on MidAmerican Energy’s financial results. Subject to the outcome of the above rulemaking, MidAmerican Energy will submit its next triennial review three years after the date of the final order in the current review proceeding.
Transmission
The FERC regulates PacifiCorp’s and MidAmerican Energy’s wholesale transmission services. The regulation requires each to provide open access transmission service at cost-based rates. The FERC also regulates unbundled transmission service to retail customers. These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. Our transmission businesses are managed and operated independently from our generating and wholesale marketing businesses in accordance with the FERC Standards of Conduct.
On February 16, 2007, the FERC adopted a final rule designed to strengthen the pro-forma OATT by providing greater specificity and increasing transparency. The most significant revisions to the pro forma OATT relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and to exempt intermittent generators, and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation redispatch. As transmission providers with OATT on file with FERC, PacifiCorp and MidAmerican Energy will be required to comply with the requirements of the new rule. Certain details related to the rule, such as the precise methodology that will be used to calculate available transfer capability, will be determined prospectively and thus, it is difficult to make a precise determination of the effect of this new rule on PacifiCorp’s and MidAmerican Energy’s transmission operations. In addition, it is difficult to determine the effect of this new rule once fully implemented on the availability and price of transmission service from the perspective of the wholesale marketing function. However, at least on a preliminary basis, the rule is not anticipated to have a significant impact on PacifiCorp’s or MidAmerican Energy’s financial results.
In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp’s use of its transmission system while conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff during an internal review of its compliance with certain FERC regulations shortly before MEHC’s acquisition of PacifiCorp. Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily related to the way PacifiCorp used its own transmission system to transmit energy using network service instead of point-to-point service as the FERC believes is required by PacifiCorp’s tariff. This use of transmission service neither enriched PacifiCorp’s shareholders nor harmed its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $0.9 million to other transmission customers in April 2006 and paid a $10.0 million fine to the U.S. Treasury in January 2007.
Neither PacifiCorp nor MidAmerican Energy is part of a Regional Transmission Organization, but MidAmerican Energy has hired an independent transmission system coordinator to administer various MidAmerican Energy OATT functions for transmission service. PacifiCorp, along with other private utilities and public power organizations throughout the Pacific Northwest and Western United States, is a member of the Northern Tier Transmission Group, which initially will conduct reliability and economic planning coordination for its members.
Hydroelectric Relicensing
PacifiCorp’s hydroelectric portfolio consists of 50 plants with an aggregate facility net owned capacity of 1,160.1 MW. The FERC regulates 97.9% of the installed capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric plants are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements are subject to significant uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding hydroelectric relicensing.
Energy Policy Act
On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the law expanded the FERC’s regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.
The Energy Policy Act also repealed the Public Utility Holding Company Act of (“PUHCA 1935”) and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), effective February 8, 2006. PUHCA 1935 extensively regulated and restricted the activities of registered public utility holding companies and their subsidiaries. PUHCA 2005 eliminated the substantive requirements and restrictions previously applicable to holding companies under PUHCA 1935. Its repeal enabled Berkshire Hathaway to convert its shares of MEHC’s no par, zero-coupon non-voting convertible preferred stock into an equal number of shares of MEHC’s voting common stock. As a consequence, MEHC became a majority owned subsidiary of Berkshire Hathaway. PUHCA 2005 also increased the FERC’s authority over utility mergers, provides the FERC with access to books and records and requires holding companies to comply with its record retention requirements.
The Energy Policy Act also gives the FERC “backstop” transmission siting authority and directs the FERC to oversee the establishment of mandatory transmission reliability standards. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007. In part as a result of that portion of the law, PacifiCorp and MidAmerican Energy began development efforts to add additional wind-powered generation facilities.
Nuclear Regulatory Commission
MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Exelon Generation is the operator of Quad Cities Station and is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.
The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. On October 29, 2004, the NRC extended the operating licenses for Quad Cities Station until December 14, 2032. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.
MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation (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, which was amended and extended by the Energy Policy Act of 2005. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.
U.S. Interstate Pipeline Subsidiaries
The natural gas pipeline and storage operations of the Company’s U.S. interstate pipeline subsidiaries are regulated by the FERC, which administers, most significantly, the Natural Gas Act and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (i) rates, charges, terms and conditions of service, and (ii) the construction and operation of U.S. pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities.
Northern Natural Gas continues to use a modified straight fixed variable rate design methodology, whereby substantially all fixed costs assignable to firm transportation and storage customers, including a return on invested capital and income taxes, are to be recovered through fixed monthly demand reservation charges regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, cost. Kern River’s rates have historically been set using a “levelized cost-of-service” methodology so that the rate is constant over the contract period; however, rate design is the subject of Kern River’s current rate case before the FERC and may be subject to change as a result of the rate case outcome. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases. Refer to Note 6 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding recent rate case proceedings.
FERC regulations also restrict each pipeline’s marketing affiliates’ access to U.S. interstate pipeline natural gas transmission customer data and place certain conditions on services provided by the U.S interstate pipelines to their affiliated entities.
Additional proposals and proceedings that might affect the interstate natural gas pipeline industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any new proposals might be implemented or, if so, how Northern Natural Gas and Kern River Gas might be affected.
U.S. interstate natural gas pipelines are also subject to the regulations of the Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, and the federal PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas.
The NGPSA requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. The Company’s pipeline operations conduct internal audits of their major facilities at least every four years, with more frequent reviews of those it deems of higher risk. The DOT also routinely audits these pipeline facilities. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis.
The PSIA, as amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, established mandatory inspections for all natural gas pipelines in high-consequence areas. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protection in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property. The Company believes its pipeline operations comply in all material respects to this regulation. The regulation also requires Northern Natural Gas and Kern River to complete certain modifications to their pipeline systems by December 17, 2012. Each pipeline is scheduled to have this work completed by December 2011.
In addition to FERC regulation, certain operations are subject to oversight by state regulatory commissions.
U.K. Electricity Distribution Companies
Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by the Gas and Electricity Markets Authority (“GEMA”). GEMA discharges certain of its powers through its staff within the Office of Gas and Electricity Markets (“Ofgem”). Each of fourteen distribution license holders (“DLH”) distributes electricity from the national grid system to end use customers within their respective distribution service areas effectively creating a monopoly on electricity distribution within each area.
Given the absence of a competitive market, the amount of revenue that can be collected from customers by a DLH is controlled by a distribution price control formula. This encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DLHs to reflect an increase or decrease in distribution of units and number of end users. Currently, price controls are established every five years, although the formula has been, and may be, reviewed at the regulator’s discretion. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Historically, Ofgem’s judgment of the future allowed revenue of licensees has been based upon, among other things:
·
actual operating costs of each of the licensees;
·
pension deficiency payments of each of the licensees;
·
operating costs which each of the licensees would incur if it were as efficient as, in Ofgem’s judgment, the more efficient licensees;
·
taxes that each licensee is expected to pay;
·
regulatory value ascribed to and the allowance for depreciation related to the distribution network assets;
·
rate of return to be allowed on investment in the distribution network assets by all licensees; and
·
financial ratios of each of the licensees and the license requirement for each licensee to maintain an investment grade status.
The current electricity distribution price control was agreed in December 2004, became effective April 2005 and is expected to continue through March 2010. Prices during this 5-year period will be allowed to increase by no more than the rate of inflation (based upon the retail price index). Ofgem also indicated that during the current price control period, the retention of any actual reductions in operating costs from the assumptions used in setting the new price control might depend on the successful implementation of revised cost reporting guidelines prescribed by Ofgem and to be applied by all DLHs.
In 2005, the triennial process to value the UK pension plan’s assets and liabilities, using a March 31, 2004 measurement date, was completed and showed a £190.3 million funding deficiency. Contributions are computed based on the objective of eliminating the funding deficiency by April 1, 2017. CE Electric UK contributed £17.3 million in 2005 and £23.1 million in 2006 and intends to contribute an additional £23.1 million in 2007 to reduce the funding deficiency. Both Northern Electric’s and Yorkshire Electricity’s current price control allows for the recovery of the majority of the deficiency payments over time.
A number of incentive schemes also operate within the current price control period to encourage DLHs to provide an appropriate quality of service with specified payments to be made for failures to meet prescribed standards of service. The aggregate of these payments is uncapped, but may be excused in certain force majeure circumstances. There are also incentive schemes pursuant to which allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.
Ofgem also monitors DLH compliance with license conditions and enforces the remedies resulting from any breach of condition. Under the Utilities Act 2000, the regulators are able to impose financial penalties on DLHs who contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or who are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee’s revenue.
On November 3, 2006, Ofgem announced that it was investigating the possible breach by Northern Electric and Yorkshire Electricity of license conditions that require them to provide Ofgem with certain information pertaining to the number and duration of interruptions in the supply of electricity through the licensee’s electricity distribution system and the number and identity of customers who had telephoned the licensee to report a loss of supply. The investigation is ongoing and if Ofgem concludes a violation of the standard has occurred, it may impose a penalty as described above.
Independent Power Projects
Foreign
The Philippine Congress passed the Electric Power Industry Reform Act of 2001 (“EPIRA”), legislation aimed at restructuring the Philippine power industry, privatizing the NPC and introducing a competitive electricity market. The implementation of EPIRA may impact the Company’s future operations in the Philippines and the Philippine power industry as a whole, the effect of which is not yet known as changes resulting from EPIRA are ongoing. However, CE Casecnan has received written confirmation from the Philippine government that the issues with respect to the Casecnan Project that had been raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to the project under certain provisions of EPIRA, which authorized the ROP to seek to renegotiate certain contracts such as the Project Agreement, have been satisfactorily addressed.
Domestic
Both the Cordova and Power Resources Projects are Exempt Wholesale Generators (“EWG”) under the Energy Policy Act while the remaining domestic projects are currently certified as Qualifying Facilities (“QF”) under the Public Utility Regulatory Policies Act of 1978 (“PURPA”). Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.
EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility’s “avoided cost” and to sell back-up power to the QFs on a non-discriminatory basis. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities’ avoided cost.
Residential Real Estate Brokerage Company
HomeServices is regulated by the U.S. Department of Housing and Urban Development, most significantly under the Real Estate Settlement Procedures Act (“RESPA”), and by state agencies where it operates. RESPA primarily governs the real estate settlement process by mandating all parties fully inform borrowers about all closing costs, lender servicing and escrow account practices, and business relationships between closing service providers and other parties to the transaction.
Environmental Regulation
MEHC and its energy subsidiaries are subject to federal, state, local, and foreign laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance including fines, injunctive relief and other sanctions. The Company believes it is in material compliance with all laws and regulations. The most significant environmental laws and regulations affecting MEHC’s subsidiaries include:
·
The federal Clean Air Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards. Rules issued by the United States Environmental Protection Agency (“EPA”) and certain states require substantial reductions in sulfur dioxide (“SO2”), mercury, and nitrogen oxide (“NOx”) emissions beginning in 2009 and extending through 2018. The Company has already installed certain emission control technology and is taking other measures to comply with required reductions. Refer to the Clean Air Standards section below for additional discussion regarding this topic.
·
The Clean Water Act and individual state clean water laws that regulate cooling water intake structures and discharges of wastewater, including storm water runoff. The Company believes that it currently has, or has initiated the process to receive, all required water quality permits. Refer to the Clean Water Standards section below for additional discussion regarding this topic.
·
The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws, which may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding environmental contingencies.
·
The Nuclear Waste Policy Act of 1982, under which the U.S. Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. Refer to Note 12 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding the nuclear decommissioning and mine reclamation obligations.
·
The FERC oversees the relicensing of existing hydroelectric projects and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric projects, dam safety inspections and environmental monitoring. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding the relicensing of certain of PacifiCorp’s existing hydroelectric facilities.
The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Company. In particular, the Clean Air Act will likely continue to impact the operation of the Company’s domestic generating facilities and will likely require both PacifiCorp and MidAmerican Energy to make emissions reductions at their facilities through the installation of emission controls or to comply with the regulations through the purchase of additional emission allowances or some combination thereof.
Expenditures for compliance-related items such as pollution-control technologies, replacement generation, mine reclamation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into the routine cost structure of MEHC’s energy subsidiaries. An inability to recover these costs from the Company’s customers, either through regulated rates, long-term arrangements or market prices, could adversely affect the Company’s future financial results.
Clean Air Standards
The Clean Air Act provides a framework for protecting and improving the nation’s air quality, and controlling mobile and stationary sources of air emissions. The major Clean Air Act programs, which most directly affect the Company’s electric generating facilities, are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional, more stringent requirements.
National Ambient Air Quality Standards
The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. The counties in Washington, Idaho, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located, and the entire state of Iowa, where MidAmerican Energy’s major emission sources are located, are in attainment of the ambient air quality standards. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. Air quality modeling and preliminary air quality monitoring data indicate that portions of the states in which PacifiCorp and MidAmerican Energy have major emission sources may not meet the new standards. Until three years of data are collected and attainment designations under the new fine particulate standard are made, the impact of these new standards on PacifiCorp and MidAmerican Energy will not be known.
Regulated Air Pollutants
In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”), a two-phase program that utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons. The program requires initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. Individual states are required to implement the CAMR or alternative measures to achieve equivalent or greater mercury emission reductions through their state implementation plans. The CAMR is applicable to all PacifiCorp and MidAmerican Energy coal-fired facilities.
In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of SO2 and NOx emissions in the eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both. The state of Iowa has adopted rules implementing the market-based cap and trade system. Under the CAIR, the first phase of NOx emissions reductions are effective January 1, 2009, and the first phase of SO2 emissions reductions are effective January 1, 2010. For both NOx and SO2, the second-phase reductions are effective January 1, 2015. The CAIR requires overall reductions by 2015 of SO2 and NOx in Iowa of 68% and 67%, respectively, from 2003 levels. PacifiCorp’s generation facilities are not subject to the CAIR.
The CAMR or the CAIR could, in whole or in part, be superseded or made more stringent by current or future regulatory and legislative proposals at the federal or state levels that would result in significant reductions of SO2, NOX and mercury, as well as carbon dioxide and other gases that may affect global climate change. In addition to any federal rules or legislation that could be enacted, the CAMR and the CAIR could be changed or overturned as a result of litigation. The sufficiency of the standards established by both the CAMR and the CAIR has been legally challenged in the United States District Court of Appeals for the District of Columbia Circuit.
Regional Haze
The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s and MidAmerican Energy’s plants meet the threshold applicability criteria under the Clean Air Visibility Rules. With other stakeholders, PacifiCorp is participating in the Western Regional Air Partnership and MidAmerican Energy is participating in the Central States Regional Air Partnership to help develop the technical and policy tools needed to comply with this program.
New Source Review
Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated pollutant or (2) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states and environmental groups, among others, potentially subject a utility to material expenses for fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.
As part of an industry-wide investigation to assess compliance with the PSD and the New Source Performance Standards of the Clean Air Act (referred to collectively as NSR), the EPA has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating plants. In 2001 and 2003, PacifiCorp received requests for information relating to capital projects at seven of its generating plants. In 2002 and 2003, MidAmerican Energy received requests to provide documentation related to its capital projects at its generating plants. PacifiCorp and MidAmerican Energy have submitted information to the EPA in response to these requests, and there are currently no outstanding data requests pending from the EPA. An NSR enforcement case against another utility has been argued and is currently pending decision in the Supreme Court. The Supreme Court’s decision in that case may provide a definitive legal ruling on the proper legal test that EPA may apply in examining data such as that submitted by PacifiCorp and MidAmerican Energy to determine whether there has been an emissions increase. PacifiCorp and MidAmerican Energy cannot predict the outcome of EPA’s review of the data they have submitted at this time.
In and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge and in March 2006, a panel of the United States Court of Appeals for the District of Columbia Circuit invalidated portions of EPA’s new NSR rules, holding that they conflicted with the wording of the statute. However, EPA has asked the Supreme Court to review portions of the case. Until such time as the legal challenges are resolved and the revised rules are effective, PacifiCorp and MidAmerican Energy will continue to manage projects at their generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects, which are now subject to permitting under the PSD program. In 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the permitting process and allow facilities to undertake activities that improve their safety, reliability and efficiency without triggering NSR requirements. The EPA plans to finalize the rules by May 2007.
Refer to the Liquidity and Capital Resources section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding planned capital expenditures related to air quality standards. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding commitments and litigation related to air quality standards.
Climate Change
As a result of increased attention to climate change in the United States numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority and many congressional observers expect to see the passage of climate change legislation within the next several years. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific or regional legislative initiatives to reduce greenhouse gas emissions. For example, the states of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont have signed a mandatory regional pact to reduce greenhouse gas emissions by ten percent from 1990 levels that would become effective in 2009. An executive order signed by California’s governor in 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 levels by 2050. In August 2006, California enacted a greenhouse gas emission performance standard applicable to all electricity generated within the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation facility. California also adopted a statewide greenhouse gas emission cap to reduce greenhouse gas emissions by approximately 25% from 1990 levels by 2020. In November 2006, Washington voters passed a measure, which modified state law to require utilities that serve more than 25,000 Washington customers to obtain at least 15% of their electricity from renewable resources by the year 2020. The outcome of federal and state climate change legislation cannot be determined at this time; however, adoption of stringent limits on greenhouse emissions could significantly impact the Company’s fossil-fueled facilities, and, therefore, its financial results.
Water Quality Standards
The Clean Water Act establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the “best technology available for minimizing adverse environmental impact” to aquatic organisms. In July 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water a day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit Court of Appeals remanded almost all aspects of the rule to the EPA, leaving companies with cooling water intake structures uncertain regarding compliance with these requirements. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as further action is taken by the EPA. In the event that PacifiCorp’s or MidAmerican Energy’s existing intake structures require modification or alternative technology is required by new rules, expenditures to comply with these requirements could be significant.
Item 1A.
Item 1A. Risk Factors.
We are subject to certain risks in our business operations which are described below. Careful consideration of these risks should be made before making an investment decision. The risks and uncertainties described below are not the only ones facing us. Additional risks and uncertainties not presently known or that are currently deemed immaterial may also impair our business operations.
Our Corporate and Financial Structure Risks
We are a holding company and depend on distributions from subsidiaries, including joint ventures, to meet our obligations.
We are a holding company with no material assets other than the stock of our subsidiaries and joint ventures, or collectively referred to as our subsidiaries. Accordingly, cash flows and the ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the payment of such earnings to us in the form of dividends, loans, advances or other distributions. Our subsidiaries are separate and distinct legal entities and they have no obligation, contingent or otherwise, to provide us with funds or to guarantee the payment of any of our obligations. Distributions from subsidiaries may also be limited by:
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their respective earnings, capital requirements, and required debt and preferred stock payments;
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the satisfaction of certain terms contained in financing or organizational documents; and
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regulatory restrictions which limit the ability of our regulated utility subsidiaries to distribute profits.
We are substantially leveraged, the terms of our senior and subordinated debt do not restrict the incurrence of additional indebtedness by us or our subsidiaries, and our senior and subordinated debt is structurally subordinated to the indebtedness of our subsidiaries, each of which could have an adverse impact on our financial results.
A significant portion of our capital structure is debt and we expect to incur additional indebtedness in the future to fund acquisitions, capital investments or the development and construction of new or expanded facilities. At December 31, 2006, we had the following outstanding obligations:
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senior indebtedness of $4.5 billion;
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subordinated indebtedness of $1.4 billion, consisting of $0.3 billion of trust preferred securities held by third parties and $1.1 billion held by Berkshire Hathaway and its affiliates; and
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guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating $97.8 million.
Our consolidated subsidiaries also have outstanding indebtedness, which totaled $11.6 billion at December 31, 2006. These amounts exclude (i) trade debt or preferred stock obligations, (ii) letters of credit in respect of subsidiary indebtedness, and (iii) our share of the outstanding indebtedness of our own or our subsidiaries’ equity investments.
Given our substantial leverage, we may not generate sufficient cash to service our debt which could limit our ability to finance future acquisitions, develop and construct additional projects, or operate successfully under adverse economic conditions. It could also impair our credit quality or the credit quality of our subsidiaries, making it more difficult to finance operations or issue future indebtedness on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
The terms of our senior and subordinated debt do not limit our ability or the ability of our subsidiaries to incur additional debt or issue preferred stock. Accordingly, we or our subsidiaries could enter into acquisitions, refinancings, recapitalizations or other highly leveraged transactions that could significantly increase our or our subsidiaries’ total amount of outstanding debt. The interest payments needed to service this increased level of indebtedness could have a material adverse effect on our or our subsidiaries’ financial results. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of our other indebtedness, we may not have sufficient funds to repay all of the accelerated indebtedness.
Because we are a holding company, the claims of our senior and subordinated debt holders are structurally subordinated with respect to the assets and earnings of our subsidiaries. Therefore, the rights of our creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary’s creditors and preferred shareholders. In addition, a significant amount of the stock or assets of our operating subsidiaries is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of our senior and subordinated debt.
A downgrade in our credit ratings or the credit ratings of our subsidiaries could negatively affect our or our subsidiaries’ access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
Our senior unsecured long-term debt is rated investment grade by various rating agencies. We cannot assure that our senior unsecured long-term debt will continue to be rated investment grade in the future. Although none of our outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase our borrowing costs and commitment fees on the revolving credit agreements, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market, the principal source of short-term borrowings, could be significantly limited resulting in higher interest costs.
Similarly, any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause us to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing our and our subsidiaries’ liquidity and borrowing capacity.
Most of our large customers, suppliers and counterparties require sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If our credit ratings or the credit ratings of our subsidiaries were to decline, especially below investment grade, operating costs would likely increase because counterparties may require a letter of credit, collateral in the form of cash-related instruments or some other security as a condition to further transactions with us or our subsidiaries.
Our majority shareholder, Berkshire Hathaway, could exercise control over us in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.
Berkshire Hathaway is our majority owner and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between Berkshire Hathaway and our creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.
Our Business Risks
Much of our growth has been achieved through strategic acquisitions, and additional acquisitions may not be successful.
Our growth has been achieved largely through strategic acquisitions, including, since 2002, those of Kern River, Northern Natural Gas, PacifiCorp and various residential real estate brokerage businesses. We will continue to investigate and pursue opportunities for strategic acquisitions that we believe may increase shareholder value and expand or complement existing businesses. We may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful. Any transaction that does take place may involve consideration in the form of cash, debt or equity securities.
Completion of any business or asset acquisition entails numerous risks, including, among others, the:
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failure to complete the transaction for various reasons, such as the inability to obtain the required regulatory approvals;
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failure of the combined business to realize the expected benefits; and
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need for substantial additional capital and financial investments.
An acquisition could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. The diversion of management’s attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect our combined businesses and financial results and could impair our ability to realize the anticipated benefits of the acquisition.
Our regulated businesses are subject to extensive regulations that affect their operations and costs. These regulations are complex, dynamic and subject to change.
Our businesses are subject to numerous regulations and laws enforced by regulatory agencies. In the United States, these regulatory agencies include, among others, FERC, EPA, NRC, and the DOT. In addition, our utility subsidiaries are subject to state utility regulation in each state in which they operate. In the United Kingdom, these regulatory agencies include, among others, GEMA, which discharges certain of its powers through its staff within Ofgem.
Regulations affect almost every aspect of our business and limit our ability to independently make and implement management decisions regarding, among other items, business combinations, constructing, acquiring or disposing of operating assets, setting rates charged to customers, establishing capital structures and issuing equity or debt securities, engaging in transactions between our domestic utilities and other subsidiaries and affiliates, and paying dividends. Regulations are subject to ongoing policy initiatives and we cannot predict the future course of changes in regulatory laws, regulations and orders, or the ultimate effect that regulatory changes may have on us. However, such changes could materially impact our financial results. For example, such changes could result in, but are not limited to, increased retail competition within our subsidiaries’ service territories, new environmental requirements, the acquisition by a municipality or other quasi-governmental body of our subsidiaries’ distribution facilities (by negotiation, legislation or condemnation or by a vote in favor of a Public Utility District under Oregon law), or a negative impact on our subsidiaries’ current transportation and cost recovery arrangements, including income tax recovery.
Federal and state energy regulation changes are emerging as one of the more challenging aspects of managing utility operations. New and expanded regulations imposed by policy makers, court systems, and industry restructuring have imposed changes on the industry. The following are current or recent changes to our regulatory environment that may impact us:
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Energy Policy Act of 2005 - In the United States, the Energy Policy Act impacts many segments of the energy industry. Congress granted the FERC additional authority in the Energy Policy Act which expanded its regulatory role from a regulatory body to an enforcement agency. To implement the law, the FERC has and will continue to issue new regulations and regulatory decisions addressing electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority, including the ability to assess civil penalties of up to one million dollars per day per infraction for non-compliance. The full impact of those decisions remains uncertain however, the FERC has recently exercised its enforcement authority by imposing significant civil penalties for violations of its rules and regulations. In addition, as a result of past events affecting electric reliability, the Energy Policy Act requires federal agencies, working together with non-governmental organizations charged with electric reliability responsibilities, to adopt and implement measures designed to ensure the reliability of electric transmission and distribution systems effective June 1, 2007. Under the new regime, a transmission owner’s reliability compliance issues could result in financial penalties. Such measures could impose more comprehensive or stringent requirements on us or our subsidiaries, which would result in increased compliance costs and could adversely affect our financial results.
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FERC Orders - FERC has issued several orders, including Orders 636 and 637, to encourage competition in natural gas markets, the expansion of existing pipelines and the construction of new pipelines. Local distribution companies and end-use customers have additional choices in this more competitive environment and may be able to obtain service from more than one pipeline to fulfill their natural gas delivery requirements. Any new pipelines that are constructed could compete with our pipeline subsidiaries to service customer needs. Increased competition could reduce the volumes of gas transported by our pipeline subsidiaries or, in the absence of long-term fixed rate contracts, could force our pipeline subsidiaries to lower their rates to remain competitive. This could adversely affect our pipeline subsidiaries’ financial results.
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Hydroelectric Relicensing - Several of PacifiCorp’s hydroelectric projects whose operating licenses have expired or will expire in the next few years are in some stage of the FERC relicensing process. Hydroelectric relicensing is a political and public regulatory process involving sensitive resource issues and uncertainties. We cannot predict with certainty the requirements (financial, operational or otherwise) that may be imposed by relicensing, the economic impact of those requirements, whether new licenses will ultimately be issued or whether PacifiCorp will be willing to meet the relicensing requirements to continue operating its hydroelectric projects. Loss of hydroelectric resources or additional commitments arising from relicensing could increase PacifiCorp’s operating costs or result in large capital expenditures that reduce earnings and cash flows.
Recovery of costs by our energy subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect their financial results.
State Rate Proceedings - Public Utility Subsidiaries
Two of our regulated subsidiaries, PacifiCorp and MidAmerican Energy, establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns, but who generally have the common objective of limiting rate increases. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings.
Each state sets retail rates based in part upon the state utility commission’s acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year’s realized costs are higher than normal, rates will not be sufficient to cover those costs. Each state utility commission generally sets rates based on a test year established in accordance with that commission’s policies. Certain states use a future test year or allow for escalation of historical costs while other states use an historical test year. Use of an historical test year may cause regulatory lag which results in our utilities incurring costs, including significant new investments, for which recovery through rates is delayed. State commissions also decide the allowed rate of return we will be permitted to earn on our equity investment. They also decide the allowed levels of expense and investment that they deem is just and reasonable in providing service. The state commissions may disallow recovery in rates for any costs that do not meet such standard.
In Iowa, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2013 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. MidAmerican Energy expects to continue to make significant capital expenditures to maintain and improve the reliability of its generation, transmission and distributions facilities to reduce emissions and to support new business and customer growth. As a result, MidAmerican Energy’s financial results may be adversely affected if it is not able to deliver electricity in a cost-efficient manner and is unable to offset inflation and the cost of infrastructure investments with costs savings or additional sales.
In certain states, PacifiCorp and MidAmerican Energy are not permitted to pass through energy cost increases in their electric rates without a general rate case. Any significant increase in fuel costs or purchased power costs for electricity generation could have a negative impact on PacifiCorp or MidAmerican Energy, despite efforts to minimize this impact through future general rate cases or the use of hedging instruments. Any of these consequences could adversely affect our financial results.
While rate regulation is premised on providing a fair opportunity to obtain a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that we will be able to realize a reasonable rate of return.
FERC Jurisdiction - Public Utility Subsidiaries
FERC establishes cost-based tariffs under which both PacifiCorp and MidAmerican Energy provide transmission services to wholesale markets and retail markets in states that allow retail competition. FERC also has responsibility for approving both cost- and market-based rates under which both companies sell electricity at wholesale and has licensing authority over most of PacifiCorp’s hydroelectric generation facilities. FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or may (pursuant to pending or future proceedings) revoke or restrict the ability of our public utility subsidiaries to sell electricity at market-based rates, which could adversely affect our financial results. FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act, FERC’s rules or orders.
Interstate Pipelines
FERC has jurisdiction over, among other things, the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such facilities. FERC also has jurisdiction over the rates, charges and terms and conditions of service for the transportation of natural gas in interstate commerce.
Rates established for our U.S. interstate gas transmission and storage operations at Northern Natural Gas and Kern River are subject to FERC’s regulatory authority. The rates FERC authorizes these companies to charge their customers may not be sufficient to cover the costs incurred to provide services in any given period. These pipelines, from time to time, have in effect rate settlements approved by FERC which prevent them or third parties from modifying rates, except for allowed adjustments, for certain periods. These settlements do not preclude FERC from initiating a separate proceeding under the Natural Gas Act to modify the rates. It is not possible to determine at this time whether any such actions would be instituted or what the outcome would be, but such proceedings could result in rate adjustments.
U.K. Electricity Distribution
Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of the electricity distribution license holders is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not constrain profits from year to year, but is a control on revenue that operates independently of most of the electricity distribution license holder’s costs. It has been the practice of Ofgem, to review and reset the formula at five-year intervals, although the formula has been, and may be, reviewed at other times at the discretion of Ofgem. The current five-year cost control period became effective on April 1, 2005. A resetting of the formula requires the consent of the electricity distribution license holder however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British competition commission. GEMA is able to impose financial penalties on electricity distribution companies who contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the electricity distribution license holder’s revenue. During the term of the price control, additional costs have a direct impact on the financial results of Northern Electric and Yorkshire Electricity.
Through energy subsidiaries, we are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which is subject to significant risk, and our electric utility subsidiaries have significant funding needs related to their planned capital expenditures.
Through energy subsidiaries, we are continuing to develop and construct new or expanded facilities. We expect that these subsidiaries will incur substantial annual capital expenditures over the next several years. Expenditures could include, among others, amounts for new coal-fired, natural gas and wind powered electric generating facilities, electric transmission or distribution projects, environmental control and compliance systems, gas storage facilities, new or expanded pipeline systems, as well as the continued maintenance of the installed asset base.
Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor and other items over a multi-year construction period These risks may result in higher than expected costs to complete an asset and place it into service. Such costs, if found to be imprudent, may not be recoverable in the rates our subsidiaries are able to charge their customers. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs may materially affect our financial results.
Furthermore, our energy subsidiaries depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If we do not provide needed funding to our subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures. Failure to construct these projects could limit opportunities for revenue growth and increase operating costs. For example, if PacifiCorp is not able to expand its existing generating facilities it may be required to enter into bilateral long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.
Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and other requirements that may adversely affect our financial results.
Operational Standards
Our subsidiaries are subject to numerous environmental, health, safety, and other laws, regulations and other requirements affecting many aspects of their present and future operations, including, among others:
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the EPA’s CAIR, which established cap and trade programs to reduce sulfur dioxide, or SO2, and nitrous oxide, or NOx, emissions starting in 2009 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards;
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the EPA’s CAMR, which establishes a cap and trade program to reduce mercury emissions from coal-fired power plants starting in 2010;
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the DOT regulations, effective in 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property; and
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other laws or regulations that establish or could establish standards for greenhouse gas emissions, water quality, wastewater discharges, solid waste and hazardous waste.
These and related laws, regulations and orders generally require our subsidiaries to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals.
Compliance with environmental, health, safety, and other laws, regulations and other requirements can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, damages arising out of contaminated properties, and fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to regulations could be prohibitively expensive. As a result, some facilities may be required to shut down or alter their operations. Further, our subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals for their operating assets or development projects. Delays in obtaining any required environmental or regulatory permits, failure to comply with the terms and conditions of the permits or increased regulatory or environmental requirements may increase costs or prevent or delay our subsidiaries from operating their facilities or developing new facilities. If our subsidiaries fail to comply with all applicable environmental requirements, they may be subject to penalties and fines or other sanctions. The costs of complying with current or new environmental, health, safety, and other laws, regulations and other requirements could adversely affect our financial results. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called ‘‘greenhouse gases’’ such as carbon dioxide, a by-product of burning fossil fuels, methane (the primary component of natural gas), and methane leaks from pipelines. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.
Further, the regulatory rate structure or long-term customer contracts may not necessarily allow our subsidiaries to recover all costs incurred to comply with new environmental requirements. Although we believe that, in most cases, our regulated subsidiaries are legally entitled to recover these kinds of costs, the inability to fully recover such costs in a timely manner could adversely affect our financial results.
Site Clean-up and Contamination
Environmental, health, safety, and other laws, regulations and other requirements also impose obligations to remediate contaminated properties or to pay for the cost of such remediation, often by parties that did not actually cause the contamination. Our subsidiaries are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of their assets, including power generation facilities, and electric and natural gas transmission and distribution assets which our subsidiaries have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions, we or our subsidiaries may obtain or require indemnification against some environmental liabilities. If our subsidiaries incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, our subsidiaries could suffer material losses. Our subsidiaries have established reserves to recognize their estimated obligations for known remediation liabilities, but such estimates may change materially over time. In addition, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities which may be material. MidAmerican Energy is also required to fund its portion of the costs of decommissioning the Quad Cities Station when it is retired from service, which may include site remediation or decontamination.
Our subsidiaries are exposed to credit risk of counterparties with whom they do business and failure of their significant customers to perform under or to renew their contracts could reduce our operating revenues materially.
Certain of our subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. For example:
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a portion of our pipeline subsidiaries' capacity is contracted under long-term arrangements, and our pipeline subsidiaries are dependent upon relatively few customers for a substantial portion of their revenues;
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PacifiCorp and MidAmerican Energy rely on their wholesale customers to fulfill their commitments and pay for energy delivered to them on a timely basis;
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our U.K. utility electricity distribution businesses are dependent upon a relatively small number of retail suppliers. In particular, one supplier, RWE Npower PLC and certain of its affiliates represented approximately 42% of the total distribution revenues of our U.K. distribution companies in 2006; and
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generally, a single power purchaser takes energy from our non-utility generating facilities.
Adverse economic conditions or other events affecting counterparties with whom our subsidiaries conduct business could impair the ability of these counterparties to pay for services or fulfill their contractual obligations, or cause them to delay or reduce such payments to our subsidiaries. Our subsidiaries depend on these counterparties to remit payments on a timely basis. Any delay or default in payment or limitation on the subsidiaries to negotiate alternative arrangements could adversely affect our financial results.
If our subsidiaries are unable to renew, remarket, or find replacements for their long-term arrangements, our sales volume and revenue would be exposed to increased volatility. For example, without the benefit of long-term transportation, transmission or power purchase agreements, we cannot assure that our pipeline subsidiaries will be able to transport gas at efficient capacity levels, our regulated subsidiaries’ will be able to operate profitably, or our unregulated power generators will be able to sell the power generated by the non-utility generating facilities. Failure to secure these long-term arrangements could adversely affect our financial results.
The replacement of any existing long-term customer arrangements depends on market conditions and other factors that are beyond our subsidiaries’ control.
Inflation and changes in commodity prices and fuel transportation costs may adversely affect our financial results.
Inflation affects our businesses through increased operating costs and increased capital costs for plant and equipment. As a result of existing rate agreements and competitive price pressures, our subsidiaries may not be able to pass the costs of inflation on to their customers. If our subsidiaries are unable to manage costs increases or pass them on to their customers, our financial results could be adversely affected.
We are also heavily exposed to changes in prices and availability of coal and natural gas and the transportation of coal and natural gas because a substantial majority of our generation capacity utilizes these fossil fuels. Each of our electric utilities currently has contracts of varying durations for the supply and transportation of coal for much of their existing generation capacity, although PacifiCorp obtains some of its coal supply from mines owned or leased by it. When these contracts expire or if they are not honored, we may not be able to purchase or transport coal on terms as favorable as the current contracts. We have similar exposures regarding the market price of natural gas. Changes in the cost of coal or natural gas supply and transportation and changes in the relationship between such costs and the market price of power will affect our financial results. Since the sales price we receive for power may not change at the same rate as our coal or natural gas supply and transportation costs, we may be unable to pass on the changes in costs to our customers. In addition, the overall prices we charge our retail customers in some jurisdictions are capped and our fuel recovery mechanisms in other states are frozen for various periods of time or have been eliminated.
A significant decrease in demand for natural gas in the markets served by our subsidiaries’ pipeline and gas distribution systems would significantly decrease our operating revenues and thereby adversely affect our business and financial results.
A sustained decrease in demand for natural gas in the markets served by our subsidiaries’ pipeline and gas distribution systems would significantly reduce our operating revenue and adversely affect our financial results. Factors that could lead to a decrease in market demand include, among others:
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a recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on natural gas;
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an increase in the market price of natural gas or a decrease in the price of other competing forms of energy, including electricity, coal and fuel oil;
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efforts by customers to reduce their consumption of natural gas through various conservation measures and programs;
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higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or that limit the use of natural gas; and
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a shift to more fuel-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation proposing to mandate higher fuel economy, price differentials, incentives or otherwise.
Our public utility subsidiaries’ financial results may be adversely affected if they are unable to obtain adequate, reliable and affordable access to transmission service.
Our public utility subsidiaries depend on transmission facilities owned and operated by other utilities to transport electricity and natural gas to both wholesale and retail markets, as well as natural gas purchased to supply some of our subsidiaries’ electric generation facilities. If adequate transmission is unavailable, our subsidiaries may be unable to purchase and sell and deliver products. Such unavailability could also hinder our subsidiaries from providing adequate or economical electricity or natural gas to their wholesale and retail electric and gas customers and could adversely affect their financial results.
The different regional power markets have varying and dynamic regulatory structures, which could affect our businesses growth and performance. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to counter volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the financial results of our utilities.
Our subsidiaries are subject to market risk, counterparty performance risk and other risks associated with wholesale energy markets.
In general, wholesale market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. PacifiCorp and MidAmerican Energy purchase electricity and fuel in the open market or pursuant to short-term or variable-priced contracts as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, PacifiCorp or MidAmerican Energy may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when PacifiCorp or MidAmerican Energy is a net seller of electricity in the wholesale market, PacifiCorp or MidAmerican Energy will earn less revenue.
Wholesale electricity prices in PacifiCorp’s service areas are influenced primarily by factors throughout the western United States relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability and/or changes in customer loads due to the weather, the economy, regulations or customer behavior. Although PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, PacifiCorp is a net buyer of electricity during peak periods and therefore, its energy costs may be adversely impacted by market risk. In addition, PacifiCorp may not be able to timely recover all, if any, of those increased costs unless the state regulators authorize such recovery.
MidAmerican Energy’s total accredited net generating capability exceeds its historical peak load. As a result, in comparison to PacifiCorp, which relies to a significant extent on wholesale power purchases to satisfy its peak load, MidAmerican Energy has less exposure to wholesale electricity market price fluctuations. The actual amount of generation capacity available at any time, however, may be less than the accredited capacity due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons. In such circumstances, MidAmerican Energy may need to purchase energy in the wholesale markets and it may not recover in rates all of the additional costs that may be associated with such purchases. Most of MidAmerican Energy’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility, including price fluctuations.
PacifiCorp and MidAmerican Energy are also exposed to risks related to performance of contractual obligations by wholesale suppliers and customers. Each utility relies on suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the utilities to incur additional expenses to meet customer needs. In addition, when these contractual agreements terminate, the utilities may be unable to purchase the commodities on terms equivalent to the terms of current contractual agreements.
PacifiCorp and MidAmerican Energy rely on wholesale customers to take delivery of the energy they have committed to purchase and to pay for the energy on a timely basis. Failure of customers to take delivery may require these subsidiaries to find other customers to take the energy at lower prices than the original customers committed to pay. At certain times of the year, prices paid by PacifiCorp and MidAmerican Energy for energy needed to satisfy their customers’ energy needs may exceed the amounts they receive through rates from these customers. If the strategy used to hedge these risk exposures is ineffective, significant losses could result.
Our operating results may fluctuate on a seasonal and quarterly basis.
The sale of electric power and natural gas are generally seasonal businesses. In most parts of the United States and other markets in which our subsidiaries operate, demand for electricity peaks during the hot summer months when cooling needs are higher. Market prices for electric supply also generally peak at that time. In other areas, demand for electricity peaks during the winter. In addition, demand for gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in Northern Natural Gas’ market area and MidAmerican Energy’s retail gas business. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snow-pack may also impact electric generation at PacifiCorp’s hydroelectric projects.
As a result, the overall financial results of our energy subsidiaries may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less power, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our financial results through lower revenues or increased energy costs. Conversely, unusually extreme weather conditions could increase our costs to provide power and adversely affect our financial results. Furthermore, during or following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less electricity from hydroelectric projects and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. The extent of fluctuation in financial results may change depending on a number of factors related to our subsidiaries’ regulatory environment and contractual agreements, including their ability to recover power costs, the existence of revenue sharing provisions and terms of the power sale contracts.
Our subsidiaries are subject to operating uncertainties that may adversely affect our financial results.
The operation of complex electric and gas utility (including generation, transmission and distribution) systems, pipelines or power generating facilities that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, unscheduled plant outages, work stoppages, shortage of qualified labor, transmission and distribution system constraints or outages, fuel shortages or interruptions, unavailability of critical equipment, materials and supplies, low water flows, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes or explosions. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Any of these risks or other operational risks could significantly reduce or eliminate our subsidiaries’ revenues or significantly increase their expenses, thereby reducing the availability of distributions to us. For example, if our subsidiaries cannot operate their electric or natural gas facilities at full capacity due to damage caused by a catastrophic event, their revenues could decrease due to decreased wholesale sales and their expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks and current and future insurance coverage may not be sufficient to replace lost revenues or cover repair and replacement costs. Any reduction of revenues for such reason, or any other reduction of our subsidiaries’ revenues or increase in their expenses resulting from the risks described above could adversely affect our financial results.
Potential terrorist activities or military or other actions could adversely affect us.
The continued threat of terrorism since September 11, 2001 and the impact of military and other actions by the United States and its allies may lead to increased political, economic and financial market instability and subject our subsidiaries’ operations to increased risk of acts of terrorism. The United States government has issued warnings that energy assets, specifically pipeline, nuclear generation and other electric utility infrastructure are potential targets for terrorist organizations. Political, economic or financial market instability or damage to the operating assets of our subsidiaries, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to natural gas and electric energy, increased security, repair or other costs that may materially adversely affect us and our subsidiaries in ways that cannot be predicted at this time. Any of these risks could materially affect our financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability and the ability of our subsidiaries to raise capital.
The insurance industry changed in response to these events. As a result, insurance covering risks we and our subsidiaries typically insure against may decrease in scope and availability and we may elect to self-insure against many such risks. In addition, the available insurance may have higher deductibles, higher premiums and more restrictive policy terms.
MidAmerican Energy is subject to the unique risks associated with nuclear generation.
The ownership and operation of nuclear power plants, such as MidAmerican Energy’s 25% ownership interest in the Quad Cities Station involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The prolonged unavailability of the Quad Cities Station could materially affect MidAmerican Energy’s financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale power prices. The following are among the more significant of these risks:
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Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at the Quad Cities Station.
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Regulatory Risk - The NRC, may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, applicable regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for the Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
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Nuclear Accident Risk - Accidents and other unforeseen problems have occurred at nuclear facilities other than the Quad Cities Station, both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident could exceed MidAmerican Energy’s resources, including insurance coverage.
We own investments and projects located in foreign countries that are exposed to increased economic, regulatory and political risks.
We own and may acquire significant energy-related investments and projects outside of the United States. The economic, regulatory and political conditions in some of the countries where we have operations or are pursuing investment opportunities may present increased risks related to, among others, inflation, currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations, or tax policy. We may not be capable of either fully insuring against or effectively hedging these risks.
We are exposed to risks related to fluctuations in currency rates.
Our business operations and investments outside the United States increase our risk related to fluctuations in currency rates, primarily the British pound and the Philippine peso. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact. We may selectively reduce some foreign currency risk by, among other things, requiring contracted amounts be settled in United States dollars, indexing contracts to the United States dollar or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect our financial results. We attempt, in many circumstances, to structure foreign transactions to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars. We may not be able to obtain sufficient dollars or other hard currency or available dollars may not be allocated to pay such obligations, which could adversely affect our financial results.
Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions which are beyond HomeServices’ control. Any of the following are examples of items that could have a material adverse effect on HomeServices’ businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
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rising interest rates or unemployment rates;
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periods of economic slowdown or recession in the markets served;
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decreasing home affordability;
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declining demand for residential real estate as an investment; and
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nontraditional sources of new competition.
We and our subsidiaries are involved in numerous legal proceedings, the outcomes of which are uncertain and could negatively affect our financial results.
We and our subsidiaries are parties to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is reasonably possible that the final resolution of some of the matters in which we and our subsidiaries are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our financial results. Similarly, it is also reasonably possible that the terms of resolution could require that we or our subsidiaries change business practices and procedures, which could also have a material adverse effect on our financial results.
Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which may change the way analysts measure our business or financial performance.
Accounting irregularities discovered in the past few years in various industries have caused regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will ultimately develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board, or FASB, the FERC or the SEC could enact new or revised accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets and liabilities.
Item 1B.
Item 1B. Unresolved Staff Comments.
Not applicable.
Item 2.
Item 2. Properties.
The Company’s energy properties consist of the physical assets necessary and appropriate to generate, transmit, store, distribute and supply energy and consist mainly of electric generation, transmission and distribution facilities and gas distribution plants, natural gas pipelines, storage facilities, compressor stations and meter stations, along with the related rights-of-way. It is the opinion of the Company’s management that the principal depreciable properties owned by the Company are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each of the Company’s subsidiaries (except CE Electric UK, all of MidAmerican Energy’s gas utility properties and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. For additional information regarding the Company’s energy properties, refer to Item 1. Business and Note 4 and Note 24 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
The right to construct and operate the Company’s electric transmission and distribution facilities and pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River in the United States and Northern Electric and Yorkshire Electricity in the United Kingdom continue to have the power of eminent domain in each of the jurisdictions in which they operate their respective facilities, but the United States utilities do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.
With respect to real property, each of the electric transmission and distribution facilities and pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the generation stations, electric substations, compressor stations, measurement stations and office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and pipelines. The Company believes that each of its energy subsidiaries have satisfactory title to all of the real property making up their respective facilities in all material respects.
Item 3.
Item 3. Legal Proceedings.
In addition to the proceedings described below, the Company is currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by the Company to have a material adverse effect on its consolidated financial results.
Regulated Utility Companies
In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the Ninth Circuit Court of Appeals and briefing was completed in March 2006. Any final order will be subject to appeal. PacifiCorp believes the outcome of this proceeding will not have a material impact on its financial results.
In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Clean Air Act’s opacity standards at PacifiCorp’s Jim Bridger Power Plant in Wyoming. Under the Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light in the flue of a generating facility. The complaint alleges thousands of violations and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. PacifiCorp believes it has a number of defenses to the claims, and it has already committed to invest at least $812.0 million in pollution control equipment at its generating facilities, including the Jim Bridger plant, that is expected to significantly reduce emissions. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time.
On December 28, 2004, an apparent gas explosion and fire resulted in three fatalities, one serious injury and property damage at a commercial building in Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an improper installation of a pipeline connection may have been a cause of the explosion and fire. A predecessor company to MidAmerican Energy provided gas service in Ramsey, Minnesota, at the time of the original installation in 1980. In 1993, a predecessor of CenterPoint Energy, Inc. (“CenterPoint”) acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company.
As a result of the explosion and fire, MidAmerican Energy and CenterPoint have received settlement demands which total $15.5 million. MidAmerican Energy’s exposure, if any, to these demands is covered under its liability insurance to which a $2.0 million retention applies. In addition, CenterPoint has completed replacing all service lines in the former North Central Public Service Company properties located in Minnesota at a cost of approximately $39 million according to publicly filed reports.
Two lawsuits naming MidAmerican Energy as a third party defendant have been filed by CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy, in the U.S. District Court, District of Minnesota, related to this incident. The complaints seek contribution and indemnity on a wrongful death claim filed by the estate of one of the decedents and on a property damage and business interruption claim filed by the business whose premises were involved together with all sums associated with CenterPoint’s service lines replacement program. All claims arising from this incident have been settled by CenterPoint pursuant to Confidential Orders and Agreements; however, the third party actions remain. A Report and Recommendation on MidAmerican Energy’s motion for summary judgment in both of these cases was issued on January 16, 2007, recommending that CenterPoint’s third party claims based upon negligent installation be barred against MidAmerican Energy; however, claims based upon negligent operation and maintenance of the gas pipeline may continue. The parties timely objected to the Report and Recommendation and filed an appeal. MidAmerican Energy intends to vigorously defend its position in these claims and believes its ultimate outcome will not have a material impact on MidAmerican Energy’s financial results.
Interstate Pipeline Companies
In 1998, the United States Department of Justice informed the then current owners of Northern Natural Gas and Kern River that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Northern Natural Gas and Kern River. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys’ fees and costs. Motions to Dismiss based on various jurisdictional grounds were filed on June 4, 2004. On May 17, 2005, Northern Natural Gas and Kern River each received a Special Master’s Report and Recommendations in which the Special Master recommended that the action against Northern Natural Gas and Kern River be dismissed for lack of subject matter jurisdiction. Grynberg and the coordinated defendants each filed motions relating to the Special Master’s Report and Recommendations on June 27, 2005. On October 20, 2006, the United States District Court for the District of Wyoming ruled that Grynberg’s 1995 Qui Tam Litigation Documents constituted public disclosure not only with regard to Northern Natural Gas and Kern River (which were party to that action) but also as to all the other defendants which were not party to that action. The District Court thus affirmed the Special Master’s Report and Recommendation that the court lacked subject matter jurisdiction and dismissed Grynberg’s compliant as to all defendants. On November 16, 2006, Grynberg filed 74 separate notices of appeal from the district court’s decision of dismissal. In connection with the purchase of Kern River from The Williams Companies, Inc. (“Williams”) in 2002, Williams agreed to indemnify MEHC against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in 2002. The Company believes that the Grynberg cases filed against Northern Natural Gas and Kern River are without merit and that Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously and believes its ultimate outcome will not have a material impact on their financial results.
On June 8, 2001, a number of interstate pipeline companies, including Northern Natural Gas and Kern River, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. On May 12, 2003, the plaintiffs filed a motion for leave to file a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The court granted the motion for leave to amend on July 28, 2003. Kern River was not a named defendant in the amended complaint and has been dismissed from the action. Northern Natural Gas filed an answer to the fourth amended petition on August 22, 2003. On January 4, 2005, the plaintiffs filed their class certification motion and brief in support of that motion. Northern Natural Gas and other defendants filed their joint briefs and expert affidavits in opposition to class certification on February 22, 2005. The plaintiffs filed their reply brief in support of class certification on March 18, 2005. On November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which ruled that in that case the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues and remanded a denial of class certification for such an analysis. The plaintiffs hope to use this as grounds for further class certification briefing. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes its ultimate outcome will not have a material impact on its financial results.
Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter filed a new companion action against a number of parties, including Northern Natural Gas but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. The action was filed on May 12, 2003. On January 4, 2005, the plaintiffs filed their class certification motion and brief in support of that motion. Northern Natural Gas and other defendants filed their joint briefs and expert affidavits in opposition to class certification on February 22, 2005. The plaintiffs filed their reply brief in support of class certification on March 18, 2005. On November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which ruled that in that case the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues and remanded a denial of class certification for such an analysis. The plaintiffs hope to use this as grounds for further class certification briefing. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes its ultimate outcome will not have a material impact on its financial results.
Independent Power Projects
Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon proforma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA arbitration. On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend declarations in 2006, 2005 and 2004, totaling $32.5 million, was set aside in a separate bank account in the name of CE Casecnan.
On August 4, 2005, the court issued a decision, ruling in favor of LPG on five of the eight disputed issues in the first phase of the litigation. On September 12, 2005, LPG filed a motion seeking the release of the funds which have been set aside pursuant to the status quo agreement referred to above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October 3, 2005, and at the hearing on October 26, 2005, the court denied LPG’s motion. On January 3, 2006, the court entered a judgment in favor of LPG against CE Casecnan Ltd. According to the judgment, LPG would retain its ownership of 15% of the shares of CE Casecnan and distributions of the amounts deposited into escrow plus interest at 9% per annum. On February 28, 2006, CE Casecnan Ltd. filed an appeal of this judgment and the August 4, 2005 decision. On February 21, 2007, California Court of Appeals remanded the case to the lower court to modify its finding on one of the five disputed issues previously determined in favor of LPG. The judgment was affirmed in all other respects. The Company is currently evaluating the Court of Appeal’s order. The parties are proceeding in the trial court on LPG’s remaining claim against MEHC for damages for alleged breach of fiduciary duty. This claim is expected to be resolved sometime in 2007. The Company intends to vigorously defend the remaining claims.
In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. The Company believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, the Company will vigorously defend such action. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Cascenan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the matter is currently in the early stages of discovery. The Company intends to vigorously defend the counterclaims.
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, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Since March 14, 2000, MEHC’s common stock has been owned by Berkshire Hathaway, Mr. Walter Scott, Jr. and certain of his family members and family controlled trusts and corporations, Mr. David L. Sokol, its Chairman and Chief Executive Officer, and Mr. Gregory E. Abel, its President and Chief Operating Officer, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. MEHC has not declared or paid any cash dividends on its common stock since March 14, 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
For a discussion of contractual and regulatory restrictions that limit certain of MEHC’s subsidiaries’ ability to pay dividends on their common stock to MEHC, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 11 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
On November 17, 2006, MEHC issued 200,000 shares of its common stock, no par value, to Mr. Sokol upon the exercise by Mr. Sokol of 200,000 of his outstanding common stock options. The common stock options were exercisable at a price of $34.69 per share and the aggregate exercise price paid by Mr. Sokol was $6.9 million. MEHC also issued, on November 15, 2006, 125,000 shares of its common stock, no par value, to Mr. Abel upon the exercise by Mr. Abel of 125,000 of his outstanding common stock options. The common stock options were exercisable at a weighted-average price of $17.68 per share and the aggregate exercise price paid by Mr. Abel was $2.2 million. These issuances were pursuant to private placements and were exempt from the registration requirements of the Securities Act of 1933, as amended.
Item 6.
Item 6. Selected Financial Data.
The following table sets forth the Company’s selected consolidated historical financial data, which should be read in conjunction with Item 7.
Item 7. 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 financial condition and results of operations of the Company during the periods included herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with Item 6. Selected Financial Data and with the Company’s historical Consolidated Financial Statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. The Company’s actual results in the future could differ significantly from the historical results.
Executive Summary
The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding (which primarily includes MidAmerican Energy), Northern Natural Gas, Kern River, CE Electric UK (which primarily includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. Through these platforms, MEHC owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas interstate pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.
The following significant events and changes occurred during 2006 as discussed in more detail herein and in Item 1. Business, that highlight some of the factors which affected, or may affect in the future, the Company’s financial condition, results of operations and liquidity:
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On February 9, 2006, following the effective date of the repeal of PUHCA 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par, zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock.
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On March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC common equity. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum increments of at least $250 million pursuant to one or more drawings authorized by MEHC’s Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to us in exchange for additional shares of MEHC’s common stock. The Berkshire Equity Commitment will expire on February 28, 2011.
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On March 21, 2006, MEHC issued common stock of $5.1 billion to Berkshire Hathaway and other existing shareholders and purchased PacifiCorp, a wholly owned indirect subsidiary of ScottishPower, for $5.1 billion in cash. The results of PacifiCorp are included in MEHC’s results beginning March 21, 2006.
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MEHC’s subsidiaries continue to invest primarily in rate-regulated infrastructure assets including significant new coal, gas and wind generation facilities, as well as transmission and distribution assets and environmental compliance equipment. In 2006, the Company’s capital expenditures were $2.4 billion. The Company is currently estimating 2007 capital expenditures to be approximately $3 billion. On a consolidated basis, the Company issued $2.4 billion of long-term debt and repurchased $1.75 billion of common equity in 2006.
Results of Operations
Overview
Net income for 2006 increased $353.4 million, or 62.8%, to $916.1 million compared to 2005. Net income related to PacifiCorp, which was acquired on March 21, 2006, was $214.8 million during 2006. Also contributing to the increase in net income were favorable comparative results at most of the Company’s energy businesses and from $73.3 million of after tax gains on sales of available-for-sale securities. These improvements were partially offset by lower earnings at HomeServices and higher interest expense on parent company senior debt.
Net income for 2005 increased $392.5 million, or 230.6%, to $562.7 million compared to 2004. The increase was primarily due to a $367.6 million after-tax loss from discontinued operations recognized in 2004 as a result of management’s decision to cease operations of the Zinc Recovery Project. The remaining increase was the result of favorable comparative results at most of the Company’s domestic businesses and from gains on sales of certain non-strategic assets and investments. These improvements were partially offset by lower earnings at CE Electric UK, primarily associated with the distribution businesses, and an after-tax gain of $43.7 million, recognized in 2004, from the realization of certain Enron-related bankruptcy claims.
Segment Results
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions, including administrative costs, intersegment eliminations and fair value adjustments relating to acquisitions. Additionally, the activity of the Company’s Mineral Assets, which was previously reported in the CalEnergy Generation-Domestic reportable segment, is presented as discontinued operations within the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
A comparison of operating revenue and operating income for the Company’s reportable segments for the years ended December 31 follows (in millions):
PacifiCorp
On March 21, 2006, MEHC acquired 100% of the common stock of PacifiCorp. Operating revenue for 2006 consisted of $2,328.6 million of retail revenues and $610.6 million of wholesale and other revenues. Operating income for 2006 totaled $528.4 million. PacifiCorp’s results included $37.7 million of after-tax, non-cash losses from the period of acquisition to December 31, 2006, on its electricity and natural gas forward purchase and sales contracts. The losses related principally to unfavorable mark-to-market movements in forward price curves. PacifiCorp uses derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize the value of power generation assets and related contracts.
MidAmerican Funding
MidAmerican Funding’s operating revenue and operating income for the years ended December 31 are summarized as follows (in millions):
Regulated Electric Operations
Sales volumes and average number of customers of MidAmerican Energy’s regulated electric business for the years ended December 31 are summarized as follows (in millions, except for average number of customers):
MidAmerican Energy’s regulated electric retail revenue for 2006 increased $47.0 million, or 3.8%, to $1,269.0 million compared to 2005 and the related gross margin increased $39.4 million. Growth in retail demand, which included a 1.3% increase in the average number of retail customers and the addition of a large steel manufacturer in October 2005, contributed $36.4 million to the revenue increase. Changes in non-weather electricity usage factors, such as home size, technology changes and multiple appliances, accounted for another $10.6 million of the increase. These increases were offset by $20.8 million in lower revenue due to mild summer temperatures in 2006. Also, contributing to higher electric retail revenue were a $14.0 million increase in transmission service revenues, earned to transport wholesale volumes across MidAmerican Energy’s system, and $7.1 million in energy efficiency revenues.
In addition to electric retail sales, MidAmerican Energy sells electric energy, or wholesale sales, to other utilities, marketers and municipalities. Wholesale revenue for 2006 increased $219.3 million, or 75.3%, to $510.5 million compared to 2005 and the related gross margin increased $31.4 million. Higher average electric energy prices increased wholesale revenue by $122.3 million, while a 33.3% increase in wholesale sales volumes accounted for the remaining $97.0 million increase resulting from MidAmerican Energy-owned wind-powered generation and greater market opportunities.
MidAmerican Energy’s regulated electric operating income in 2006 increased $37.5 million, or 11.2%, to $372.1 million compared to 2005 due to the aforementioned $70.8 million combined increase in retail and wholesale gross margins which was partially offset by $27.6 million in higher operating expenses and $5.8 million in higher deprecation expense. Operating expenses increased primarily due to higher generating plant operating and maintenance expenses including additional expense for wind generation.
MidAmerican Energy’s regulated electric retail revenue for 2005 increased $85.3 million, or 7.5%, to $1,222.0 million compared to 2004. Electric retail sales volumes increased 6.6% compared to 2004. Higher average temperatures during 2005 compared to 2004 resulted in a $43.4 million increase in electric retail revenue. A growing retail customer base in 2005 improved electric retail revenue by $17.7 million, while non-weather electricity usage factors increased electric revenue by $9.1 million. Additionally, transmission revenue increased $7.9 million.
MidAmerican Energy’s wholesale revenue for 2005 increased $6.2 million, or 2.2%, to $291.2 million compared to 2004. The effect of higher electric energy prices, offset partially by a higher proportion of lower-priced, off-peak sales, increased wholesale energy revenue in 2005 by $33.3 million. Wholesale units for 2005 decreased 9.5% from 2004, resulting in a $27.1 million decrease in revenue. The primary reason for the decrease in wholesale sales volumes for 2005 was the timing of planned generation outages for the Louisa Generating Station and the loss of generating capacity at the Ottumwa Generating Station Unit No. 1 (“OGS Unit No. 1”), which experienced a failure of its step-up transformer on February 20, 2005. OGS Unit No. 1 returned to service on May 3, 2005.
MidAmerican Energy’s regulated electric operating income for 2005 increased $30.6 million, or 10.1%, to $334.6 million compared to 2004. Regulated electric retail and wholesale sales gross margin increased $22.0 million as the cost of fuel, energy and capacity for 2005 increased $69.5 million, or 17.4%, compared to 2004, which offset the majority of the increased revenue. The increase in the cost of fuel, energy and capacity was principally due to the cost of replacement power in connection with the generating station outages previously discussed and the increased use of gas-fired generation, primarily from the Greater Des Moines Energy Center. Regulated electric operating expense for 2005 decreased $10.6 million compared to 2004 due principally to the timing of generating plant maintenance and lower postretirement benefit costs, partially offset by higher distribution and transmission operations costs.
Regulated Natural Gas Operations
Under its purchase gas adjustment clauses, MidAmerican Energy is permitted to recover the cost of gas used to service its retail gas utility customers. Consequently, neither fluctuations in the cost of gas sold nor changes in wholesale gas sales have a significant effect on regulated gross margin or operating income.
The average per-unit cost of gas sold decreased 13.2% in 2006 resulting in a $134.7 million decrease in revenue and cost of gas sold compared to 2005. Wholesale volumes were 4.7% lower and retail sales volumes were 8.3% lower in 2006 compared to 2005, due to mild temperatures, resulting in a $75.2 million decrease in revenue and cost of gas sold. The lower retail volumes were the primary factor in the lower regulated natural gas operating income.
The average per-unit cost of gas sold increased 32.8% in 2005 resulting in a $271.6 million increase in revenue and cost of gas sold compared to 2004. Wholesale volumes were 10.8% higher and retail volumes were 0.9% higher in compared to 2004, resulting in a $36.8 million increase to revenue and cost of gas sold. Regulated natural gas operating income in 2005 decreased $3.7 million primarily due to higher operating costs, partially offset by the small increase in retail sales volumes.
Non-regulated Operations
MidAmerican Funding’s non-regulated operating revenue for 2006 increased $231.5 million, or 70.1%, to $561.7 million compared to 2005. The increase was primarily due to a change in the management strategy related to certain end-use natural gas contracts that required the related revenues and cost of sales to be recorded prospectively on a gross, rather than net, basis. For 2005, cost of sales totaling $289.2 million were netted in non-regulated operating revenue for such end-use gas contracts. Partially offsetting this increase to non-regulated operating revenue in 2006 was a decrease in natural gas sales volumes and lower electric and natural gas prices compared to 2005.
Northern Natural Gas
Operating revenue for 2006 increased $64.5 million, or 11.3%, to $633.6 million compared to 2005. Transportation revenue increased $55.0 million, or 12.2%, due to favorable market conditions resulting in higher field area demand and rates and new transportation contracts related to new and growing demand. Storage revenue increased $10.4 million due to favorable market conditions on interruptible services and the expansion of our firm storage cycle capacity. Transportation and storage revenues were also favorably impacted in 2006 by an $8.6 million reduction in 2005 due to the net effects of rate case settlements.
Operating income for 2006 increased $60.3 million, or 28.9%, to $269.1 million compared to 2005 due to the aforementioned increase in transportation and storage revenues as well as a $29.0 million asset impairment charge in 2005, partially offset by a gain of $19.7 million in 2005 from the sale of an idled section of pipeline in Oklahoma and Texas and the adjustments from two FERC-approved settlements that increased operating income in 2005 by $16.0 million.
Operating revenue for 2005 increased $24.3 million, or 4.5%, to $569.1 million compared to 2004. The increase was mainly due to higher gas and liquids sales of $25.6 million, due to higher sales of gas from operational storage utilized to manage physical flows on the pipeline system, and higher transportation and storage revenues of $5.4 million, due to changes in the composition of transportation contracts. These increases were partially offset by the net effects of the consolidated rate case and system levelized account (“SLA”) settlements, which decreased operating revenue by $8.6 million.
Operating income for 2005 increased $18.5 million, or 9.7%, to $208.8 million compared to 2004 due to the $19.7 million gain on sale of the pipeline asset, $16.0 million impact of rate case settlements, the $5.4 million increase in transportation and storage revenues and lower operating expenses, partially offset by the $29.0 million asset impairment charge in 2005.
Kern River
In October 2006, the FERC issued an order that modified certain aspects of the administrative law judge’s initial decision on Kern River’s pending rate case received earlier in 2006, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the rates for the vintage system being designed on a 95% load factor basis as the FERC determined a 100% load factor basis should be used. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. As a result of the October 2006 order, Kern River increased its estimate for rates subject to refund by $35.6 million and reduced depreciation expense by $28.2 million.
Operating revenue for 2006 increased $1.6 million, or 0.5%, to $325.2 million compared to 2005 due primarily to higher transportation revenues of $33.9 million due to favorable market conditions, largely offset by the aforementioned $33.6 million adjustment to Kern River’s provision for estimated refunds.
Operating income for 2006 increased $12.4 million, or 6.1%, to $216.9 million compared to 2005 due primarily to the higher transportation revenues discussed above and lower depreciation and amortization due primarily to changes in the expected rates in connection with the current rate proceeding.
Operating revenue for 2005 increased $7.5 million, or 2.4%, to $323.6 million compared to 2004. The increase in operating revenue resulted from higher demand and commodity transportation revenues of $14.0 million due mainly to higher rates, subject to refund, for the current rate proceeding which became effective on November 1, 2004. This increase was partially offset by lower interruptible transportation revenue of $5.9 million. Operating income remained relatively flat in 2005 compared to 2004.
CE Electric UK
Operating revenue for 2006 increased $44.2 million, or 5.0%, to $928.3 million compared to 2005 due primarily to higher contracting revenue of $20.9 million, higher distribution revenues at Northern Electric and Yorkshire Electricity of $13.7 million due to higher units distributed and the favorable impact of the exchange rate of $12.3 million. Operating income for 2006 increased $31.8 million, or 6.6%, to $515.7 million due primarily to the aforementioned increase in operating revenue, partially offset by higher cost of sales of $17.1 million due to higher contracting revenues.
Operating revenue for 2005 decreased $52.3 million, or 5.6%, to $884.1 million compared to 2004 due primarily to $37.0 million of lower distribution revenues at Northern Electric and Yorkshire Electricity due to higher units distributed, $9.1 million of lower contracting revenues and a $6.9 million adverse impact of the exchange rate. Operating income for 2005 decreased $13.5 million, or 2.7%, to $483.9 million due mainly to the previously discussed reductions in operating revenue, partially offset by lower cost of sales of $7.5 million due primarily to lower contracting work and exit charges from the National Grid Company and a gain of $13.3 million on the partial disposal of certain CE Gas Australian assets and lower costs of $11.2 million associated with the withdrawal from the metering market.
CalEnergy Generation-Foreign
Operating revenue for 2006 increased $24.0 million, or 7.7%, to $336.3 million compared to 2005. Higher revenue at the Casecnan Project of $41.5 million as a result of higher water flows throughout 2006 was partially offset by lower operating revenue at the Leyte Projects of $17.5 million as the Upper Mahiao Project was transferred on June 25, 2006 to the Philippine government.
Operating income for 2006 increased $44.9 million, or 24.3%, to $229.9 million compared to 2005 due primarily to the higher revenue as well as lower operating expenses of $14.8 million due primarily to the aforementioned transfer of the Upper Mahiao Project.
HomeServices
Operating revenue for 2006 decreased $166.7 million, or 8.9%, to $1,701.8 million compared to 2005 resulting in lower gross margin of $43.3 million. The decrease in operating revenue was due to a decline from existing businesses totaling $282.5 million reflecting fewer brokerage transactions as a result of the general slowdown in the U.S. housing market, partially offset by the results of acquired companies totaling $115.8 million not included in the comparable 2005 period.
Operating income for 2006 decreased $70.6 million compared to 2005 due to the aforementioned decrease in gross margin, higher operating expenses of $13.2 million and higher acquisition related amortization of $10.1 million. Operating expenses increased mainly due to $29.5 million for acquired companies not included in the comparable 2005 period, partially offset by $16.3 million in lower operating expense at existing businesses due primarily to lower salaries and employee benefits expenses.
Operating revenue for 2005 increased $112.0 million, or 6.4%, to $1,868.5 million compared to 2004 resulting in higher gross margin of $33.3 million. The increase in operating revenue was due to growth from existing businesses totaling $62.1 million reflecting primarily higher average sales prices and the results of acquired companies not included in the comparable 2004 period totaling $49.4 million.
Operating income for 2005 increased by $12.4 million due to the aforementioned increase in gross margin, partially offset by higher operating expenses of $24.5 million. Operating expenses increased mainly due to $12.8 million for acquired companies not included in the comparable 2004 period and $11.7 million in higher operating expense at existing businesses due primarily to higher marketing and occupancy costs.
Consolidated Other Income and Expense Items
Interest Expense
Interest expense for the years ended December 31 is summarized as follows (in millions):
Interest expense on subsidiary debt for 2006 increased $224.4 million to $757.7 million compared to 2005 due primarily to PacifiCorp’s interest expense which totaled $223.5 million during the period from acquisition to December 31, 2006. Additionally, interest expense on subsidiary debt was higher in 2006 compared to 2005 due to additional debt at MidAmerican Energy offset by scheduled maturities of debt and principal repayments and a $10.2 million charge incurred in February 2005 to exercise the call option on CE Electric UK debt.
Interest expense on subsidiary debt for 2005 increased $11.8 million to $533.3 million compared to 2004 due mainly to a $10.2 million charge to exercise the call option on CE Electric UK debt, as well as due to additional interest expense on the £350.0 million of 5.125% bonds issued by certain indirect wholly-owned subsidiaries of CE Electric UK in May 2005 and additional debt at MidAmerican Energy. These increases were partially offset by lower interest expense due to maturities of debt and principal repayments.
Interest expense on parent company senior debt for 2006 increased $60.3 million to $233.5 million compared to 2005 due to MEHC’s 6.125% $1,700.0 million debt issuance in March 2006, partially offset by scheduled debt maturities. Interest expense on parent company short-term and senior debt for 2005 decreased $11.6 million to $173.2 million compared to 2004 due primarily to the scheduled redemption of $260.0 million of 7.23% notes in September 2005.
Interest expense on parent company subordinated debt-Berkshire for 2006 decreased $23.5 million to $133.8 million compared to 2005 and decreased $12.6 million to $157.3 million compared to 2004 as a result of scheduled principal repayments.
Other Income, Net
Other income, net for the years ended December 31 is summarized as follows (in millions):
Capitalized interest for 2006 increased $23.0 million to $39.7 million compared to 2005 mainly due to $18.5 million from PacifiCorp and increased levels of capital project expenditures at MidAmerican Energy. Capitalized interest for 2005 decreased $3.3 million to $16.7 million compared to 2004 due to lower capitalization at Northern Electric and Yorkshire Electricity, partially offset by increased levels of capital projects at MidAmerican Energy.
Interest and dividend income for 2006 increased $15.4 million to $73.5 million from the comparable period in 2005 mainly due to $8.9 million from PacifiCorp and earnings on guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) purchased by certain indirect wholly owned subsidiaries of CE Electric UK in May 2005. Interest and dividend income for 2005 increased $19.2 million to $58.1 million compared to 2004 mainly due to earnings on guaranteed investment contracts described previously, as well as earnings on higher cash balances and higher short-term interest rates.
Other income for 2006 increased $164.8 million to $239.3 million compared to 2005. Other income in 2006 included Kern River’s $89.3 million of gains from the sales of Mirant stock and MidAmerican Funding’s $32.1 million of gains from the disposition of common shares held in an electronic energy and metals trading exchange. Also contributing to the increase in other income for 2006 was higher allowance for equity funds used during construction of $30.5 million, primarily due to $17.9 million from PacifiCorp and $12.8 million due largely to increased levels of capital project expenditures at MidAmerican Energy. Excluding the allowance for equity funds used during construction, PacifiCorp also contributed $8.7 million to the increase in other income in 2006.
Other income for 2005 decreased $53.7 million to $74.5 million compared to 2004. In 2005, the Company realized gains from sales of certain non-strategic investments at MidAmerican Funding of $13.4 million and CE Electric UK of $8.4 million. In 2004, the Company recognized a $72.2 million gain on Northern Natural Gas’ sale of an approximately $259 million note receivable with Enron (the “Enron Note Receivable”) and a $14.8 million gain on amounts collected by Kern River on its claim for damages against Mirant. Additionally, the allowance for equity funds used during construction for 2005 increased $5.7 million compared to 2004 due to increased levels of capital project expenditures at MidAmerican Energy.
Other expense for 2006 decreased $9.1 million to $13.0 million compared to 2005 due primarily to losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines of $15.6 million in 2005. Other expense for 2005 increased $12.0 million to $22.1 million compared to 2004 due to the aforementioned impairment losses on investments in commercial passenger aircraft leased to major domestic airlines.
Income Tax Expense
Income tax expense for 2006 increased $162.0 million to $406.7 million compared to 2005. The effective tax rates were 31.1% and 32.0% for 2006 and 2005, respectively. The lower effective tax rate in 2006 was due primarily to the effects of production tax credits related to energy produced by MidAmerican Energy’s wind facilities and lower income taxes on foreign earnings in 2006.
Income tax expense for 2005 decreased $20.3 million to $244.7 million compared to 2004. The effective tax rates were 32.0% and 33.2% for 2005 and 2004, respectively. The lower effective tax rate in 2005 was mainly due to the effects of production tax credits related to energy produced by MidAmerican Energy’s wind facilities and lower income taxes on foreign earnings in 2005, partially offset by a change in the state of Iowa’s income tax laws in 2004 related to bonus depreciation that lowered income tax expense and benefits from CE Electric UK’s settlement of various positions with the Inland Revenue.
Minority Interest and Preferred Dividends of Subsidiaries
Minority interest and preferred dividends of subsidiaries for 2006 increased $12.2 million to $28.2 million compared to 2005 due mainly to higher earnings at CE Casecnan and preferred dividends at PacifiCorp. Minority interest and preferred dividends for 2005 remained relatively flat from the comparable period in 2004.
Equity Income
Equity income for 2006 decreased $9.8 million to $43.5 million compared to 2005 due primarily to lower earnings at CE Generation as a result of higher depreciation and maintenance expenses and lower equity income at HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures.
Equity income for 2005 increased $36.4 million to $53.3 million compared to 2004. The increase was mainly due to higher earnings at CE Generation due to higher energy rates, partially offset by higher fuel costs, mainly at its natural gas-fired generation facilities and increased production at the Imperial Valley Projects due to the timing and length of scheduled outages and lower major maintenance costs, partially offset by higher fuel costs. Additionally, 2004 results included MEHC’s $16.8 million after-tax portion of a charge as a result of the partial impairment of the carrying value of CE Generation’s Power Resources project.
Discontinued Operations
On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. In connection with ceasing operations, the Zinc Recovery Project’s assets have been dismantled and sold and certain employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Implementation of the decommissioning plan began in September 2004 and, as of December 31, 2005, the dismantling, decommissioning, and sale of remaining assets of the Zinc Recovery Project was completed.
The income from discontinued operations, net of income tax, of $5.2 million for the year ended December 31, 2005 reflects the proceeds received from the sale of assets, partially offset by the disposal costs incurred, in connection with the Zinc Recovery Project. The loss from discontinued operations, net of income tax, of $367.6 million for the year ended December 31, 2004 consists primarily of a $340.3 million impairment charge recognized in connection with ceasing the operations of the Zinc Recovery Project.
Liquidity and Capital Resources
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Equity Commitment. 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 securities 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.
Each of MEHC’s direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for its own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC’s will be available to satisfy the obligations of MEHC or any of its other subsidiaries’ obligations. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.
The Company’s cash and cash equivalents and short-term investments, which consist primarily of auction rate securities that are used in the Company’s cash management program, were $357.8 million as of December 31, 2006, compared to $396.3 million as of December 31, 2005. In addition, the Company recorded separately, in restricted cash and short-term investments and in deferred charges and other assets, restricted cash and investments as of December 31, 2006 and 2005 of $162.2 million and $136.7 million, respectively. The restricted cash balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) customer deposits held in escrow, (iii) custody deposits, and (iv) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.
Cash Flows from Operating Activities
The Company generated cash flows from operations of $1,923.2 million for the year ended December 31, 2006 as compared to $1,310.8 million for the comparable period in 2005. The increase was mainly due to the inclusion of $423.4 million of PacifiCorp’s operating cash flows for the period from acquisition to December 31, 2006, more favorable operating results at most other energy businesses and an accrual for rate refunds at Kern River which will likely be paid in 2007, partially offset by lower cash flow from operations at CE Electric UK and HomeServices.
Cash Flows from Investing Activities
Cash flows used in investing activities for the years ended December 31, 2006 and 2005 were $7,321.4 million and $1,551.3 million, respectively. The increase was due primarily to the 2006 acquisition of PacifiCorp, net of cash acquired, for $4,932.4 million; a $1,226.9 million increase in capital expenditures, construction and other development costs due primarily to PacifiCorp capital expenditures of $1,114.4 million for the period from acquisition through December 31, 2006; and a $68.7 million increase in other acquisitions, net of cash acquired. These increases were partially offset by the 2005 purchase of two guaranteed investment contracts by certain indirect wholly owned subsidiaries of CE Electric UK totaling $556.6 million.
PacifiCorp Acquisition
On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5,109.5 million, which was funded through the issuance of common stock. MEHC also incurred $10.6 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees and expenses, resulting in a total purchase price of $5,120.1 million. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.
In the first quarter of 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by MEHC and PacifiCorp include:
·
Approximately $812 million in investments (generally to be made over several years following the sale and subject to subsequent regulatory review and approval) in emissions reduction technology for PacifiCorp’s existing coal plants, which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result in significant reductions in emissions rates of SO2, NOx, and mercury and to avoid an increase in the carbon dioxide emissions rate;
·
Approximately $520 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization; and
·
The addition of 400 MW of cost-effective renewable resources to PacifiCorp’s generation portfolio by December 31, 2007, including 100 MW of cost-effective wind resources by March 21, 2007.
The commitments approved by the state commissions also include credits that will reduce retail rates generally through 2010 to the extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to customers. The maximum potential value of these rate credits to customers in all six states is $142.5 million. PacifiCorp and MEHC have made additional commitments to the state commissions that limit the dividends PacifiCorp can pay to MEHC or its affiliates. As of December 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. As of December 31, 2006, PacifiCorp’s ratio, as calculated pursuant to the requirements of the applicable commitment exceeded the minimum threshold.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings LLC or MEHC if PacifiCorp’s unsecured debt rating is BBB- or lower by Standard & Poor’s Rating Services or Fitch Ratings or Baa3 or lower by Moody’s Investor Service, as indicated by two of the three rating services. At December 31, 2006, PacifiCorp’s unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and Fitch Ratings and Baa1 by Moody’s Investor Service.
Capital Expenditures, Construction and Other Development Costs
Capital expenditures, construction and other development costs were $2,423.1 million for the year ended December 31, 2006, compared with $1,196.2 million for the same period in 2005. The following table summarizes the expenditures by business segment for the years ended December 31 (in millions):
Forecasted capital expenditures, construction and other development costs for fiscal 2007, which exclude the non-cash equity allowance for funds used during construction (“AFUDC”), are approximately $3 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Estimates of environmental capital and operating requirements may change significantly at any time as a result of, among other factors, changes in related regulations, prices of products used to meet the requirements, competition in the industry for similar technology and management’s strategies for achieving compliance with the regulations. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting mainly of recurring expenditures and the funding of growing load requirements, were $1,684.3 million and $796.3 million, respectively, for the years ended December 31, 2006 and 2005. Construction and other development costs were $738.8 million and $399.9 million, respectively, for the years ended December 31, 2006 and 2005. These costs consist mainly of expenditures for large scale generation projects at PacifiCorp and MidAmerican Energy as described below.
PacifiCorp and MidAmerican Energy anticipate a continuing increase in demand for electricity from their regulated customers. To meet existing and anticipated demand and ensure adequate electric generation in their service territory, PacifiCorp and MidAmerican Energy have been and are each continuing to construct major generation projects.
PacifiCorp
In March 2006, PacifiCorp completed construction of the Currant Creek Power Plant, a 540-MW combined-cycle plant in Utah. Total project costs incurred were approximately $343 million. Presently under construction is the Lake Side Power Plant, an estimated 534-MW combined cycle plant in Utah, which is expected to be in service by June 2007. The cost of the Lake Side Power Plant is expected to total approximately $347 million, including approximately $13 million of non-cash equity AFUDC, of which $284.0 million, including $9.6 million of non-cash equity AFUDC, has been incurred through December 31, 2006. Both plants are 100% owned and operated by PacifiCorp.
In July 2006, PacifiCorp entered into an agreement to acquire a 100.5-MW wind energy generation facility that became operational in September 2006. An initial investment in an additional 140.4-MW wind energy generation facility occurred in September 2006 and construction is scheduled to be completed by August 2007. PacifiCorp continues to pursue additional cost-effective wind-powered generation.
Additionally, in conjunction with regulatory commitments made by the Company, approximately $520 million in investments are anticipated being made to PacifiCorp’s transmission and distribution system over the next several years that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. Such investments would be subject to regulatory review and approval.
PacifiCorp’s capital requirements for 2007, which exclude the non-cash equity AFUDC, are estimated to be approximately $1,489 million, which includes $632 million for the generation development projects described above, $127 million for emissions control equipment to address current and anticipated air quality regulations and $730 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.
In conjunction with state regulatory approvals of MEHC’s acquisition of PacifiCorp, MEHC and PacifiCorp committed to invest approximately $812 million, which include the $127 million planned for 2007, in capital spending over several years for emission control equipment to address current and future air quality initiatives implemented by the EPA or the states in which PacifiCorp operates facilities. Additional capital expenditures for emission reduction projects may be required, depending on the outcome of pending or new air quality regulations. In addition to capital expenditure requirements, incremental operating costs are expected to be incurred by PacifiCorp in conjunction with the utilization of the emission control equipment.
MidAmerican Funding
MidAmerican Energy is currently constructing Council Bluffs Unit 4, a 790-MW (expected accreditation) super-critical-temperature, coal-fired generating plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy’s current ownership interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and public power utilities own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. The facility will provide service to regulated retail electricity customers. Wholesale sales may also be made from the facility to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual cost of CBEC Unit 4 in its Iowa rate base as long as the actual cost does not exceed the agreed cap that MidAmerican Energy has deemed to be reasonable. If the cap is exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the cap, subject to regulatory review. MidAmerican Energy expects to invest approximately $870 million in CBEC Unit 4, including transmission facilities and approximately $64 million of non-cash equity AFUDC. Through December 31, 2006, MidAmerican Energy has invested $785.9 million in the plant, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract and $49.2 million of non-cash equity AFUDC.
On April 18, 2006, the IUB approved a settlement agreement between MidAmerican Energy and the OCA regarding ratemaking principles for up to 545 MW (nameplate ratings) of wind-powered generation capacity in Iowa to be installed in 2006 and 2007. In the second half of 2006, MidAmerican Energy placed in service 99 MW (nameplate ratings) of wind-powered generation. In June 2006, MidAmerican Energy entered into agreements to add 123 MW (nameplate ratings) of wind-powered generation by the end of 2007. MidAmerican Energy continues to pursue additional cost effective wind-powered generation.
MidAmerican Energy’s capital requirements for 2007, which exclude the non-cash AFUDC, are estimated to be approximately $926 million, which includes approximately $375 million for the generation development projects discussed above, approximately $150 million for emissions control equipment to address current and anticipated air quality regulations and approximately $401 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.
MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as promulgated by the EPA. The plan allows MidAmerican Energy to more effectively manage its expenditures required to comply with emissions standards. On April 1, 2006, MidAmerican Energy submitted to the IUB an updated plan, as required every two years by Iowa law, which increased its estimate of required expenditures. MidAmerican Energy currently estimates that the incremental capital expenditures for emission control equipment to comply with air quality requirements will total approximately $540 million for January 1, 2007 through December 31, 2015. Additionally, MidAmerican Energy expects to incur significant incremental operating costs in conjunction with the utilization of the emissions control equipment.
HomeServices’ Acquisitions
In 2006, HomeServices separately acquired three real estate companies for an aggregate purchase price of $44.3 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2005, these real estate companies had combined revenue of $149.4 million on approximately 17,600 closed sides representing $5.2 billion of sales volume.
Cash Flows from Financing Activities
Cash flows from financing activities were $5,377.4 million for the year ended December 31, 2006. Sources of cash totaled $7,899.0 million and consisted primarily of $5,131.7 million of proceeds from the issuance of common stock, $1,699.3 million of proceeds from the issuance of parent company senior debt and $717.7 million of proceeds from the issuance of subsidiary and project debt. Uses of cash totaled $2,521.6 million and consisted primarily of $1,750.0 million of repurchases of common stock, $516.5 million for repayments of subsidiary and project debt and $234.0 million for repayments of parent company subordinated debt.
Cash flows used in financing activities were $219.1 million for the year ended December 31, 2005. Uses of cash totaled $1,336.9 million and consisted primarily of $875.4 million for repayments of subsidiary and project debt and $448.5 million for repayments of parent company senior and subordinated debt. Sources of cash totaled $1,117.8 million and consisted primarily of $1,050.6 million of proceeds from the issuance of subsidiary and project debt and $51.0 million of net proceeds from MEHC’s revolving credit facility.
Stock Transactions and Agreements
On March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC’s common equity upon any requests authorized from time to time by MEHC’s Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for future acquisitions.
On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing shareholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s shareholders.
In March 2006, MEHC repurchased 12,068,412 shares of common stock for an aggregate purchase price of $1,750.0 million.
In 2006, 775,000 common stock options were exercised having a weighted average exercise price of $28.65 per share and in 2005, 200,000 common stock options were exercised having an exercise price of $29.01 per share.
Debt Issuances, Redemptions and Maturities
In addition to the debt issuances, redemptions and maturities discussed herein, MEHC and its subsidiaries made scheduled repayments on parent company subordinated debt and subsidiary and project debt totaling approximately $590 million during the year ended December 31, 2006.
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On March 24, 2006, MEHC completed a $1,700.0 million offering of 6.125% unsecured senior bonds due 2036. The proceeds were used to fund MEHC’s exercise of its right to repurchase shares of its common stock previously issued to Berkshire Hathaway.
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On June 15, 2006, MidAmerican Energy’s 6.375% series of notes, totaling $160.0 million, matured.
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On July 6, 2006, MEHC entered into a $600.0 million credit facility pursuant to the terms and conditions of an amended and restated credit agreement. The amended and restated credit agreement remains unsecured, carries a variable interest rate based on LIBOR or a base rate, at MEHC’s option, plus a margin, and the termination date was extended to July 6, 2011. The facility is for general corporate purposes and also continues to support letters of credit for the benefit of certain subsidiaries and affiliates.
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On August 10, 2006, PacifiCorp issued $350.0 million of 6.1%, 30-year first mortgage bonds. The proceeds from this offering were used to repay a portion of PacifiCorp’s short-term debt and for general corporate purposes.
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On October 6, 2006, MidAmerican Energy completed the sale of $350.0 million in aggregate principal amount of its 5.8% medium-term notes due October 15, 2036. The proceeds from this offering are being used to support construction of MidAmerican Energy’s electric generation projects, to repay a portion of its short-term debt and for general corporate purposes.
Debt Issuances, Redemptions and Maturities
In addition to the debt issuances, redemption and maturities discussed herein, MEHC and its subsidiaries made scheduled repayments on parent company subordinated debt and subsidiary and project debt totaling approximately $565 million during the year ended December 31, 2005.
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In February 2005, a subsidiary of CE Electric UK exercised a call option to purchase, and then cancelled, its £155.0 million Variable Rate Reset Trust Securities, due in 2020. A charge to exercise the call option of $10.2 million was recognized in interest expense.
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On February 15, 2005, MidAmerican Energy’s 7% series of mortgage bonds, totaling $90.5 million, was repaid upon maturity.
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On April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125% senior notes due May 1, 2015. The proceeds were used by Northern Natural Gas to repay its outstanding $100.0 million 6.875% senior notes due May 1, 2005.
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On May 5, 2005, Northern Electric Finance plc, an indirect wholly owned subsidiary of CE Electric UK, issued £150.0 million of 5.125% bonds due 2035, guaranteed by Northern Electric and guaranteed as to scheduled payments of principal and interest by Ambac. Additionally, on May 5, 2005, Yorkshire Electricity, a wholly owned subsidiary of CE Electric UK, issued £200.0 million of 5.125% bonds due 2035, guaranteed as to scheduled payments of principal and interest by Ambac. The proceeds from the offerings are being invested and used for general corporate purposes. Investments include a £100.0 million, 4.75%, fixed rate guaranteed investment contract maturing in December 2007 and a £200.0 million, 4.73%, fixed rate guaranteed investment contract maturing in February 2008. The proceeds from the maturing guaranteed investment contracts will be used to repay certain long-term debt of subsidiaries of CE Electric UK. In connection with the issuance of such bonds, CE Electric UK entered into agreements amending certain terms and conditions of its £200.0 million 7.25% bonds due 2022.
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On September 15, 2005, MEHC’s 7.23% senior notes, totaling $260.0 million, were repaid upon maturity.
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On November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75% medium-term notes due in 2035. The proceeds are being used to support construction of its electric generation projects and for general corporate purposes.
Credit Ratings
As of January 31, 2007, MEHC’s senior unsecured debt credit ratings were as follows: Moody’s Investor Service, “Baa1/stable”; Standard and Poor’s, “BBB+/stable”; and Fitch Ratings, “BBB+/stable.”
Debt and preferred securities of MEHC and its subsidiaries may be rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed below, MEHC and its subsidiaries do not have any credit agreements that require termination or a material change in collateral requirements or payment schedule in the event of a downgrade in the credit ratings of the respective company’s securities.
In conjunction with their risk management activities, PacifiCorp and MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern PacifiCorp’s and MidAmerican Energy’s energy supply and marketing activities either specifically require each company to maintain investment grade credit ratings or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s or MidAmerican Energy’s creditworthiness. If one or more of PacifiCorp’s or MidAmerican Energy’s credit ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy supply and marketing activities. As of January 31, 2007, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell below investment grade, PacifiCorp’s and MidAmerican Energy’s estimated potential collateral requirements would total approximately $257 million and $249 million, respectively. PacifiCorp’s and MidAmerican Energy’s potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.
Yorkshire Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect certain currency rate swap agreements for its Yankee bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $281.0 million of 6.496% Yankee bonds outstanding as of December 31, 2006. 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 7.3450%. The estimated fair value of these swap agreements as of December 31, 2006 was $104.7 million based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if YPGL’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of January 31, 2007, YPGL’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been $48.8 million.
Inflation
Inflation has not had a significant impact on the Company’s costs.
Obligations and Commitments
The Company has contractual obligations and commercial commitments that may affect its financial condition. Contractual obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, operating leases and power and fuel purchase contracts. Other obligations and commitments arise from unused lines of credit and letters of credit. Material obligations and commitments as of December 31, 2006 are as follows (in millions):
(1)
The coal, electricity and natural gas contract commitments, owned hydroelectric commitments and operating leases are not reflected on the Consolidated Balance Sheets.
(2)
MidAmerican Energy is allowed to defer up to $200.0 million in payments to the contractor under its contract to build Council Bluffs Unit 4. Approximately 39.3% of this commitment is expected to be funded by the joint owners of Council Bluffs Unit 4.
The Company has other types of commitments that are subject to change and relate primarily to the items listed below. For additional information, refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data.
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Construction and other development costs (Liquidity and Capital Resources included within this Item 7)
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Debt service reserve guarantees (Note 13)
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Asset retirement obligations (Note 12)
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Residual guarantees on operating leases (Note 19)
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Pension and postretirement commitments (Note 20)
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, an amount is recorded on the Company’s Consolidated Balance Sheets 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.
As of December 31, 2006, the Company’s investments that are accounted for under the equity method had long-term debt and letters of credit outstanding of $702.4 million and $90.8 million, respectively. As of December 31, 2006, the Company’s pro-rata share of such long-term debt and outstanding letters of credit was $346.6 million and $45.4 million, respectively. All of the Company’s pro-rata share of the outstanding long-term debt is non-recourse to the Company. $35.2 million of the Company’s pro-rata share of the outstanding letters of credit is recourse to the Company and is included in the Obligations and Commitments table. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse long-term debt could result in a loss of invested equity.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.
Critical Accounting Policies
Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled in the future. Amounts recognized in the financial statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the financial statements will likely increase or decrease in the future as additional information becomes available. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated Businesses”) prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”) which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.
Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based rate making to another form of regulation, other regulatory actions or the impact of competition which could limit the Company’s ability to recover its costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes no longer probable that these costs will be recovered, the regulatory assets and regulatory liabilities would be written off and recognized in operating income. Total regulatory assets were $1,827.2 million and total regulatory liabilities were $1,838.7 million as of December 31, 2006. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding the Company’s regulatory assets and liabilities.
Derivatives
The Company is exposed to variations in the market prices of electricity and natural gas, foreign currency and interest rates and uses derivative instruments, including forward purchases and sales, futures, swaps and options to manage these inherent market price risks.
Measurement Principles
Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualifying for the normal purchases and normal sales exemptions afforded by GAAP. The fair values of derivative instruments are determined using forward price curves. Forward price curves represent the Company’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations when available and uses internally developed, modeled prices when market quotations are unavailable. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contracts.
Classification and Recognition Methodology
The majority of the Company’s contracts are either probable of recovery in rates and therefore recorded as a net regulatory asset or liability or are accounted for as cash flow hedges and therefore recorded as accumulated other comprehensive income. Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2006, the Company had $244.2 million recorded as net regulatory assets and $29.2 million recorded as accumulated other comprehensive income, net of tax, related to these contracts in the Consolidated Balance Sheets. If it becomes no longer probable that a contract will be recovered in rates, the regulatory asset will be written-off and recognized in earnings. For contracts designated in hedge relationships (“hedge contracts”), the Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in accumulated other comprehensive income will remain there until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in accumulated other comprehensive income are immediately recognized in earnings.
Impairment of Long-Lived Assets and Goodwill
The Company evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. For non-regulated assets, any resulting impairment loss is reflected in the Consolidated Statement of Operations.
The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from, but are not limited to, significant changes in the market price of the asset, the use of the asset, management’s plans, legal factors, the business climate or the physical condition of the asset. An impairment analysis of generating facilities or pipelines requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. Any resulting impairment loss is highly dependent on those underlying assumptions and could significantly affect the Company’s results of operations.
The Company’s Consolidated Balance Sheet as of December 31, 2006 includes goodwill of acquired businesses of $5.3 billion. Goodwill is allocated to each reporting unit and is tested for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are charged to earnings. The Company completed its annual review as of October 31. A significant amount of judgment is required in performing goodwill impairment tests. Key assumptions used in the testing include, but are not limited to, the use of an appropriate discount rate and estimated future cash flows. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating cash flows, the Company incorporates current market information as well as historical factors.
During 2005 and 2004, the Company recognized impairments on certain of its long-lived assets and goodwill. For additional discussion of these impairments, refer to Notes 4 and 17 of Notes to Consolidated Financial Statements Included in Item 8. Financial Statements and Supplementary Data.
Accrued Pension and Postretirement Expense
The Company sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. Effective with the adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” as of December 31, 2006, the funded status of defined benefit pension and postretirement plans must be recognized in the balance sheet. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2006, the Company recognized an asset totaling $66.6 million for the over-funded status and a liability totaling $838.7 million for the under-funded status for the Company’s defined benefit pension and other postretirement benefit plans.
The expense and benefit obligations relating to these pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets, and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries. Refer to Note 20 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for disclosures about the Company’s pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic cost for these plans as of and for the period ended December 31, 2006.
In establishing its assumption as to the expected return on assets, the Company reviews the expected asset allocation and develops return assumptions for each asset class based on historical performance and independent advisors’ forward-looking views of the financial markets. Pension and other postretirement benefit expenses increase as the expected rate of return on retirement plan and other postretirement benefit plan assets decreases. The Company regularly reviews its actual asset allocations and periodically rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a discount rate based upon high quality fixed-income investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.
The Company chooses a health care cost trend rate which reflects the near and long-term expectations of increases in medical costs. The health care cost trend rate gradually declines to 5% in 2010 through 2012 at which point the rate is assumed to remain constant. Refer to Note 20 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for health care cost trend rate sensitivity disclosures.
The actuarial assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded. If changes were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:
A variety of factors, including the plan funding practices of the Company, affect the funded status of the plans. The Pension Protection Act of 2006 imposed generally more stringent funding requirements for defined benefit pension plans, particularly for those significantly under-funded, and allowed for greater tax deductible contributions to such plans than previous rules permitted under the Employee Retirement Income Security Act. As a result of the Pension Protection Act of 2006, the Company does not anticipate any significant changes to the amount of funding previously anticipated through 2007; however, depending on a variety of factors which impact the funded status of the plans, including asset returns, discount rates and plan changes, the Company may be required to accelerate contributions to its domestic pension plans for periods after and there may be more volatility in annual contributions than historically experienced, which could have a material impact on cash flows.
Income Taxes
In determining the Company’s tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax returns, the Company is subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Internal Revenue Service has closed examination of the Company’s income tax returns through 2001. Although the ultimate resolution of the Company’s federal and state tax examinations is uncertain, the Company believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, is not expected to have a material adverse affect on the Company’s financial results.
Both PacifiCorp and MidAmerican Energy are required to pass income tax benefits related to certain accelerated tax depreciation and other property-related basis differences on to their customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $581.0 million as of December 31, 2006, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory assets are probable of recovery. If it becomes probable that these costs will not be recovered, the assets would be written-off and recognized in earnings.
The Company has not provided U.S. deferred income taxes on its currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations were approximately $1.1 billion as of December 31, 2006. Because of the availability of U.S. foreign tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to remit those earnings. The Company periodically evaluates its cash requirements in the U.S. and abroad and evaluates its short-term and long-term operational and fiscal objectives in determining whether the earnings of its foreign subsidiaries are indefinitely invested outside the U.S. or will be remitted to the U.S. within the foreseeable future.
Revenue Recognition - Unbilled Revenue
Unbilled revenues were $407.3 million as of December 31, 2006. Historically, any differences between the actual and estimated amounts have been immaterial.
Electric and Natural Gas Retail Revenues and Electric Distribution Revenues
Revenue from electric customers is recognized as electricity is delivered and includes amounts for services rendered. Revenue from the sale and distribution of natural gas is recognized when either the service is provided or the product is delivered.
For PacifiCorp and MidAmerican Energy, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, PacifiCorp and MidAmerican Energy record unbilled revenues representing an estimate of the amount customers will be billed for energy provided between the meter-reading dates and the end of that month. This estimate is reversed in the following month and actual revenue is recorded based on subsequent meter readings.
The monthly unbilled revenues of PacifiCorp and MidAmerican Energy are determined by the estimation of unbilled energy provided during the period, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Factors that can impact the estimate of unbilled energy provided include, but are not limited to, seasonal weather patterns, historical trends, line losses, economic impacts and composition of customer classes.
The distribution businesses in Great Britain record unbilled revenue representing the estimated amounts that customers will be billed for electricity distributed during the period based upon information received from the national settlement system.
Natural Gas Transportation and Storage
The majority of the pipelines’ transportation and storage revenue is derived from fixed reservation charges based on contractual quantities and rates. The remaining revenue, consisting primarily of commodity charges, is based on contractual rates and actual or estimated usage. The usage is based on scheduled quantities and is subject to volume estimates, which include estimates of meter readings and lost and unaccounted for volumes.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s Consolidated Balance Sheets include assets and liabilities whose fair values are subject to market risks. The Company’s significant market risks are primarily associated with commodity prices, currency exchange rates and interest rates. The following sections address the significant market risks associated with the Company’s business activities. The Company also has established guidelines for credit risk management. Refer to Notes 2 and 14 of Notes to Consolidated Financial Statements included in Item 8.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
MidAmerican Energy Holdings Company
Des Moines, Iowa
We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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, the Company adopted Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R),” as of December 31, 2006.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
February 27, 2007
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
(Amounts in millions)
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
MidAmerican Energy Holdings Company (“MEHC”) is a holding company owning subsidiaries (together with MEHC, the “Company”) that are principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The Company is organized and managed as eight distinct platforms: PacifiCorp (which was acquired on March 21, 2006), MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (the subsidiaries owning the Malitbog and Mahanagdong Projects (collectively the “Leyte Projects”) and the Casecnan Project), CalEnergy Generation-Domestic (the subsidiaries owning interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.
(2) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest. The Consolidated Statements of Operations include the revenues and expenses of an acquired entity from the date of acquisition.
Intercompany accounts and transactions have been eliminated.
Reclassifications
Certain amounts in the fiscal 2005 and 2004 Consolidated Financial Statements and supporting note disclosures have been reclassified to conform to the fiscal presentation. As of December 31, 2005, the Company reclassified $1.6 billion of accumulated depreciation related to the acquisitions of Northern Natural Gas and Kern River from gross property to accumulated depreciation.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. These estimates include, but are not limited to, unbilled receivables, valuation of energy contracts, the effects of regulation, long-lived asset recovery, goodwill impairment, the accounting for contingencies, including environmental, regulatory and income tax matters, and certain assumptions made in accounting for pension and postretirement benefits. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Cash Equivalents
Cash equivalents consist of funds invested in commercial paper, money market securities and in other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where the availability for distribution is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in restricted cash and short-term investments and deferred charges and other assets in the accompanying Consolidated Balance Sheets.
Investments
The Company’s management determines the appropriate classification of investments in debt securities and equity securities at the acquisition date and re-evaluates the classifications at each balance sheet date. The Company’s investments in debt and equity securities are primarily classified as available-for-sale.
Held-to-maturity investments are carried at amortized cost, reflecting the Company’s intent and ability to hold the securities to maturity. Available-for-sale securities are stated at fair value with realized gains and losses, as determined on a specific identification basis, recognized in earnings and unrealized gains and losses recognized in accumulated other comprehensive income (“AOCI”), net of tax, except for realized and unrealized gains and losses on certain trust funds related to the decommissioning of nuclear generation assets and the final reclamation of leased coal mining property. Realized and unrealized gains and losses on these trust funds are recorded as regulatory assets or liabilities since the Company expects to recover costs for these activities through rates.
The Company utilizes the equity method of accounting with respect to investments where it exercises significant influence, but not control, over the operating and financial policies of the investee. The equity method of accounting is normally applied where the Company has a voting interest of at least 20% and no greater than 50%. In applying the equity method, investments are recorded at cost and subsequently increased or decreased by the Company’s proportionate share of the net earnings or losses of the investee. The Company also records a proportionate share of other comprehensive income items of the investee as a component of its other comprehensive income. Dividends or other equity distributions are recorded as a reduction of the investment. Equity investments are required to be tested for impairment when it is determined that an other-than-temporary loss in value below the carrying amount has occurred.
Accounting for the Effects of Certain Types of Regulation
PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated Businesses”) prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”) which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.
Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based rate making to another form of regulation, other regulatory actions or the impact of competition which could limit the Company’s ability to recover its costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. If it becomes no longer probable that these costs will be recovered, the regulatory assets and regulatory liabilities would be written off and recognized in operating income.
Allowance for Doubtful Accounts
The allowance for doubtful accounts is based on the Company’s assessment of the collectibility of payments from its customers. This assessment requires judgment regarding the outcome of pending disputes, arbitrations and the ability of customers to pay the amounts owed to the Company. At December 31, 2006 and 2005, the allowance for doubtful accounts totaled $30.4 million and $21.4 million, respectively.
Amounts Held in Trust
Amounts held in trust consist of separately designated trust accounts for homebuyers’ earnest money and other deposits, which are held until pending sales of properties are closed. Subsequent disbursements are made in accordance with the settlement instructions.
Derivatives
The Company employs a number of different derivative instruments in connection with its electric and natural gas, foreign currency exchange rate and interest rate risk management activities, including forward purchases and sales, futures, swaps and options. Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualify for the normal purchases and normal sales exemptions afforded by GAAP. Derivative contracts for commodities used in the Company’s normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases and normal sales pursuant to the exemption provided by GAAP. Recognition of these contracts in operating revenue or cost of sales in the Consolidated Statements of Operations occurs when the contracts settle.
For contracts designated in hedge relationships (“hedge contracts”), the Company maintains formal documentation of the hedge. In addition, at inception and on a quarterly basis, the Company formally assesses whether the hedge contracts are highly effective in offsetting changes in cash flows or fair values of the hedged items. The Company documents hedging activity by transaction type and risk management strategy.
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Shareholders’ Equity as AOCI, net of tax, until the hedged item is recognized in earnings. The Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.
Certain derivative electric and gas contracts utilized by the regulated operations of PacifiCorp and MidAmerican Energy are recoverable through rates. Accordingly, unrealized changes in fair value of these contracts are deferred as net regulatory assets or liabilities pursuant to SFAS No. 71.
When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts without available quoted market prices, fair value is determined based on internally developed modeled prices.
Inventories
Inventories consist mainly of materials and supplies, coal stocks, gas in storage and fuel oil, which are valued at the lower of cost or market. The cost of materials and supplies, coal stocks and fuel oil is determined primarily using average cost. The cost of gas in storage is determined using the last-in-first-out (“LIFO”) method. With respect to inventories carried at LIFO cost, the cost determined under the first-in-first-out method would be $76.4 million and $125.0 million higher as of December 31, 2006 and 2005, respectively.
Property, Plant and Equipment, Net
General
Property, plant and equipment is recorded at historical cost. The Company capitalizes all construction related material, direct labor costs and contract services, as well as indirect construction costs, which include capitalized interest and equity AFUDC. The cost of major additions and betterments are capitalized, while costs for replacements, maintenance, and repairs that do not improve or extend the lives of the respective assets are charged to operating expense. Depreciation and amortization are generally computed by applying the straight-line method based on estimated economic lives or regulatorily mandated recovery periods. The Company believes the useful lives assigned to the depreciable assets, which range from 3 to 85 years, are reasonable.
When the Company retires its regulated property, plant and equipment, it charges the original cost to accumulated depreciation. The cost of removal is charged against the cost of removal regulatory liability that was established through depreciation rates. Generally, when regulated assets are sold, the cost is removed from the property accounts, the related accumulated depreciation and amortization accounts are reduced and the residual gain or loss is deferred and subsequently amortized through future depreciation rates. Any gain or loss on disposals of assets from non-regulated businesses is recorded in income or expense.
The Domestic Regulated Businesses record AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of domestic regulated facilities. AFUDC is capitalized as a component of property, plant and equipment cost, with offsetting credits to the accompanying Consolidated Statements of Operations. After construction is completed, the Company is permitted to earn a return on these costs by their inclusion in rate base, as well as recover these costs through depreciation expense over the useful life of the related assets.
Asset Retirement Obligations
The Company recognizes legal asset retirement obligations (“ARO”), mainly related to the decommissioning of nuclear generation assets and the final reclamation of leased coal mining property. The fair value of a liability for a legal ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the liability is adjusted for any material revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability. Estimated removal costs that PacifiCorp and MidAmerican Energy recover through approved depreciation rates, but that do not meet the requirements of a legal ARO are accumulated in asset retirement removal costs within regulatory liabilities in the accompanying Consolidated Balance Sheets.
Impairment
The Company evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. For assets of non-regulated businesses, any resulting impairment loss is reflected in the Consolidated Statement of Operations.
Goodwill
Goodwill represents the difference between purchase cost and the fair value of net assets acquired in business acquisitions. Goodwill is allocated to each reporting unit and is tested for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are charged to earnings. The Company completed its annual review as of October 31. Key assumptions used in the testing include, but are not limited to, the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, the Company incorporates current market information as well as historical factors. During 2006 and 2005, the Company did not record any goodwill impairments.
The Company records goodwill adjustments for (i) changes in the estimates or the settlement of tax bases of acquired assets, liabilities and carryforwards and items relating to acquired entities’ prior income tax returns, (ii) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill, and (iii) changes to the purchase price allocation prior to the end of the allocation period, which is generally one year from the acquisition date.
Revenue Recognition
Energy Businesses
Revenue from electric customers is recognized as electricity is delivered and includes amounts for services rendered. Revenue from the sale, distribution and transportation of natural gas is recognized when either the service is provided or the product is delivered. Revenue recognized includes unbilled as well as billed amounts.
Rates charged by the domestic regulated energy businesses are subject to federal and state regulation. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a provision for estimated refunds is accrued. Electric distribution revenues in the U.K. are limited to amounts allowed under their regulatory formula while under-recoveries are not recognized in revenue. Over- or under-recoveries of amounts allowed under the regulatory formula are either refunded to customers or recovered through adjustments in future rates.
Electricity and water is delivered in the Philippines pursuant to provisions of the respective project agreements which are accounted for as arrangements that contain both a lease and a service contract. The leases are classified as operating due to significant uncertainty regarding the collection of future amounts mainly due to the existence of political, economic and other uncertainties in the Philippines. The majority of the revenue under these arrangements is fixed.
Real Estate Commission Revenue and Related Fees
Commission revenue from real estate brokerage transactions and related amounts due to agents are recognized when a real estate transaction is closed. Title fee revenue from real estate transactions and related amounts due to the title insurer are recognized at closing.
Unamortized Debt Premiums, Discounts and Financing Costs
Premiums, discounts and financing costs incurred during the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Foreign Currency
The accounts of foreign-based subsidiaries are measured in most instances using the local currency as the functional currency. Revenue and expenses of these businesses are translated into U.S. dollars at the average exchange rate for the period. Assets and liabilities are translated at the exchange rate as of the end of the reporting period. Gains or losses from translating the financial statements of foreign-based operations are included in shareholders’ equity as a component of AOCI. Gains or losses arising from other transactions denominated in a foreign currency are included in the accompanying Consolidated Statements of Operations.
Income Taxes
Berkshire Hathaway commenced including the Company in its U.S. federal income tax return in 2006 as a result of converting its convertible preferred stock of MEHC into shares of MEHC common stock on February 9, 2006. The Company’s provision for income taxes has been computed on a stand-alone basis. Prior to the conversion, the Company filed a consolidated U.S. federal income tax return.
Deferred tax assets and liabilities are based on differences between the financial statements and tax bases of assets and liabilities using the estimated tax rates in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income are charged or credited directly to other comprehensive income. Otherwise, changes in deferred income tax assets and liabilities are included as a component of income tax expense. Valuation allowances have been established for certain deferred tax assets where management has judged that realization is not likely.
Both PacifiCorp and MidAmerican Energy are required to pass income tax benefits related to certain accelerated tax depreciation and other property-related basis differences on to their customers in most state jurisdictions. These amounts were recognized as a net regulatory asset of $581.0 million as of December 31, 2006 and $146.0 million as of December 31, 2005, and will be included in rates when the temporary differences reverse. Management believes the existing net regulatory asset is probable of recovery.
Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties or as prescribed by various regulatory jurisdictions.
The Company has not provided U.S. federal deferred income taxes on its currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations were approximately $1.1 billion as of December 31, 2006. Because of the availability of U.S. foreign tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to remit those earnings.
In determining the Company’s tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax returns, the Company is subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Internal Revenue Service has closed examination of the Company’s income tax returns through 2001. Although the ultimate resolution of the Company’s federal and state tax examinations is uncertain, the Company believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, will not have a material adverse affect on the Company’s financial results. The Company’s provision for tax uncertainties is included in accrued property and other taxes and other long-term accrued liabilities, as appropriate, in the accompanying Consolidated Balance Sheets.
New Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS No. 158”). SFAS No. 158 requires an employer to recognize in its statement of financial position the over- or under-funded status of a defined benefit postretirement plan measured as the difference between the fair value of plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation; for any other postretirement benefit plan, such as a retiree health care plan, the benefit obligation is the accumulated postretirement benefit obligation. SFAS No. also requires entities to recognize as a component of other comprehensive income, net of tax, the actuarial gains and losses and the prior service costs and credits that arise during the period, but were not recognized as components of net periodic benefit cost of the period pursuant to SFAS No. 87, “Employers' Accounting for Pensions” (“SFAS No. 87”) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS No. 106”). The Company recognized as regulatory assets (liabilities) the majority of the amounts attributable to its domestic regulated operations that would otherwise be recorded to AOCI, net of tax, pursuant to SFAS No. 71. SFAS No. 158 does not impact the calculation of net periodic benefit cost and the amounts recognized in either AOCI or regulatory assets (liabilities) will be adjusted as they are subsequently recognized as components of net periodic benefit cost pursuant to the recognition and amortization provisions of SFAS No. 87 and SFAS No. 106.
The Company adopted the recognition and related disclosure provisions of SFAS No. 158 as of December 31, 2006. The incremental impact to the accompanying Consolidated Balance Sheet of such adoption is as follows (in millions):
Immediately prior to the initial adoption of SFAS No. 158, an after-tax benefit of $338.4 million was recorded in other comprehensive income which reduced the additional minimum pension liability recorded under SFAS No. 87. This benefit to shareholders’ equity related primarily to the elimination of CE Electric UK’s additional minimum pension liability as the market value of the plan assets was greater than the accumulated benefit obligation at that date. This increase to shareholders' equity is reflected in the “Before SFAS No. 158” column in the table above.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115” ("SFAS No. 159"). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of adopting SFAS No. 159 on its consolidated financial position and results of operations.
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a return. Guidance is also provided on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company is required to adopt FIN 48 in the first quarter of fiscal year 2007. The Company is currently evaluating the impact and based upon its assessment to date does not believe the adoption of FIN 48 will have a material effect on its consolidated financial position.
(3) PacifiCorp Acquisition
General
In May 2005, MEHC reached a definitive agreement with Scottish Power plc (“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary, PacifiCorp. On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5,109.5 million, which was funded through the issuance of common stock (see Note 18). MEHC also incurred $10.6 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees, resulting in a total purchase price of $5,120.1 million. As a result of the acquisition, MEHC controls the significant majority of PacifiCorp’s voting securities, which include both common and preferred stock. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006 (the “acquisition date”).
PacifiCorp is a regulated electric utility serving approximately 1.7 million residential, commercial and industrial customers in service territories in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities.
Allocation of Purchase Price
SFAS No. 141, “Business Combinations,” requires that the total purchase price be allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. PacifiCorp’s operations are regulated, which provide revenue derived from cost, and are accounted for pursuant to SFAS No. 71. PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Certain adjustments related to derivative contracts, severance costs and income taxes have been made through December 31, 2006, which were not significant to the overall purchase price allocation. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions).
(1)
$51.2 million of total regulatory assets, represent net unrealized losses related to derivative contracts that are probable of recovery in retail rates as of the acquisition date. In February 2006 in Oregon and in March 2006 in Utah, PacifiCorp filed rate cases to ensure, among other items, that PacifiCorp would achieve recovery of its future net power costs. Actual rate case settlements were achieved in both states during the third quarter of 2006. Based on management’s consideration of the rate settlements, as well as the new power costs recovery adjustment mechanisms obtained in Wyoming and California earlier in 2006, it was determined that certain contracts were probable of being recovered in retail rates as of the acquisition date. Accordingly, the Company recorded a $43.5 million reduction to its regulatory assets and a corresponding increase to goodwill related to its estimate of the unrealized gains on contracts receiving recovery.
The Company has not identified any material pre-acquisition contingencies where the related asset, liability or impairment is probable and the amount of the asset, liability or impairment can be reasonably estimated. The Company will adjust goodwill prospectively for the settlement of any income tax related pre-acquisition contingencies. Prior to the end of the purchase price allocation period, if information becomes available that a non-income tax related pre-acquisition related loss had been incurred and the amounts can be reasonably estimated, such items will be included in the purchase price allocation.
Certain transition activities, pursuant to established plans, were undertaken as PacifiCorp was integrated into the Company. Costs, consisting primarily of employee termination activities, have been incurred associated with such transition activities, which have been substantially completed as of December 31, 2006. The finalization of certain integration plans resulted in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Qualifying severance costs accrued during the period from the acquisition date to December 31, 2006 totaled $40.7 million. Accrued severance costs were $31.3 million as of December 31, 2006.
Goodwill
The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1,118.1 million and was allocated as goodwill to the PacifiCorp reportable segment. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. Deferred taxes are not recorded on the goodwill since it is not tax deductible.
The recognition of goodwill from the acquisition of PacifiCorp resulted from various attributes of PacifiCorp’s operations and business in general. There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition. These attributes include, but are not limited to:
·
Ability to improve operational results through the prudent deployment of capital;
·
Operations in six states providing regulatory and geographic diversity;
·
Ability to improve regulatory relationships and develop customer solutions;
·
Low-cost competitive position;
·
Generation and fuel diversification, including:
·
The operation of coal generation;
·
The operation of several coal mines contributing to low-cost supply and supply certainty;
·
Access to multiple gas suppliers; and
·
Low-cost hydroelectric generation;
·
Strong customer service reputation; and
·
Significant customer and load growth opportunities.
Pro Forma Financial Information
The following pro forma condensed consolidated results of operations assume that the acquisition of PacifiCorp was completed as of January 1, 2005 and provides information for the years ended December 31 (in millions):
The pro forma financial information represents the historical operating results of the combined company with adjustments for purchase accounting and is not necessarily indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of each period presented.
(4) Property, Plant and Equipment, Net
Property, plant and equipment, net consist of the following as of December 31 (in millions):
Substantially all of the construction in progress as of December 31, 2006 and 2005 relates to the construction of regulated assets.
Northern Natural Gas entered into a purchase and sale agreement for the West Hugoton non-strategic section of its interstate pipeline system in the fourth quarter of 2005. As a result of entering into the purchase and sale agreement, Northern Natural Gas recognized a non-cash impairment charge of $29.0 million ($17.5 million after-tax) to write down the carrying value of the asset to its fair value. The fair value was determined based on the agreed sale price. The impairment charge is recorded in operating expense in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005.
(5) Jointly Owned Utility Plant
Under joint plant ownership agreements with other utilities, both PacifiCorp and MidAmerican Energy, as a tenants in common, have undivided interests in jointly owned generation and transmission facilities. The Company accounts for its proportional share of each facility. Operating costs of each plant are assigned to joint owners based on ownership percentage or energy purchased, depending on the nature of the cost. Operating expenses in the accompanying Consolidated Statements of Operations include the Company’s share of the expenses of these units.
The amounts shown in the table below represent the Company’s share in each jointly owned facility as of December 31, 2006 (dollars in millions):
(6) Regulatory Matters
Regulatory Assets and Liabilities
Regulatory assets represent costs that are expected to be recovered in future rates. The Company’s regulatory assets reflected in the accompanying Consolidated Balance Sheets consist of the following as of December 31 (in millions):
(1)
Amounts represent income tax benefits related to certain accelerated tax depreciation, property-related basis differences and other various differences that were previously flowed through to customers and will be included in rates when the temporary differences reverse.
(2)
Amounts represent unrecognized components of benefit plans’ funded status that are recoverable in rates when recognized in net periodic benefit cost.
(3)
Amounts represent net unrealized losses related to derivative contracts included in rates.
The Company had regulatory assets not earning a return or earning less than the stipulated return as of December 31, 2006 and 2005 of $1,722.6 million and $400.8 million, respectively.
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company’s regulatory liabilities reflected in the accompanying Consolidated Balance Sheets consist of the following as of December 31 (in millions):
(1)
Amounts are deducted from rate base or otherwise accrue a carrying cost.
(2)
Amounts represent the remaining estimated costs, as accrued through depreciation rates, of removing electric utility assets in accordance with accepted regulatory practices.
(3)
Amounts represent unrecognized components of benefit plans’ funded status that are to be returned to customers in future periods when recognized in net periodic benefit cost.
Rate Matters
Oregon Senate Bill 408
In September 2005, Oregon’s governor signed into law Senate Bill 408. This legislation is intended to address differences between income taxes collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or consolidated groups in which utilities are included for income tax reporting purposes.
Oregon Senate Bill 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provided electric or natural gas service to Oregon customers file an annual tax report with the Oregon Public Utility Commission (“OPUC”). Among other information, the tax report must contain (i) the amount of taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, and (ii) the amount of taxes “authorized to be collected in rates.” If the OPUC determines that the amount of taxes “authorized to be collected” differs by more than $100,000 from the amount of taxes paid, in either direction, the OPUC will require the public utility to implement a rate schedule with an automatic adjustment clause resulting in an increase or a decrease on customer bills. The law is applicable for years beginning on or after January 1, 2006. The first tax report that can result in a rate adjustment will be filed on or before October 15, 2007 with the resulting increase or decrease, if any, implemented in rates on or before June 1, 2008.
The final administrative rules define the amount of federal, state, and local taxes paid by the utility, or paid by the affiliated group and “properly attributed” to the regulated operations of the utility, as the lowest of: (i) the total tax liability of the affiliated group of which the utility is a member; (ii) the standalone tax liability of the utility; or (iii) the tax liability calculated using the “apportionment method.” The “apportionment method” uses an evenly weighted three-factor formula premised on property, payroll and sales, with amounts for the regulated operations of the utility in the numerator and amounts for the affiliated group in the denominator, to generate an allocation factor that is applied against the tax liability of PacifiCorp’s respective affiliated group in order to “apportion” part of that tax liability to the regulated operations of the utility. For federal purposes, the affiliated group of which PacifiCorp is a member is Berkshire Hathaway and its subsidiaries. For state and local purposes, the affiliated group differs based upon jurisdictional filing requirements.
As a result of the law and the final administrative rules, the tax liability of the affiliated group of which PacifiCorp is a member and the affiliated group’s impact on the factor determined under the “apportionment method” may impact the amount of taxes paid and “properly attributed” to PacifiCorp. PacifiCorp cannot predict the financial results and the related impact of its federal affiliated group, Berkshire Hathaway and subsidiaries, and therefore, cannot determine the impact this law may have on its consolidated financial results.
Additionally, the calculation of “taxes authorized to be collected in rates,” as defined by the OPUC, is based upon assumptions in the latest rate case(s) used to set rates for the respective financial reporting period. As such, “taxes authorized to be collected in rates” does not reflect actual tax collections. The resulting difference between actual tax collections and the amount deemed collected pursuant to Oregon Senate Bill 408 may be a benefit or detriment to PacifiCorp and cannot be reasonably predicted.
The OPUC recognizes that a potential conflict between its rules and federal Internal Revenue Code regulations could deny PacifiCorp the tax benefits of accelerated depreciation. As such, at the request of the OPUC in December 2006, PacifiCorp and the other affected utilities filed requests for private letter rulings from the Internal Revenue Service on this issue, which may result in further changes to the rule or underlying law.
Oregon Senate Bill 408 cannot be used to decrease utility rates below a fair and reasonable level and the final administrative rules expressly provide that a utility may challenge any adjustment resulting in rates that are not fair, just and reasonable resulting in confiscatory rates.
PacifiCorp continues to evaluate its legal and legislative options with respect to Oregon Senate Bill 408.
In September 2005, the OPUC issued an order granting a general rate increase of $25.9 million, or an average increase of 3.2%, effective October 2005. The OPUC’s order reduced PacifiCorp’s revenue requirement by $26.6 million (and therefore denied any related further rate increase) based on the OPUC’s interpretation of Senate Bill 408. In October 2005, PacifiCorp filed with the OPUC a motion for reconsideration and rehearing of the rate order generally on the basis that the tax adjustment was not made in compliance with applicable law. With the motion, PacifiCorp also filed a deferred accounting application with the OPUC to track revenues related to the disallowed tax expenses. In July 2006, a final order was issued by the OPUC affirming its initial application of Senate Bill 408. The order also modified the tax adjustment, resulting in an additional annual increase in PacifiCorp’s revenue of $6.1 million effective July 2006, as well as granting deferred accounting for the period from October 2005 to July 2006. In September 2006, PacifiCorp filed an application for deferred accounting treatment of the remainder of the tax adjustment, pending the outcome of the permanent rulemaking for Senate Bill 408. This application was necessary to ensure that PacifiCorp is allowed the opportunity to recover any revenue shortfall related to its allocated tax expense in rates for 2006, to the extent any such revenue shortfall is not recovered through the Senate Bill 408 automatic adjustment clause. Because the result of the automatic adjustment clause will not be known until after the October 2007 tax reports are filed, PacifiCorp’s application for deferred accounting of the remainder of the tax adjustment will be postponed until fall 2007.
Iowa Electric Revenue Sharing
Under a series of electric settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate and other interveners approved by the Iowa Utilities Board (“IUB”), MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2013, unless its Iowa jurisdictional electric return on equity in any year falls below 10%. Under the settlement agreements, MidAmerican Energy has agreed to share revenue based upon certain predetermined return on equity thresholds. MidAmerican Energy agreed to share revenues through December 31, 2005 at 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%. From January 1, 2006 to December 31, 2012, MidAmerican Energy has agreed to share amounts equal to 40% of revenues associated with returns on equity between 11.75% and 13%, 50% of revenues associated with returns on equity between 13% and 14%, and 83.3% of revenues associated with returns on equity above 14%. Separate regulatory liability accounts are maintained by year.
The regulatory liabilities created by the settlement agreements are recorded as a regulatory charge in depreciation and amortization expense when the liability is accrued. Additionally, interest expense is accrued on the portion of the regulatory liability balance recorded in prior years. Regulatory liabilities created for the years through 2010 will be reduced as they are credited against plant in service associated with generating plant additions. As a result of such credits applied to generating plant balances, future depreciation will be reduced. The regulatory liability accrued for 2011 and 2012, if any, will be credited to customer bills in 2012 and 2013.
Refund Matters
PacifiCorp
PacifiCorp is a party to a Federal Energy Regulatory Commission (“FERC”) proceeding that is investigating potential refunds for energy transactions in the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices in 2000 and 2001. PacifiCorp has reserved for these potential refunds. Also in that time period, PacifiCorp experienced defaults of amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator and California Power Exchange as a result of California market conditions. PacifiCorp has reserved for these receivables. As part of the global settlement process underway in the FERC proceeding, as sponsored by the United States Court of Appeals for the Ninth Circuit and the FERC, PacifiCorp has been working with the California parties in an effort to explore settlement of these claims.
Northern Natural Gas
On May 1, 2003, Northern Natural Gas filed a general rate case proceeding for increased rates with the FERC and filed an additional rate case proceeding on January 30, 2004 to reflect further cost increases. The FERC consolidated the 2003 and 2004 rate cases due to the similarity of issues in both cases and the updated costs. On March 25, 2005, as modified on April 22, 2005, Northern Natural Gas filed a stipulation and agreement with the FERC (the “Settlement”) resolving the consolidated rate cases. On June 20, 2005, the FERC approved the Settlement without modification. The Settlement represents the agreement Northern Natural Gas reached with its customers to settle the base tariff rates and related tariff issues in the consolidated cases. The Settlement provided for, among other things, rates designed to generate revenues on an annual basis above the base rates which were in effect as of October 31, 2003, as follows: $48 million for the period November 1, 2003 through October 31, 2004, $53 million for the period November 1, 2004 through October 31, 2005, $58 million for the period November 1, 2005 through October 31, 2006, and $62 million beginning November 1, 2006. Northern Natural Gas provided refunds including interest of $71.5 million to its customers in the third quarter of 2005 consistent with the terms of the Settlement, reflecting the difference between the rate increases implemented on November 1, 2003 and November 1, 2004 and the revenue generated using the Settlement rates.
In April 2004, Northern Natural Gas also filed tariff sheets with the FERC in relation to its system levelized account (“SLA”) (an imbalance recovery mechanism) with the new rates going into effect on June 1, 2004, subject to refund. On February 14, 2005, Northern Natural Gas received FERC approval of the SLA settlement. The SLA settlement provides for recovery of the final SLA balance as of December 31, 2004, over a forty-eight month period beginning November 1, 2003. Under the SLA settlement, Northern Natural Gas is responsible for the financial impacts of managing operational storage volumes.
Kern River
Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 2006, the FERC issued an order that modified certain aspects of the administrative law judge’s initial decision, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the load factors to be used in calculating rates for the vintage system. The FERC determined that a 100% load factor should be used in the rate calculation rather than the 95% load factor requested by Kern River. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. Kern River submitted its compliance filing, which sets forth compliance rates in accordance with the initial order, on December 18, 2006. A final order on the request for rehearing and compliance filing is expected to be issued in the first or second quarter of 2007. Rate refunds will be due within 30 days after the final order is issued. Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Since that time, Kern River has recorded a provision for estimated refunds. As a result of the October 19, 2006 order, additional customer billings and the accrual of interest, the liability for rates subject to refund increased $77.8 million during 2006 to $107.3 million as of December 31, 2006.
(7) Investments
Other Investments
Other investments are classified as non-current, until currently due according to stated maturities, in the accompanying Consolidated Balance Sheets as management does not intend to use them in current operations. Gross realized and unrealized gains and losses of other investments are not material as of December 31, 2006 and 2005. Other investments consist of the following as of December 31 (in millions):
In May 2005, certain indirect wholly owned subsidiaries of CE Electric UK purchased £300.0 million of fixed rate guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) with a portion of the proceeds of the issuance of £350.0 million of 5.125% bonds due in 2035. These guaranteed investment contracts mature in December 2007 (£100.0 million) and February 2008 (£200.0 million). The proceeds of which will be used to repay certain long-term debt of subsidiaries of CE Electric UK. The guaranteed investment contracts are reported at cost.
MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Nuclear Station Units 1 and 2. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Funds are invested in the trust in accordance with applicable federal investment guidelines and are restricted for use as reimbursement for costs of decommissioning the Quad Cities Station. As of December 31, 2006, approximately 56% of the fair value of the trusts’ funds was invested in domestic common equity securities, approximately 13% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds. As of December 31, 2005, approximately 56% of the fair value of the trusts’ funds was invested in domestic common equity securities, 14% in domestic corporate debt securities and the remainder in investment grade municipal and U.S. Treasury bonds.
PacifiCorp has established a trust for the investment of funds for final reclamation of a leased coal mining property. These investments in debt and equity securities are classified as available-for-sale and are reported at fair value. Amounts funded are based on estimated future reclamation costs and estimated future coal deliveries. As of December 31, 2006, approximately 56% of the fair value of the trust’s funds was invested in equity securities with the remainder invested in debt securities.
(8) Short-Term Borrowings
Short-term borrowings consist of the following as of December 31 (in millions):
MEHC
MEHC has a $600.0 million unsecured credit facility expiring in July 2011. The credit facility has a variable interest rate based on the London Interbank Offered Rate (“LIBOR”) plus 0.195% that varies based on MEHC’s credit ratings for its senior unsecured long-term debt securities or a base rate, at MEHC’s option, and the credit facility supports letters of credit for the benefit of certain subsidiaries and affiliates. As of December 31, 2006, the outstanding balance of the credit facility totaled $152.0 million, at an interest rate of 5.57%, and letters of credit issued under the credit agreement totaled $59.7 million. As of December 31, 2005, the outstanding balance of the credit facility totaled $51.0 million, at an interest rate of 4.85%, and letters of credit issued totaled $41.9 million. The related credit agreement requires that MEHC’s ratio of consolidated debt to total capitalization, including current maturities, not exceed 0.70 to 1.0 as of the last day of any quarter.
PacifiCorp
PacifiCorp has an $800.0 million unsecured revolving credit facility expiring in July 2011. The credit facility includes a variable interest rate borrowing option based on LIBOR plus 0.195% that varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities and it supports PacifiCorp’s commercial paper program. As of December 31, 2006, PacifiCorp had $397.3 million of commercial paper arrangements outstanding at an average interest rate of 5.3% and no borrowings outstanding under its revolving credit agreement as of December 31, 2006. The revolving credit agreement requires that PacifiCorp’s ratio of consolidated debt to total capitalization, including current maturities, at no time exceed 0.65 to 1.0.
MidAmerican Energy
MidAmerican Energy has a $500.0 million unsecured revolving credit facility expiring in July 2011. The credit facility has a variable interest rate based on the LIBOR plus 0.115% that varies based on MidAmerican Energy’s credit ratings for its senior unsecured long-term debt securities and it supports MidAmerican Energy’s $379.6 million commercial paper program and its variable rate pollution control revenue obligations. As of December 31, 2006 and 2005, MidAmerican Energy had no commercial paper or bank notes outstanding. The related credit agreement requires that MidAmerican Energy’s ratio of consolidated debt to total capitalization, including current maturities, not exceed 0.65 to 1.0 as of the last day of any quarter.
CE Electric UK
CE Electric UK has a £100.0 million unsecured revolving credit facility expiring in April 2010. The facility carries a variable interest rate based on sterling LIBOR plus 0.25% to 0.40%. As of December 31, 2006 there were no borrowings outstanding. As of December 31, 2005 there was $10.4 million outstanding at an interest rate of 5.14%. The related credit agreement requires that CE Electric UK’s ratio of consolidated senior net debt to regulated asset value, including current maturities, not exceed 0.8 to 1.0 at CE Electric UK and 0.65 to 1.0 at Northern Electric and Yorkshire Electricity as of June 30 and December 31. Additionally, CE Electric UK’s interest coverage ratio can not exceed 2.0 to 1.0 during 2006 and 2.5 to 1.0 thereafter.
CE Electric UK also has a total of £35.0 million in unsecured, uncommitted lines of credit, none of which were drawn on as of December 31, 2006 and 2005. The interest rate of these uncommitted lines of credit as of December 31, 2006 is variable based on sterling LIBOR plus 0.40%.
HomeServices
HomeServices has a $125.0 million unsecured senior revolving credit facility expiring in December 2010. The facility carries a variable interest rate based on the prime lending rate or LIBOR, at HomeServices’ option, plus 0.5% to 1.125%, that varies based on HomeServices’ total debt ratio. The spread was 0.5% as of December 31, 2006 and 2005. As of December 31, 2006 and 2005 there were no borrowings outstanding. The related credit agreement requires that HomeServices’ ratio of consolidated total debt to EBITDA not exceed 3.0 to 1.0 at the end of any fiscal quarter and its ratio of EBITDA to interest can not be less than 2.5 to 1.0 at the end of any fiscal quarter.
Additionally, HomeServices has a $25.0 million mortgage warehouse line of credit expiring in May 2008. The line of credit carries a variable interest rate based on LIBOR plus 1.75% to 2.00% depending on the type of mortgage loan funded. As of December 31, 2006, the balance outstanding on this line of credit was $2.5 million at a weighted average interest rate of 7.10% and the balance outstanding on this line of credit as of December 31, 2005 was $8.7 million at a weighted average interest rate of 6.14%.
(9) Parent Company Senior Debt
Parent company senior debt represents unsecured senior obligations of MEHC and consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):
(10) Parent Company Subordinated Debt
Parent company subordinated debt consists of the following, including fair value adjustments, as of December 31 (in millions):
The Capital Trusts were formed for the purpose of issuing trust preferred securities to holders and investing the proceeds received in parent company subordinated debt issued by MEHC. The terms of the parent company subordinated debt are substantially identical to those of the trust preferred securities. The parent company subordinated debt associated with the CalEnergy Trusts is callable at the option of MEHC at any time at par value plus accrued interest. The parent company subordinated debt associated with the MidAmerican Capital Trusts is not callable by MEHC except upon the limited occurrence of specified events. Distributions on the parent company subordinated debt are payable either quarterly or semi-annually, depending on the issue, in arrears, and can be deferred at the option of MEHC for up to five years. During the deferral period, interest continues to accrue on the CalEnergy Capital Trusts at their stated rates, while interest accrues on the MidAmerican Capital Trusts at 13% per annum. The CalEnergy Capital Trust preferred securities are convertible any time into cash at the option of the holder for an aggregate amount of $283.7 million.
The MidAmerican Capital Trusts preferred securities are held by Berkshire Hathaway and its affiliates, which are prohibited from transferring the securities absent an event of default to non-affiliated persons. Interest expense to Berkshire Hathaway for the years ended December 31, 2006, 2005 and 2004 was $133.8 million, $157.3 million and $169.9 million, respectively. Interest expense on the CalEnergy Capital Trusts for the years ended December 31, 2006, 2005 and 2004 was $27.4 million, $27.1 million and $27.0 million, respectively.
The parent company subordinated debt is subordinated to all senior indebtedness of MEHC and is subject to certain covenants, events of default and optional and mandatory redemption provisions, all described in the indenture. Upon involuntary liquidation, the holder is entitled to par value plus any distributions in arrears. MEHC has agreed to pay to the holders of the trust preferred securities, to the extent that the applicable Trust has funds available to make such payments, quarterly distributions, redemption payments and liquidation payments on the trust preferred securities.
(11) Subsidiary and Project Debt
MEHC’s direct and indirect subsidiaries are organized as legal entities separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for its own project or subsidiary debt. It should not be assumed that the assets of any subsidiary will be available to satisfy MEHC’s obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.
Distributions at these separate legal entities are limited by various covenants including, among others, leverage ratios, interest coverage ratios and debt service coverage ratios. As of December 31, 2006, all subsidiaries were in compliance with their covenants. However, Cordova Energy’s 537-MW gas-fired power plant in the Quad Cities, Illinois area is currently prohibited from making distributions by the terms of its indenture due to its failure to meet its debt service coverage ratio requirement.
Long-term debt of subsidiaries and projects consists of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (in millions):
PacifiCorp
The components of PacifiCorp’s long-term debt consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):
(1)
Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as the pollution-control revenue bonds.
(2)
Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime rates or other short-term market rates.
First mortgage bonds of PacifiCorp may be issued in amounts limited by PacifiCorp’s property, earnings and other provisions of the mortgage indenture. Approximately $14.6 billion of the eligible assets (based on original cost) of PacifiCorp were subject to the lien of the mortgage as of December 31, 2006.
As of December 31, 2006, $2.7 billion of first mortgage bonds were redeemable at PacifiCorp’s option at redemption prices dependent upon United States Treasury yields. As of December 31, 2006, $541.7 million of variable-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par. As of December 31, 2006, $71.2 million of fixed-rate pollution-control revenue bonds were redeemable at PacifiCorp’s option at par and another $12.7 million at 102.0% of par. The remaining long-term debt was not redeemable as of December 31, 2006.
As of December 31, 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $21.0 million of standby letters of credit to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available as of December 31, 2006 and expire periodically through February 2011.
MidAmerican Funding
The components of MidAmerican Funding’s senior notes and bonds consist of the following, including fair value adjustments, as of December 31 (dollars in millions):
MidAmerican Funding’s subsidiaries must make payments on their own indebtedness before making distributions to MidAmerican Funding. The distributions are also subject to utility regulatory restrictions agreed to by MidAmerican Energy in March 1999, whereby it committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain a common equity to total capitalization ratio above 42%, except under circumstances beyond its control. MidAmerican Energy’s common equity to total capitalization ratio is not allowed to decline below 39% for any reason. If the ratio declines below the defined threshold, MidAmerican Energy must seek the approval of a reasonable utility capital structure from the IUB. MidAmerican Energy’s ability to issue debt could also be restricted. As of December 31, 2006, MidAmerican Energy’s common equity to total capitalization ratio, computed on a basis consistent with the commitment, was 53.6%.
MidAmerican Energy
The components of MidAmerican Energy’s mortgage bonds, pollution control revenue obligations and notes consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):
Northern Natural Gas
The components of Northern Natural Gas’ senior notes consist of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):
On February 12, 2007, Northern Natural Gas issued $150.0 million of 5.8% Senior Notes due February 15, 2037. The proceeds will be used by Northern Natural Gas to fund capital expenditures and for other general corporate purposes.
Kern River
The components of Kern River’s term notes are due in monthly installments and consist of the following as of December 31 (dollars in millions):
Kern River provides a debt service reserve letter of credit in amounts equal to the next six months of principal and interest payments due on the loans which were equal to $64.4 million and $64.5 million, respectively, as of December 31, 2006 and 2005.
CE Electric UK
The components of CE Electric UK and its subsidiaries’ long-term debt consist of the following, including fair value adjustments and unamortized premiums and discounts, as of December 31 (dollars in millions):
(1)
The par values for these debt instruments are denominated in sterling and have been converted to U.S. dollars at the applicable exchange rate.
CE Casecnan
CE Casecnan Water and Energy Company, Inc. (“CE Casecnan”) has 11.95% Senior Secured Series B Bonds, due in 2010 with a par value of $106.3 million. The outstanding balance of these bonds, including fair value adjustments, as of December 31, 2006 and 2005 was $105.4 million and $140.6 million, respectively.
Leyte Projects
The Leyte Projects’ term loans consist of the following as of December 31 (dollars in millions):
MEHC provides a debt service reserve letter of credit in amounts equal to the next six months of principal and interest payments due on the loans which were equal to $13.2 million and $18.8 million as of December 31, 2006 and 2005, respectively.
Cordova Funding
Cordova Funding Corporation’s (“Cordova Funding”) senior secured bonds are due in semi-annual installments and consist of the following, including fair value adjustments, as of December 31 (dollars in millions):
MEHC has issued a limited guarantee of a specified portion of the final scheduled principal payment on December 15, 2019, on the Cordova Funding senior secured bonds in an amount up to a maximum of $37.0 million. On September 14, 2006, MEHC gave notice to terminate the then existing debt service reserve guarantee, the maximum amount of which was equal at any given time to the difference between the next succeeding debt service payment ($11.0 million as of December 31, 2005) and the amount then on deposit in the debt service reserve fund ($9.0 million as of December 31, 2005). As required by the debt service reserve guarantee, the debt service reserve account is fully funded with cash and the required amount is equal to or exceeds the current debt service required balance.
HomeServices
The components of HomeServices’ long-term debt consist of the following, including fair value adjustments, as of December 31 (dollars in millions):
Annual Repayments of Long-Term Debt
The annual repayments of parent company and subsidiary and project debt for the years beginning January 1, 2007 and thereafter, excluding fair value adjustments and unamortized premiums and discounts, are as follows (in millions):
(12) Asset Retirement Obligations
The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur due to plan revisions, changes in estimated costs and changes in timing of the performance of reclamation activities. The change in the balance of the total ARO liability, which is included in other long-term accrued liabilities in the accompanying Consolidated Balance Sheets, is summarized as follows (in millions):
PacifiCorp’s coal mining operations are subject to the Surface Mining Control and Reclamation Act of 1977 and similar state statutes that establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These statutes mandate that mine property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp is incurring expenditures for both ongoing and final reclamation. The fair value of PacifiCorp’s estimated mine and plant reclamation costs was $140.8 million as of December 31, 2006 and is the asset retirement obligation for these mines. PacifiCorp has established trusts for the investment of funds for certain mine and plant reclamation. The fair value of the assets held in trusts was $109.8 million as of December 31, 2006, and is reflected in other investments in the accompanying Consolidated Balance Sheet.
The Nuclear Regulatory Commission (“NRC”) regulates the decommissioning of nuclear power plants, which includes the planning and funding for the decommissioning. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay for its share of the Quad Cities Station decommissioning. These expected costs have been developed based on a site-specific decommissioning study that includes decontamination, dismantling, site restoration and dry fuel storage using an assumed shutdown date. The decommissioning costs are included in base rates in MidAmerican Energy’s Iowa tariffs. The fair value of MidAmerican Energy’s share of estimated Quad Cities Station decommissioning costs was $142.1 million and $163.0 million, respectively, as of December 31, 2006 and 2005, and is the asset retirement obligation for Quad Cities Station. MidAmerican Energy has established trusts for the investment of decommissioning funds. The fair value of the assets held in the trusts was $258.8 million and $228.1 million, respectively, as of December 31, 2006 and 2005, and is reflected in other investments in the accompanying Consolidated Balance Sheets.
The majority of the revisions recorded in 2006 are a result of a new valuation, consistent with its practice of periodically performing such studies, conducted by the operator of the Quad Cities Station related to the nuclear decommissioning ARO liability. The revision increased regulatory liabilities and did not impact earnings.
On December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, the Company is required to recognize a liability for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO should be factored into the measurement of the liability when sufficient information exists.
In conjunction with the adoption of FIN 47, the Company recorded $11.4 million of conditional ARO liabilities; $0.8 million of associated ARO assets, net of accumulated depreciation; and a $10.6 million reduction of regulatory liabilities. Adoption of FIN 47 did not impact net income. The total ARO liability, computed on a pro forma basis as if FIN 47 had been applied during each of the periods presented in the Consolidated Financial Statements, would have been $295.2 million as of January 1, 2004 and $197.0 million as of December 31, 2004.
In addition to the ARO liabilities, the Company has accrued for the cost of removing other electric and gas assets through its depreciation rates, in accordance with accepted regulatory practices. These accruals are reflected as regulatory liabilities and total $1,164.2 million and $448.5 million as of December 31, 2006 and 2005, respectively.
(13) Preferred Securities of Subsidiaries
The total outstanding preferred stock of PacifiCorp, which does not have mandatory redemption requirements, was $41.3 million as of December 31, 2006. Generally, this preferred stock is redeemable at stipulated prices plus accrued dividends, subject to certain restrictions. Upon voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Any premium paid on redemptions of preferred stock is capitalized, and recovery is sought through future rates. Dividends on all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp board of directors in the event dividends payable are in default in an amount equal to four full quarterly payments.
The total outstanding cumulative preferred securities of MidAmerican Energy are not subject to mandatory redemption requirements and may be redeemed at the option of MidAmerican Energy at prices which, in the aggregate, total $31.1 million as of December 31, 2006 and 2005. The aggregate total the holders of all preferred securities outstanding as of December 31, 2006 and 2005, are entitled to upon involuntary bankruptcy is $30.3 million plus accrued dividends.
The total outstanding 8.061% cumulative preferred securities of a subsidiary of CE Electric UK, which are redeemable in the event of the revocation of the subsidiary’s electricity distribution license by the Secretary of State, was $56.0 million as of December 31, 2006 and 2005.
(14) Risk Management and Hedging Activities
MEHC is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, particularly through its ownership of PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. MEHC is also exposed to foreign currency risk from its business operations and investments in Great Britain and the Philippines. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps and options. The risk management process established by each business platform is designed to identify, assess, monitor, report, manage, and mitigate each of the various types of risk involved in its business. The Company does not engage in a material amount of proprietary trading activities.
The following table summarizes the various derivative mark-to-market positions included in the balance sheets as of December 31, 2006 (in millions):
(1) Before income taxes.
The following table summarizes the various derivative mark-to-market positions included in the balance sheets as of December 31, 2005 (in millions):
(1) Before income taxes.
Commodity Price Risk
MEHC is subject to significant commodity risk particularly through its ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in the price of wholesale electricity that is purchased and sold, fuel costs to generate electricity, and natural gas supply for regulated retail gas customers. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other items, changing weather, limited storage, transmission and transportation constraints, and lack of alternative supplies from other areas. To mitigate a portion of the risk, both utilities use derivative instruments, including forwards, futures, options, swap and other over-the-counter agreements, to effectively secure future supply or sell future production at fixed prices. The settled cost of these contracts is generally recovered from customers in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives, that are probable of recovery in rates, are recorded as regulatory net assets or liabilities.
MidAmerican Energy also uses futures, options and swap agreements to economically hedge gas commodity prices for physical delivery to non-regulated customers. Non-regulated physical contracts are considered normal purchases or sales and gains and losses on such contracts are recognized when settled. All other non-regulated gas and electric contracts are recorded at fair value.
Other MEHC subsidiaries use derivative instruments such as swaps, future, forwards and options principally as cash flow hedges for spring operational sales, natural gas storage and other transactions. During 2006, CE Gas recognized $14.4 million of unrealized losses on derivative contracts that became ineffective due to its inability to effectively forecast the associated hedged transactions.
Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales or operating expenses depending upon the nature of the item being hedged. Net unrealized gains and losses on hedges utilized for regulatory purposes are generally recorded as regulatory assets and liabilities. As of December 31, 2006, the Company had cash flow hedges with expiration dates through November 2009. For the year ended December 31, 2006, hedge ineffectiveness was insignificant. As of December 31, 2006, $1.1 million of pre-tax net unrealized gains are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.
Foreign Currency Risk
MEHC selectively reduces its foreign currency risk by hedging through foreign currency derivatives. CE Electric UK has entered into certain currency rate swap agreements with large multi-national financial institutions for its U.S. dollar denominated senior notes and Yankee bonds. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $237.0 million of 6.995% senior notes and $281.0 million of 6.496% Yankee bonds outstanding as of December 31, 2006. The agreements extend to the maturity date of the bonds, December 30, 2007 and February 25, 2008, respectively. The estimated fair value of these swap agreements as of December 31, 2006 and 2005, was $148.9 million and $77.5 million, respectively, based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated.
Interest Rate Risk
The Company may enter into contractual agreements to hedge exposure to interest rate risk. In September 2006, MEHC entered into a treasury rate lock agreement in the notional amount of $1.55 billion to protect against an increase in interest rates on future long-term debt issuances. As of December 31, 2006, the fair value of the treasury rate lock agreement was $12.5 million. In May 2005, MEHC entered into a treasury rate lock agreement in the notional amount of $1.6 billion to protect against an increase in interest rates on future long-term debt issuances. The financing occurred on March 24, 2006 and MEHC received $53.0 million, which is being amortized as a reduction to interest expense over the term of the related financing.
(15) Income Taxes
Income tax expense on continuing operations consists of the following for the years ended December 31 (in millions):
A reconciliation of the federal statutory tax rate to the effective tax rate on continuing operations applicable to income before income tax expense for the years ended December 31 follows:
The net deferred tax liability consists of the following as of December 31 (in millions):
As of December 31, 2006, the Company has available unused NOL and credit carryforwards that may be applied against future taxable income and that expire at various intervals between 2007 and 2026.
(16) Other Income and Expense
Other Income
Other income, as shown on the accompanying Consolidated Statements of Operations, for the years ending December 31 consists of the following (in millions):
Gain on Mirant Americas Energy Marketing (“Mirant”) Bankruptcy Claim
Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90,000 Dth per day) with Kern River (the “Mirant Agreement”) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and Kern River subsequently drew on the letter of credit and held the proceeds thereof, $14.8 million, as cash collateral. Kern River claimed $210.2 million in damages due to the rejection of the Mirant Agreement. The bankruptcy court ultimately determined that Kern River was entitled to a general unsecured claim of $74.4 million in addition to the $14.8 million cash collateral. In January 2006, Mirant emerged from bankruptcy. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Kern River sold all of the shares of new Mirant stock received from its allowed claim amount plus interest in the first quarter of 2006 and recognized a gain from those sales of $89.3 million.
Gains on Sales of Non-Strategic Assets and Investments
Included in gains on sales of non-strategic assets and investments for the year ended December 31, 2006 are gains at MidAmerican Funding from the disposition of common shares held in an electronic energy and metals trading exchange where MidAmerican Funding sold a majority of these common shares and realized a pre-tax gain of $27.6 million. Also included in gains on sales of non-strategic assets and investments for the years ended December 31, 2006 and 2005, are gains from sales of certain non-strategic, passive investments at MidAmerican Funding of $15.3 million and $13.4 million, respectively, and CE Electric UK of $- million and $8.4 million, respectively.
Gains on Enron Note Receivable and Other Claims
Northern Natural Gas had a note receivable of approximately $259.0 million (the “Enron Note Receivable”) with Enron. As a result of Enron filing for bankruptcy on December 2, 2001, Northern Natural Gas filed a bankruptcy claim against Enron seeking to recover payment of the Enron Note Receivable. As of December 31, 2001, Northern Natural Gas had written-off the note. By stipulation, Enron and Northern Natural Gas agreed to a value of $249.0 million for the claim and received approval of the stipulation from Enron’s Bankruptcy Court on August 26, 2004. On November 23, 2004, Northern Natural Gas sold its stipulated general, unsecured claim against Enron of $249.0 million to a third party investor for $72.2 million.
Other Expense
MidAmerican Funding has investments in commercial passenger aircraft leased to major domestic airlines, which are accounted for as leveraged leases. During 2005, the airline industry continued to deteriorate and two major airline carriers filed for bankruptcy. MidAmerican Funding evaluated its investments in commercial passenger aircraft and recognized losses totaling $15.6 million for other-than-temporary impairments of those investments.
(17) Discontinued Operations - Zinc Recovery Project and Mineral Assets
Indirect wholly-owned subsidiaries of MEHC own the rights to commercial quantities of extractable minerals from elements in solution in the geothermal brine and fluids utilized at certain geothermal energy generation facilities located in the Imperial Valley of California and a zinc recovery plant constructed near the geothermal energy generation facilities designed to recover zinc from the geothermal brine through an ion exchange, solvent extraction, electrowinning and casting process (the “Zinc Recovery Project”).
The Zinc Recovery Project began limited production during December 2002 and continued limited production until September 2004 when management made the decision to cease operations. Based on this decision, a non-cash, after-tax impairment charge of $340.3 million was recorded to write-off the Zinc Recovery Project, rights to quantities of extractable minerals, and allocated goodwill (collectively, the “Mineral Assets”). The charge and the related activity of the Mineral Assets are classified separately as discontinued operations in the accompanying Consolidated Statements of Operations and include the following for the years ended December 31 (in millions):
In connection with ceasing operations, the Zinc Recovery Project’s assets have been dismantled and sold and certain employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Implementation of the decommissioning plan began in September 2004 and, as of December 31, 2005, the dismantling, decommissioning, and sale of remaining assets of the Zinc Recovery Project was completed.
(18) Shareholders’ Equity
Preferred Stock
As of December 31, 2005, Berkshire Hathaway owned 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock. Each share of preferred stock was convertible at the option of the holder into one share of MEHC’s common stock subject to certain adjustments as described in MEHC’s Amended and Restated Articles of Incorporation. The convertible preferred stock was convertible into common stock only upon the occurrence of specified events, including modification or elimination of the Public Utility Holding Company Act of (“PUHCA 1935”) so that holding company registration would not be triggered by conversion. On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock.
Common Stock
On March 14, 2000, and as amended on December 7, 2005, MEHC’s shareholders entered into a Shareholder Agreement that provides specific rights to certain shareholders. One of these rights allows certain shareholders the ability to put their common shares back to MEHC at the then current fair value dependent on certain circumstances controlled by MEHC.
On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011.
On March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase the amount of its common stock authorized for issuance to 115,000,000 shares and (ii) no longer provide for the authorization to issue any preferred stock of MEHC.
In March 2006, MEHC repurchased 12,068,412 shares of common stock for an aggregate purchase price of $1,750.0 million.
On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing shareholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition (see Note 3). The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s shareholders.
On January 6, 2004, MEHC repurchased shares of common stock for an aggregate purchase price of $20.0 million.
Common Stock Options
There were no common stock options granted, forfeited or allowed to expire during each of the three years in the period ended December 31, 2006, and there were no common stock options exercised during the year ended December 31, 2004. There were 775,000 common stock options exercised during the year ended December 31, 2006 having a weighted-average exercise price of $28.65 per share. There were 1,073,329 common stock options outstanding and exercisable with a weighted-average exercise price of $32.27 per share as of December 31, 2006. As of December 31, 2006, 370,000 of the outstanding and exercisable common stock options have exercise prices ranging from $24.22 to $34.69 per share, a weighted-average exercise price of $26.99 per share and a remaining contractual life of 1.25 years. The remaining 703,329 outstanding and exercisable common stock options have an exercise price of $35.05 per share and a remaining contractual life of 3.25 years.
There were 200,000 common stock options exercised during the year ended December 31, 2005 having an exercise price of $29.01 per share. There were 1,848,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.75 per share as of December 31, 2005. 1,145,000 of the outstanding and exercisable common stock options had exercise prices ranging from $15.94 to $34.69 per share, a weighted-average exercise price of $28.11 per share and a remaining contractual life of 2.25 years. The remaining 703,329 outstanding and exercisable common stock options had an exercise price of $35.05 per share and a remaining contractual life of 4.25 years. There were 2,048,329 common stock options outstanding and exercisable with a weighted-average exercise price of $30.58 per share as of December 31, 2004 and 2003.
(19) Commitments and Contingencies
Environmental Matters
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters and believes it is in material compliance with current environmental requirements.
Air Quality
Litigation was filed in the federal district court for the southern district of New York seeking to require reductions of carbon dioxide emissions from generating facilities of five large electric utilities. The court dismissed the suit, ruling that critical issues affecting the United States, like greenhouse gas emissions reductions, are not the domain of the courts and should be resolved by the executive branch of the federal government and the U.S. Congress. This ruling has been appealed to the Second Circuit Court of Appeals. The outcome of climate change litigation and federal and state climate change initiatives cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact the Company’s fossil-fueled facilities and, therefore, its financial results.
The EPA’s regulation of certain pollutants under the Clean Air Act, and its failure to regulate other pollutants, is being challenged by various lawsuits brought by both individual state attorney generals and environmental groups. To the extent that these actions may be successful in imposing additional and/or more stringent regulation of emissions on fossil-fueled facilities in general and PacifiCorp’s and MidAmerican Energy’s facilities in particular, such actions could significantly impact the Company’s fossil-fueled facilities and, therefore, its financial results.
Accrued Environmental Costs
The Company is fully or partly responsible for environmental remediation that results from other than normal operations at various contaminated sites, including sites that are or were part of the Company’s operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expense is believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of December 31, 2006 and 2005 was $50.4 million and $7.5 million, respectively, and is included in other liabilities and other long-term accrued liabilities on the accompanying Consolidated Balance Sheets. Environmental remediation liabilities that result from the normal operation of a long-lived asset and that are associated with the retirement of those assets is accounted for as an asset retirement obligation.
Hydroelectric Relicensing
PacifiCorp’s hydroelectric portfolio consists of 50 plants with an aggregate facility net owned capacity of 1,160.1 MW. The FERC regulates 97.9% of the installed capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric plants are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp had incurred $79.0 million in costs as of December 31, 2006 for ongoing hydroelectric relicensing, which are included in construction in progress and reflected in property, plant and equipment, net in the accompanying Consolidated Balance Sheet.
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169.0-MW nameplate-rated Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp will continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.
Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. The public comment period on the draft environmental impact statement closed on December 1, 2006. The FERC is expected to issue its final environmental impact statement by April 2007, after which other federal agencies will complete their endangered species analyses. The states of Oregon and California will need to issue water quality certifications prior to the FERC issuing a final license.
As of December 31, 2006, PacifiCorp has incurred costs of $42.1 million, which are reflected in property, plant and equipment, net in the accompanying Consolidated Balance Sheet, in the relicensing of the Klamath project. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.
Legal Matters
The Company is party in a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material effect on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines and penalties in substantial amounts and are described below.
PacifiCorp
In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Clean Air Act’s opacity standards at PacifiCorp’s Jim Bridger Power Plant in Wyoming. Under the Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light in the flue of a generating facility. The complaint alleges thousands of violations and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. PacifiCorp believes it has a number of defenses to the claims, and it has already committed to invest at least $812.0 million in pollution control equipment at its generating facilities, including the Jim Bridger plant, that is expected to significantly reduce emissions. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time.
CalEnergy Generation-Foreign
Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon proforma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA arbitration. On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend declarations in 2006, 2005 and 2004, totaling $32.5 million, was set aside in a separate bank account in the name of CE Casecnan.
On August 4, 2005, the court issued a decision, ruling in favor of LPG on five of the eight disputed issues in the first phase of the litigation. On September 12, 2005, LPG filed a motion seeking the release of the funds which have been set aside pursuant to the status quo agreement referred to above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October 3, 2005, and at the hearing on October 26, 2005, the court denied LPG’s motion. On January 3, 2006, the court entered a judgment in favor of LPG against CE Casecnan Ltd. According to the judgment, LPG would retain its ownership of 15% of the shares of CE Casecnan and distributions of the amounts deposited into escrow plus interest at 9% per annum. On February 28, 2006, CE Casecnan Ltd. filed an appeal of this judgment and the August 4, 2005 decision. On February 21, 2007, California Court of Appeals remanded the case to the lower court to modify its finding on one of the five disputed issues previously determined in favor of LPG. The judgment was affirmed in all other respects. The Company is currently evaluating the Court of Appeal’s order. The parties are proceeding in the trial court on LPG’s remaining claim against MEHC for damages for alleged breach of fiduciary duty. This claim is expected to be resolved sometime in 2007. The Company intends to vigorously defend the remaining claims.
In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. The Company believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, the Company will vigorously defend such action. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Cascenan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the matter is currently in the early stages of discovery. The Company intends to vigorously defend the counterclaims.
Unconditional Purchase Obligations
The Company has the following unconditional purchase obligations as of December 31, 2006 (in millions):
Coal, Electricity and Natural Gas Contract Commitments
PacifiCorp and MidAmerican Energy have fuel supply and related transportation contracts for their coal-fired and gas generating stations. PacifiCorp and MidAmerican Energy expect to supplement these contracts with additional contracts and spot market purchases to fulfill their future fossil fuel needs. PacifiCorp and MidAmerican Energy acquire a portion of their electricity through long-term purchases and/or exchange agreements. Included in the purchased electricity payments are any power purchase agreements that meet the definition of an operating lease.
Owned Hydroelectric Commitments
As part of the hydroelectric relicensing process, PacifiCorp entered into settlement agreements with various interested parties that resulted in commitments for environmental mitigation and enhancement measures over the life of the licenses.
Operating Leases, Easements and Maintenance Contracts
The Company has non-cancelable operating leases primarily for computer equipment, office space, certain operating facilities, land and rail cars. These leases generally require the Company to pay for insurance, taxes and maintenance applicable to the leased property. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. The Company also has non-cancelable easements for land on which its wind-farm turbines are located, as well as non-cancelable maintenance contracts for the turbines. Rent expense on non-cancelable operating leases totaled $117.0 million for 2006, $79.4 million for 2005 and $71.5 million for 2004.
Deferred Construction Payments
On February 12, 2003, MidAmerican Energy executed a contract with Mitsui & Co. Energy Development, Inc. (“Mitsui”) for engineering, procurement and construction of a 790-MW (based on expected accreditation) coal-fired generating plant expected to be completed in the summer of 2007. MidAmerican Energy currently holds a 60.67% individual ownership interest as a tenant in common with the other owners of the plant. Under the contract, MidAmerican Energy is allowed to defer payments, including the other owners’ shares, for up to $200.0 million of billed construction costs through the end of the project. In July 2005, MidAmerican Energy reached the total allowed amount of $200.0 million of deferred payments. In the accompanying Consolidated Balance Sheets, the liability is reflected in accounts payable as of December 31, 2006 and other long-term accrued liabilities as of December 31, 2005.
A $78.7 million asset representing the other owners’ share of the deferred payments is reflected in the accompanying Consolidated Balance Sheets in other current assets as of December 31, 2006 and deferred charges and other assets as of December 31, 2005. MidAmerican Energy will bill each of the other owners for its share of the deferred payments when payment is made to Mitsui.
Guarantees
The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company’s consolidated financial results. The Company is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of other parties. The following represent the material indemnification obligations of the Company as of December 31, 2006.
PacifiCorp
PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities and mine sites. The decommissioning guarantees require PacifiCorp to pay a proportionate share of the decommissioning costs based upon percentage of ownership. The mine reclamation obligations require PacifiCorp to pay the mining entity a proportionate share of the mine’s reclamation costs based on the amount of coal purchased by PacifiCorp. In the event of default by any of the other joint participants, PacifiCorp potentially may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party’s liability. PacifiCorp has recorded its estimated share of the decommissioning and reclamation obligations as either an asset retirement obligation, regulatory liability or other liability.
(20) Employee Benefit Plans
Domestic Operations
PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. PacifiCorp’s pension plans include a noncontributory defined benefit pension plan, a supplemental executive retirement plan (“SERP”) and a joint trust plan to which PacifiCorp contributes on behalf of certain bargaining unit employees of International Brotherhood of Electrical Workers Local 57. MidAmerican Energy sponsors defined benefit pension plans that cover substantially all employees of MEHC and its domestic energy subsidiaries other than PacifiCorp. MidAmerican Energy’s pension plans included a noncontributory defined benefit pension plan and a SERP.
In December 2006, non-bargaining employees were notified that PacifiCorp is changing from a traditional final average pay formula for the Retirement Plan to a cash balance formula effective June 1, 2007. Benefits under the final average pay formula will be frozen as of May 31, 2007, with no further benefit accrual under that formula. All future benefits will be earned under the cash balance formula.
PacifiCorp and MidAmerican Energy also provide certain postretirement health care and life insurance benefits through various plans for eligible retirees.
MidAmerican Energy’s postretirement benefit plan was amended for non-union employees on July 1, 2004, and substantially all union participants on July 1, 2006. As a result, non-union employees hired after June 30, 2004, and union employees hired after June 30, 2006, are not eligible for postretirement benefits other than pensions. The plan, as amended, establishes retiree medical accounts for participants to which the Company makes fixed contributions until the employee’s retirement. Participants will use such accounts to pay a portion of their medical premiums during retirement.
Plan assets and obligations for PacifiCorp-sponsored plans are measured as of September 30, 2006 and MidAmerican Energy-sponsored plans are measured as of December 31, 2006. For purposes of calculating the expected return on pension plan assets, a market-related value is used. Market-related value is equal to fair value except for gains and losses on investments, which are amortized into market-related value on a straight-line basis over five years.
The components of the combined net periodic benefit cost for the pension, including supplemental retirement, and other postretirement benefits plans for the years ended December 31 was as follows (in millions):
The following table is a reconciliation of the combined fair value of plan assets as of December 31 (in millions):
The SERPs have no assets, however the Company has Rabbi trusts that hold corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERPs. The cash surrender value of all of the policies included in the Rabbi trusts, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments was $147.9 million and $102.9 million as of December 31, 2006 and 2005, respectively. These assets are not included in the plan assets in the above table. The portion of the pension projected benefit obligation related to the Company’s SERPs was $160.5 million and $105.7 million as of December 31, 2006 and 2005, respectively.
The following table is a reconciliation of the combined benefit obligations as of December 31 (in millions):
As of December 31, 2006 the funded status of the pension and other postretirement plans was recorded in the Consolidated Balance Sheet as required under the adoption of SFAS No. 158. Balance sheet amounts recorded as of December 31, did not include the unrecognized net actuarial losses (gains), prior service costs and net transition obligations of ($42.1) million for the pension plans and $46.6 million for the other postretirement plans. The combined funded status of the plans and the net amount recognized in the accompanying Consolidated Balance Sheets as of December 31 is as follows (in millions):
The net loss, prior service cost and net transition obligation that will be amortized in 2007 into net periodic benefit cost are estimated to be as follows (in millions):
Plan Assumptions
Assumptions used to determine benefit obligations as of December 31 and net benefit cost for the years ended December 31 follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in millions):
Contributions and Benefit Payments
PacifiCorp contributions to the pension and other postretirement plans are expected to be $94.9 million and $43.9 million, respectively, for 2007.
The expected benefit payments to participants from its pension and other postretirement plans for 2007 through 2011 and for the five years thereafter are summarized below (in millions):
Investment Policy and Asset Allocation
The investment policy for the Company’s pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and other alternative investments. Asset allocation for the pension and postretirement plans are as indicated in the tables below. Maturities for fixed income securities are managed to targets consistent with prudent risk tolerances. Sufficient liquidity is maintained to meet near-term benefit payment obligations. The plans retain outside investment advisors to manage plan investments within the parameters outlined by each plan’s Pension and Employee Benefits Plans Administrative Committee. The return on assets assumption is based on a weighted average of the expected historical performance for the types of assets in which the plans invest.
PacifiCorp’s asset allocation as of December 31 was as follows:
MidAmerican Energy’s asset allocation as of December 31 was as follows:
Defined Contribution Plans
The Company sponsors defined contribution pension plans (401(k) plans) and an employee savings plan covering substantially all employees. The Company’s contributions vary depending on the plan, but are based primarily on each participant’s level of contribution and cannot exceed the maximum allowable for tax purposes. Total Company contributions were $33.8 million, $17.3 million and $17.1 million for 2006, 2005 and 2004, respectively.
United Kingdom Operations
Certain wholly-owned subsidiaries of CE Electric UK participate in the Northern Electric group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the “UK Plan”), which provides pension and other related defined benefits, based on final pensionable pay, to the majority of the employees of CE Electric UK.
Plan assets and obligations for the UK Plan are measured as of December 31, 2006. For purposes of calculating the expected return on pension plan assets, a market-related value is used. Market-related value is equal to fair value except for gains and losses on equity investments which are amortized into market-related value on a straight-line basis over five years. The components of the combined net periodic cost for the UK Plan for the years ended December 31 was as follows (in millions):
The following table is a reconciliation of the fair value of plan assets as of December 31 (in millions):
The following table is a reconciliation of the benefit obligations as of December (in millions):
As of December 31, 2006 the funded status of the U.K. pension was recorded in the Consolidated Balance Sheet as required under the adoption of SFAS No. 158. Balance sheet amounts recorded as of December 31, 2005 did not include the unrecognized net actuarial losses and prior service costs of $561.1 million. However, an additional minimum pension liability of $492.5 million was recorded at December 31, 2005. The funded status of the plan and the net amount recognized in the accompanying Consolidated Balance Sheets as of December 31 is as follows (in millions):
(1)
The December 31, 2006 amounts not recognized as components of net periodic benefit cost totaling $513.3 million was recorded as an adjustment to accumulated other comprehensive income as part of the adoption of SFAS No. 158.
The net loss and prior service cost that will be amortized from accumulated other comprehensive income (loss) in 2007 into net periodic benefit cost is estimated to be $36.4 million and $1.7 million, respectively.
Plan Assumptions
Assumptions used to determine benefit obligations as of December 31 and net benefit cost for the years ended December 31 are as follows:
Contributions and Benefit Payments
The expected benefit payments to participants from the UK Plan for 2007 through and for the five years thereafter are summarized below (in millions):
In 2005, the triennial process of valuing the UK Plan's assets and liabilities, using a March 31, 2004 measurement date, resulted in a £190.3 million funding deficiency. Contributions are computed based on the objective of eliminating the funding deficiency by April 1, 2017. Employer contributions to the UK Plan, including £23.1 million for the funding deficiency, are currently expected to be £35.9 million for 2007.
Investment Policy and Asset Allocation
CE Electric UK’s investment policy for its pension plan is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and real estate. Maturities for fixed income securities are managed such that sufficient liquidity exists to meet near-term benefit payment obligations. The plan retains outside investment advisors to manage plan investments within the parameters set by the trustees of the UK Plan in consultation with CE Electric UK. The return on assets assumption is based on a weighted average of the expected historical performance for the types of assets in which the plans invest.
CE Electric UK’s pension plan asset allocation as of December 31 was as follows:
(21) Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, short-term investments, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity or frequent remarketing of these instruments. Derivative instruments are recorded at their fair values, which are based upon published market indexes as adjusted for other market factors such as location pricing differences or internally developed models. Substantially all investments are carried at their fair values, which are based on quoted market prices.
The fair value of the Company’s long-term debt has been estimated based upon quoted market prices as supplied by third-party broker dealers. The carrying amount of variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying amount and estimated fair value of the Company’s long-term debt, including the current portion, as of December 31 (in millions):
(22) Supplemental Cash Flow Information
The summary of supplemental cash flow information for the years ending December follows (in millions):
(1)
is net of $19.7 million of income taxes received from Berkshire Hathaway.
(23) Components of Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss is included in the accompanying Consolidated Balance Sheets in the common shareholders’ equity section, and consists of the following components, net of tax, as of December 31 (in millions):
(24) Segment Information
MEHC’s reportable segments were determined based on how the Company’s strategic units are managed. The Company’s foreign reportable segments include CE Electric UK, whose business is principally in Great Britain, and CalEnergy Generation-Foreign, whose business is in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company’s reportable segments is shown below (in millions):
(1)
The remaining differences between the segment amounts and the consolidated amounts described as “Corporate/other” relate principally to intersegment eliminations for operating revenue and, for the other items presented, to (i) corporate functions, including administrative costs, interest expense, corporate cash and related interest income, (ii) intersegment eliminations and (iii) fair value adjustments relating to acquisitions.
The following table shows the change in the carrying amount of goodwill by reportable segment for the years ended December 31, 2006 and 2005 (in millions):
(1)
Other goodwill adjustments relate primarily to income tax adjustments.
(2)
During 2006, the Company reclassified $44.9 million of identifiable intangible assets from goodwill that principally related to trade names at HomeServices that were determined to have finite lives.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
An evaluation was performed under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, regarding the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended) as of December 31, 2006. Based on that evaluation, the Company’s management, including the chief executive officer and chief financial officer, concluded that the Company’s disclosure controls and procedures were effective. As a result of the acquisition of PacifiCorp in the first quarter of 2006, the Company has expanded its internal control over financial reporting to include consolidation of the PacifiCorp results of operations, as well as acquisition related accounting and disclosures. There have been no other changes during the fourth quarter of 2006 in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The Board of Directors appoints executive officers annually. There are no family relationships among the executive officers, nor, except as set forth in employment agreements, any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of January 31, 2007, with respect to the current directors and executive officers of MEHC:
DAVID L. SOKOL, 50, Chairman of the Board of Directors and Chief Executive Officer. Mr. Sokol has been the Chief Executive Officer since 1993, the Chairman of the Board of Directors since 1994 and a director since March 1991. Mr. Sokol joined MEHC in 1991.
GREGORY E. ABEL, 44, President, Chief Operating Officer and Director. Mr. Abel has been the President and Chief Operating Officer since 1998 and a director since 2000. Mr. Abel joined MEHC in 1992. Mr. Abel is a director of PacifiCorp.
PATRICK J. GOODMAN, 40, Senior Vice President and Chief Financial Officer since 1999. Mr. Goodman joined MEHC in 1995. Mr. Goodman is a director of PacifiCorp.
DOUGLAS L. ANDERSON, 48, Senior Vice President, General Counsel and Corporate Secretary since 2001. Mr. Anderson joined MEHC in 1993. Mr. Anderson is a director of PacifiCorp.
MAUREEN E. SAMMON, 43, Senior Vice President, Human Resources, Information Technology and Insurance since 2005. Ms. Sammon has been with MidAmerican Energy and its predecessor companies since 1986 and has held several positions, including Manager of Benefits and Vice President, Human Resources and Insurance.
KEITH D. HARTJE, 57, Senior Vice President, Communications, General Services and Safety Audit and Compliance since 2005. Mr. Hartje has been with MidAmerican Energy and its predecessor companies since 1973 and 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 E. BUFFETT, 76, Director. Mr. Buffett has been a director of MEHC since 2000 and has been Chairman of the Board and Chief Executive Officer of Berkshire Hathaway for more than five years. Mr. Buffett is a director of The Washington Post Company.
WALTER SCOTT, JR., 75, Director. Mr. Scott has been a director of MEHC since 1991 and has been Chairman of the Board of Directors of Level 3 Communications, Inc., a successor to certain businesses of Peter Kiewit & Sons’, Inc. for more than five years. Mr. Scott is a director of Peter Kiewit & Sons’, Inc., Berkshire Hathaway, Valmont Industries, Inc. and Commonwealth Telephone Enterprises, Inc.
MARC D. HAMBURG, 57, Director. Mr. Hamburg has been a director of MEHC since 2000 and has been Vice President-Chief Financial Officer and Treasurer of Berkshire Hathaway for more than five years.
Audit Committee and Audit Committee Financial Expert
The audit committee of the Board of Directors is comprised of Mr. Marc D. Hamburg. The Board of Directors has determined that Mr. Hamburg qualifies as an “audit committee financial expert,” as defined by SEC rules, based on his education, experience and background. Based on the standards of the New York Stock Exchange, on which the common stock of MEHC’s majority owner, Berkshire Hathaway, is listed, MEHC’s Board of Directors has determined that Mr. Hamburg is not independent because of his employment by Berkshire Hathaway.
Code of Ethics
MEHC has adopted a code of ethics that applies to its principal executive officer, its principal financial officer, its principal accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is filed as an exhibit to this Form 10-K.
Item 11.
Item 11. Executive Compensation.
Compensation Discussion and Analysis
Compensation Philosophy and Overall Objectives
We believe that the compensation paid to our Chief Executive Officer, or CEO, our Chief Financial Officer, or CFO, and our three other most highly compensated executive officers, whom we collectively refer to as our Named Executive Officers, or NEOs, should be closely aligned with our performance as well as that of each NEO’s individual performance on both a short-and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for our organization. Our compensation programs are designed to provide NEOs with meaningful incentives for superior performance. While individual performance is evaluated on a subjective basis, the evaluation is conducted within the context of financial and non-financial objectives that we believe contribute to our long-term success. Among these objectives are financial strength, customer service, operational excellence, employee commitment, environmental respect and regulatory integrity.
How is Compensation Determined
The Compensation Committee is responsible for the establishment and oversight of our compensation policy. In certain circumstances, the Compensation Committee delegates compensation decisions to the CEO and the President, who make recommendations to the Compensation Committee, at least annually, regarding merit increases and incentive and performance awards. Approval of compensation decisions is made by the Compensation Committee, unless specifically delegated.
Due to the unique nature of each NEO’s duties, our criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. We do not specifically use companies in similar industries as benchmarks when initially establishing NEOs’ compensation. When making annual base salary and incentive recommendations for the CEO and the President, however, the Compensation Committee does review peer company data and does use the data to make informed decisions on the compensation for these two NEOs. The peer companies for were: Alliant Energy Corporation, Ameren Corporation, American Electric Power Company, Inc., Cinergy Corp., Dominion Resources, Inc., Duke Energy Corporation, Entergy Corporation, Exelon Corporation, FirstEnergy Corp., FPL Group, Inc., NiSource Inc., Northeast Utilities, Public Service Enterprise Group Incorporated, Sempra Energy, The Southern Company, TXU Corp. and Xcel Energy Inc.
Discussion of Specific Compensation Elements
Base Salary
We determine base salaries for all our NEOs by reviewing Company and individual performance, the value each NEO brings to us and general labor market conditions. While base salary provides a base level of compensation intended to be competitive with the external market, the base salary for each NEO is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. The base salaries of NEOs are reviewed on an annual basis and any annual increase is the result of an evaluation of the Company and individual NEO’s performance for the period. The CEO makes recommendations on the President’s base salary, the CEO and President make recommendation on the other NEOs’ base salaries, and the Compensation Committee must approve all annual merit increases, which take effect on January 1 of each year. Base salaries for all NEOs increased by 2.9% effective January 1, 2006. An increase or decrease in base pay may also result from a promotion or other significant change in an NEO’s responsibilities during the year. There were no base salary changes during the year after the January 1, 2006 merit increase.
Short-Term Incentive Compensation
The objective of short-term incentive compensation is to reward significant annual corporate goal achievement while also providing NEOs’ with competitive total cash compensation.
Performance Incentive Plan
Under the Performance Incentive Plan, or PIP, all NEOs are eligible to earn an annual cash incentive award. Awards are based on a variety of measures linked to our overall performance and each NEO’s contributions to that performance. Individual NEO performance is measured against objectives which commonly include both financial (e.g., net income and cash flow) and non-financial (e.g., customer service, operational excellence, employee commitment and safety, environmental respect and regulatory integrity) measures, as well as response to issues and opportunities that arise during the year. Incentive award payouts are discretionary, the amounts are determined on a subjective basis and they are not based on a specific formula or cap. For 2006, specific factors considered in determining the PIP awards included achievement of the corporate net income goal and the integration of PacifiCorp. The CEO and the President recommend annual incentive awards (excluding their own) to the Compensation Committee prior to the last meeting of each year. The CEO recommends the annual incentive award for the President, and the Compensation Committee determines the CEO’s award. If approved by the Compensation Committee, awards are paid prior to year-end. NEOs who terminate employment prior to the end of the calendar year are ineligible to receive the annual incentive award.
Performance Awards
In addition to the annual awards under the PIP, we may grant cash performance awards periodically during the year to one or more NEOs to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and approved by the President, as delegated by the CEO and the Compensation Committee. In 2006, awards were granted to Messrs. Goodman and Anderson and Ms. Sammon in recognition of the sustained effort necessary to obtain the prompt regulatory approval and consummation of the PacifiCorp acquisition. Although both Messrs. Sokol and Abel are eligible for performance awards, neither has been granted an award under this plan in the past five years.
Long-Term Incentive Compensation
The objective of long-term incentive compensation is to retain employees, reward exceptional performance and motivate NEOs to create long-term, sustainable value. Our current long-term incentive compensation programs are all cash-based. We have not issued stock options or other forms of equity-based awards since March 2000. All stock options previously granted relate to legacy options held by Messrs. Sokol and Abel and are fully vested.
Long-Term Incentive Partnership Plan
The MidAmerican Energy Holdings Company Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align our interests and the interests of the NEOs, other than our CEO and President who do not participate in the LTIP. Messrs. Goodman and Anderson and Ms. Sammon participate in this plan. The LTIP provides for annual awards based upon significant accomplishments by the individual participants and the achievement of net income, safety, risk management, environmental and other corporate goals. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated in January of each plan year. Participation is discretionary and is determined by the CEO and the President, who do not participate. The CEO and the President recommend awards to the Compensation Committee annually at the end of each year. Except for limited situations of extraordinary performance, awards are capped at 1.5 times base salary, and the value is finalized in January of the following year. These cash-based awards are subject to mandatory deferral and ratable vesting over a five-year period starting in the performance year. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation election. The participant may defer all or a part of the award or receive payment in cash. Vested balances (including any investment profits or losses thereon) of terminating participants are paid at the time of termination.
Incremental Profit Sharing Plan
The Incremental Profit Sharing Plan, or IPSP, is designed to align our interests and the interests of the CEO and the President. The IPSP provides for a cash award to each participant based upon our achievement of a specified adjusted diluted earnings per share target for each calendar year. The adjusted diluted earnings target of $12.37 per share to achieve the maximum award was established by the Compensation Committee in 2003 and had to be achieved no later than 2007. The maximum award target was achieved in 2006, and the final award was approved by the Compensation Committee and paid in November 2006. Specifics of the 2006 award calculation are discussed in a footnote to the Summary Compensation Table. Messrs. Goodman and Anderson and Ms. Sammon do not participate in this plan.
Other Employee Benefit Plans
NEOs are eligible to participate in the health and welfare, 401(k) and retirement benefit plans that are offered to our other employees. Additionally, if eligible, the NEOs may be a participant in the following plans:
Supplemental Executive Retirement Plan
The MidAmerican Energy Company Supplemental Retirement Plan for Designated Officers, or SERP, is a plan that provides additional retirement benefits to participants, as previously approved by the Board of Directors. We include the SERP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package and as a key retention tool. Messrs. Sokol, Abel and Goodman participate, and the current plan is currently closed to any new participants. The SERP provides annual retirement benefits of up to 65% of a participant’s Total Cash Compensation in effect immediately prior to retirement, subject to an annual $1 million maximum retirement benefit. Total cash compensation means (i) the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus (ii) the average of the participant’s last three years’ awards under an annual incentive bonus program and (iii) 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 of Directors. All eligible NEOs have met the five-year service requirement under the plan. The SERP benefit will be reduced by the amount of the participant’s regular retirement benefit under the MidAmerican Energy Company Retirement Plan and ratably for retirement between ages 55 and 65.
Deferred Compensation Plan
Our MEHC Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs to make voluntary deferrals of up to 50% of base salary and 100% of short- and long-term incentive compensation awards. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on eight notional investment options elected by the participant and the plan allows participants to choose from three forms of distribution. While the plan allows for company discretionary contributions, we have not made contributions to date. We include the DCP as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.
Financial Planning and Tax Preparation
This benefit provides certain NEOs with financial planning and tax preparation services. The value of the benefit is included in the NEO’s taxable income. All NEOs except Ms. Sammon receive this benefit. It is offered both as a competitive benefit itself and also to help ensure our NEOs best utilize the other forms of compensation we provide to them.
Executive Life Insurance
This benefit provides certain NEOs with universal life insurance having a death benefit of two times annual base salary during employment, reducing to one times annual base salary in retirement. The value of the benefit is included in the NEO’s taxable income. Messrs. Sokol, Abel and Goodman receive this benefit. We include the executive life insurance as part of the participating NEO’s overall compensation in order to provide a comprehensive, competitive package.
Impact of Accounting and Tax
Compensation paid under our executive compensation plans has been reported as an expense in our historical Consolidated Financial Statements. Recent changes in rules issued by the Financial Accounting Standards Board, principally Statement of Financial Accounting Standards No. 123(R), “Share-Based Payments,” which took effect for most public companies for fiscal years beginning after June 15, 2005, have had no impact on how we design or account for our executive compensation plans.
Potential Payments Upon Termination or Change-in-Control
Certain NEOs are entitled to post-termination payments in the event their employment is terminated under certain circumstances. We believe these post-termination payments are an important component of the competitive compensation package we offer to these NEOs. In particular, by agreeing to provide post-termination payments following a change-in-control, we believe we are encouraging our NEOs to focus on our growth strategy through acquisitions and achieve the best results for our shareholders without the distraction of contemplating how a particular transaction may affect them professionally or financially.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management and has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Form 10-K.
Summary Compensation Table
The following table sets forth information regarding compensation earned by each of our NEOs during the year ended December 31, 2006:
______________
(1)
Consists of annual cash incentive awards earned pursuant to the PIP for Messrs. Sokol, Abel, Goodman and Anderson and Ms. Sammon as well as performance awards earned related to the acquisition of PacifiCorp and the vesting of LTIP awards and associated earnings for Messrs. Goodman and Anderson and Ms. Sammon. The breakout is as follows:
LTIP awards vest equally over five years with any unvested balances forfeited upon termination of employment. Vested balances (including any investment performance profits or losses thereon) are paid to the participant at the time of termination. The participant may elect to defer or receive payment of part of or the entire award. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation election. Because the amounts to be paid out may increase or decrease depending on investment performance, the ultimate payouts are undeterminable. The initial values of the 2006 LTIP awards granted to Messrs. Goodman and Anderson and Ms. Sammon were based upon the following matrix and a net income target goal, which we do not disclose herein:
Net Income
Award
Less than or equal to target goal
None *
Exceeds target goal by 0.01% - 3.25%
15% of excess
Exceeds target goal by 3.251% - 6.50%
15% of the first 3.25% excess;
25% of excess over 3.25%
Exceeds target goal by more than 6.50%
15% of the first 3.25% excess;
25% of the next 3.25% excess;
35% of excess over 6.50%
*
The LTIP provides annual awards based upon significant accomplishments by the individual participant and the achievement of net income, safety, risk management, environmental and other corporate goals.
(2)
Consists of cash awards earned pursuant to the IPSP for Messrs. Sokol and Abel. In 2006, the adjusted diluted earnings target of $12.37 per share necessary to achieve the maximum award was achieved. Therefore, Messrs. Sokol and Abel received the amounts shown above and they are no longer eligible for further awards under this plan unless and until a new performance period and goals are established by the Compensation Committee.
(3)
Amounts are based upon the aggregate increase in the actuarial present value of all qualified and nonqualified defined benefit plans, which include our cash balance and supplemental retirement plans, as applicable. Amounts are computed using the SFAS No. 87, “Employers’ Accounting for Pensions,” or SFAS No. 87, assumptions used in preparing the applicable pension disclosures included in our Notes to the Consolidated Financial Statements and are as of the pension plans’ measurement dates. No participant in our DCP earned “above-market” or “preferential” earnings on amounts deferred.
(4)
Consists of vacation payouts and amounts related to life insurance premiums, medical and disability insurance premiums, and defined contribution plan matching contributions we paid on behalf of the NEOs, as well as perquisites and other personal benefits related to the personal use of corporate aircraft and financial planning and tax preparation that we paid on behalf of Messrs. Sokol, Abel and Goodman. The personal use of corporate aircraft represents our incremental cost of providing this personal benefit determined by applying the percentage of flight hours used for personal use to our variable expenses incurred from operating our corporate aircraft. All other compensation is based upon amounts paid by us.
Items required to be reported and quantified are as follows: Mr. Sokol - life insurance premiums of $59,636, personal use of corporate aircraft of $165,639 and financial planning and tax preparation of $30,550; Mr. Abel - life insurance premiums of $48,170, medical and disability insurance premiums of $12,550 and personal use of corporate aircraft of $186,434; Mr. Goodman - life insurance premiums of $10,814, medical and disability insurance premiums of $12,550 and vacation payouts of $14,753; and Mr. Anderson - medical and disability insurance premiums of $12,653 and vacation payouts of $21,768.
(5)
Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the summary compensation table.
(6)
We did not issue equity-based compensation as part of our long-term incentive compensation package in 2006 and therefore have omitted the Stock Awards and Option Awards columns from the Summary Compensation Table.
Grants of Plan-Based Awards
The following table sets forth information regarding plan-based awards earned by each of our NEOs during the year ended December 31, 2006:
______________
(1)
We did not issue equity-based compensation as part of our long-term incentive compensation package in 2006 and therefore have omitted the columns that would disclose such awards from the Grants of Plan-Based Awards Table.
(2)
Amounts for Messrs. Sokol and Abel consist of IPSP awards. As established by the Compensation Committee in 2003, the IPSP consisted of three potential award levels based upon the diluted earnings per share targets reached over the 2003 to 2007 period. Subject to an aggregate maximum of the awards of $37,500,000, the one-time profit sharing amounts each participant could achieve were as follows:
1. If our EPS for any calendar year through year-end 2007 was greater than $10.00 per share but less than or equal to $11.14 per share, each was to receive $11,250,000.
2. If our EPS for any calendar year through year-end 2007 was greater than $11.14 per share but less than or equal to $12.37 per share, each was to receive $18,780,000.
3. If our EPS for any calendar year through year-end 2007 was greater than $12.37 per share, each was to receive $37,500,000.
The $10.00 diluted EPS target was met in 2005, thus both Messrs. Sokol and Abel were paid $11,250,000 in that year. In 2006 the $12.37 maximum EPS target was achieved, thus the remaining total potential award of $26,250,000 - or $37,500,000 less the $11,250,000 already paid - was approved by the Compensation Committee and paid in 2006.
Outstanding Equity Awards at Fiscal Year-End
The following table sets forth information regarding outstanding equity awards held by each of our NEOs at December 31, 2006:
______________
(1)
We have not issued stock options or other forms of equity-based awards since March 2000. All outstanding stock options relate to previously granted options held by Messrs. Sokol and Abel and were fully vested prior to 2006. Accordingly, we have omitted the Stock Awards columns from the Outstanding Equity Awards at Fiscal Year-End Table.
Option Exercises
The following table sets forth information regarding stock options exercised by Messrs. Sokol and Abel during the year ended December 31, 2006:
______________
(1)
We have not issued stock options or other forms of equity-based awards since March 2000. All stock options relate to previously granted options held by Messrs. Sokol and Abel and were fully vested prior to 2006. Accordingly, we have omitted the Stock Awards columns from the Option Exercises and Stock Vested Table.
Pension Benefits
The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of our NEOs at December 31, 2006:
______________
(1)
The pension benefits for Messrs’ Sokol and Abel do not depend on their years of service, as both have already reached their maximum benefit levels based on their respective ages and previous triggering events described in their employment agreements. Mr. Goodman’s credited years of service includes eight years of service with us and, for purposes of the SERP only, four additional years of imputed service from a predecessor company.
(2)
Amounts are computed using the SFAS No. 87 assumptions used in preparing the applicable pension disclosures included in our Notes to the Consolidated Financial Statements and are as of December 31, 2006, the plans’ measurement date. The present value of accumulated benefits for the SERP was calculated using the following assumptions: (1) Mr. Sokol - a 100% joint and survivor annuity; (2) Mr. Abel - a 15-year certain and life annuity; and (3) Mr. Goodman - a 66 2/3% joint and survivor annuity. The present value of accumulated benefits for the MidAmerican Energy Company Retirement Plan was calculated using a lump sum payment assumption. The present value assumptions used in calculating the present value of accumulated benefits for both the SERP and the MidAmerican Energy Company Retirement Plan were as follows: a cash balance interest crediting rate of 5.03% in 2006, 5.71% in 2007 and 5.00% thereafter; a cash balance conversion rate of 4.50%; a discount rate of 5.75%; an expected retirement age of 65; and postretirement mortality using the 1994 GAM M/F tables.
The SERP provides additional retirement benefits to legacy participants, as previously approved by the Board of Directors. The SERP provides annual retirement benefits up to 65% of a participant’s Total Cash Compensation in effect immediately prior to retirement, subject to an annual $1 million maximum retirement benefit. Total Cash Compensation means (i) the highest amount payable to a participant as monthly base salary during the five years immediately prior to retirement multiplied by 12, plus (ii) the average of the participant’s last three years’ awards under an annual incentive bonus program and (iii) 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 of Directors. Participants must be credited with five years of service to be eligible to receive benefits under the SERP. The SERP benefit will be reduced by the amount of the participant’s regular retirement benefit under the MidAmerican Energy Company Retirement Plan and ratably for retirement between ages 55 and 65. 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 SERP. Benefits from the SERP will be paid out of general corporate funds; however, through a Rabbi trust, we maintain 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 SERP.
The MidAmerican Energy Company Retirement Plan replaced retirement plans of predecessor companies that were structured as traditional, defined benefit plans. Under the MidAmerican Energy Company Retirement Plan, each participant has an account, for record-keeping purposes only, to which credits are allocated annually based upon a percentage of the participant’s base salary paid in the plan year. 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 one-year constant maturity Treasury yield plus seven-tenths of one percentage point. Participants become vested in the MidAmerican Energy Company Retirement Plan after five years of credited service. 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 Energy Company Retirement Plan.
Nonqualified Deferred Compensation
The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of our NEOs at December 31, 2006:
______________
(1)
The contribution amounts shown for Messrs. Abel and Goodman are included within the total compensation reported for these individuals in the Summary Compensation Table and are not additional earned compensation. The contribution amount shown for Ms. Sammon includes $177,664 earned toward her 2002 LTIP award prior to 2006 and thus not included within the Summary Compensation Table.
(2)
Excludes the value of 10,041 shares of our common stock reserved for issuance to Mr. Abel. Mr. Abel deferred the then current value of these shares pursuant to a legacy nonqualified deferred compensation plan.
Eligibility for our DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. These deferrals enable participants to make up for amounts they may be unable to defer in our 401(k) plan due to its contribution limits. Deferrals and any investment returns grow on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term and long-term incentive compensation awards. All deferrals are net of social security taxes due on that bonus or award. Amounts deferred under the DCP receive a rate of return elected by the participant based on eight notional investment options. Gains or losses are calculated monthly, and returns are posted to accounts based on participants’ fund allocation elections. Participants can change their fund allocations as of the end of any calendar month.
The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement distribution, in-service distribution and education distribution. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments. The education account will be distributed in four annual installments. If a participant leaves employment prior to retirement (age 55) all amounts in the participant’s account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.
Potential Payments Upon Termination or Change-in-Control
We do not have stand-alone change-in-control arrangements with any of our NEOs. However, we have entered into employment agreements with Messrs. Sokol, Abel and Goodman which provide for payments following termination of employment at or following a change in control. Pursuant to these employment agreements, a change in control is deemed to occur:
·
upon our dissolution or the sale of substantially all of our assets;
·
upon consummation of a merger other than a merger (a) that results in our reincorporation in another state, and (b) where the holders of at least 50% of our outstanding voting securities prior to the merger continue to hold 50% of our outstanding voting securities after the merger;
·
if any person acquires directly or indirectly the beneficial ownership of more than 50% of our outstanding voting securities (other than securities acquired directly from us or our affiliates); and
·
if there has been a change in the composition of a majority of our Board of Directors over a period of thirty-six months or less.
Mr. Sokol’s employment will terminate upon his resignation, permanent disability, death, termination by us with or without cause, or our failure to provide Mr. Sokol with the compensation or to maintain the job responsibilities set forth in his employment agreement. A termination of employment of either Messrs. Abel or Goodman will occur upon his resignation (with or without good reason), permanent disability, death, or termination by us with or without cause.
The employment agreements for Messrs. Sokol and Abel also include provisions specific to the calculation of their respective SERP benefits. For purposes of those calculations, the agreements define a “Triggering Event” as a termination of employment by us without cause (as defined in the agreements), resignation or a change in control following a merger.
Neither Mr. Anderson nor Ms. Sammon has an employment agreement. Where a NEO does not have an employment agreement, or in the event that the agreements for Messrs. Sokol, Abel and Goodman do not address an issue, payments upon termination are determined by the applicable plan documents and our general employment policies and practices as discussed below.
The following discussion provides further detail on post-termination and change-in-control payments.
David L. Sokol
Mr. Sokol’s employment agreement provides that we may terminate his employment with cause, in which case we must pay him any accrued but unpaid base salary and a bonus of not less than the minimum annual bonus. If termination is due to death, permanent disability or other than for cause, including a change in control, Mr. Sokol is entitled to receive an amount equal to three times the sum of his annual base salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years, plus continuation of his senior executive employee benefits (or the economic equivalent thereof) for three years. If Mr. Sokol resigns, we must pay him any accrued but unpaid base 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.
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 his annual base salary then in effect and the greater of his minimum annual bonus or his average annual bonus for the two preceding years. This total payment as of December 31, 2006 is estimated at $6,700,000 (and is not included in the termination scenarios table below). He will also receive an annual salary of $750,000 and will be eligible for an annual bonus.
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 (i) any accrued but unpaid base salary plus an amount equal to the aggregate annual base 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 and (ii) the continuation of his senior executive employee benefits (or the economic equivalent thereof) through such fifth anniversary.
Payments made in accordance with the employment agreement are contingent on Mr. Sokol complying with the confidentiality and post-employment restrictions described therein. The term of the agreement expires on August 21, 2007, but is extended automatically for additional one year terms thereafter subject to Mr. Sokol’s election to decline renewal at least 120 days prior to the then current date or termination.
The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated above. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) account balances and those portions of life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2006, and are payable as lump sums unless otherwise noted.
______________
(1)
The amounts shown in the Following Change in Position termination scenario are only applicable if the termination is due to death, disability or other than for cause.
(2)
The cash severance payments are determined in accordance with Mr. Sokol’s employment agreement. The severance payments are to be made on or before the related termination date.
(3)
Life insurance benefits are equal to two times base salary, as of the preceding June 1st, less the benefits otherwise payable in all other termination scenarios, which are equal to the total cash value of the policies less cumulative premiums paid by us.
(4)
Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table. Mr. Sokol’s death scenario is based on a 100% joint and survivor with 15-year certain annuity commencing immediately. Mr. Sokol’s other termination scenarios are based on a 100% joint and survivor annuity commencing immediately.
(5)
Includes health and welfare, life and disability insurance and financial planning and tax preparation benefits for three years (five years in the case of termination following a change in position). The health and welfare benefit amounts are estimated using the rates we currently charge employees terminating employment but electing to continue their medical, dental and vision insurance after termination. These amounts are grossed-up for taxes and then reduced by the amount Mr. Sokol would have paid if he had continued his employment. The life and disability insurance benefit amounts are based on the cost of individual policies offering benefits equivalent to our group coverage and are grossed-up for taxes. These amounts also assume benefit continuation for the entire three year period (five year period in the case of termination following a change in position), with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for three years or pay a lump sum cash amount to keep Mr. Sokol in the same economic position on an after-tax basis. The amount included is based on an annual estimated cost using the most recent three-year average annual reimbursement.
(6)
As provided in Mr. Sokol’s employment agreement, should it be deemed under Section 280G of the Internal Revenue Code that termination payments constitute excess parachute payments arising from a change in control and are therefore subject to an excise tax, we will gross up such payments to cover the excise tax and any additional taxes associated with such gross-up. Based on computations prescribed under Section 280G and related regulations, we do not believe that any of the termination scenarios are subject to an excise tax.
Gregory E. Abel
Mr. Abel’s employment agreement entitles him to receive two years base salary continuation and payments in respect of average bonuses for the prior two years in the event we terminate his employment other than for cause. The payments are to be paid ratably over 24 monthly installments, unless such termination is on or after a change in control, in which case the amount is to be paid as a lump sum with no discount for present valuation.
In addition, if Mr. Abel’s employment is terminated due to death, permanent disability or other than for cause, including a change in control, he is entitled to continuation of his senior executive employee benefits (or the economic equivalent thereof) for two years. If Mr. Abel resigns, we must pay him any accrued but unpaid base salary, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.
Payments made in accordance with the employment agreement are contingent on Mr. Abel complying with the confidentiality and post-employment restrictions described therein. The term of the agreement expires on August 6, 2007, but is extended automatically for additional one year terms thereafter subject to Mr. Abel’s election to decline renewal at least 365 days prior to the then current date or termination.
The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2006, and are payable as lump sums unless otherwise noted.
______________
(1)
The cash severance payments are determined in accordance with Mr. Abel’s employment agreement and would be paid in 24 equal monthly installments (beginning one month after termination), provided such termination occurred prior to a change in control. However, if these same events occurred on or after a change in control, Mr. Abel would receive the same payments described herein in a single lump sum without any discount to reflect present value.
(2)
Life insurance benefits are equal to two times base salary, as of the preceding June 1st, less the benefits otherwise payable in all other termination scenarios, which are equal to the total cash value of the policies less cumulative premiums paid by us.
(3)
Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table. Mr. Abel’s death scenario is based on a 100% joint and survivor with 30-year certain annuity commencing immediately. Mr. Abel’s other termination scenarios are based on a 100% joint and survivor with 15-year certain annuity commencing at age 47.
(4)
Includes health and welfare, life and disability insurance and financial planning and tax preparation benefits for two years. The health and welfare benefit amounts are estimated using the rates we currently charge employees terminating employment but electing to continue their medical, dental and vision insurance after termination. These amounts are grossed-up for taxes and then reduced by the amount Mr. Abel would have paid if he had continued his employment. The life and disability insurance benefit amounts are based on the cost of individual policies offering benefits equivalent to our group coverage and are grossed-up for taxes. These amounts also assume benefit continuation for the entire two year period, with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for two years or pay a lump sum cash amount to keep Mr. Abel in the same economic position on an after-tax basis. The amount included is based on an annual estimated cost using the most recent three-year average annual reimbursement.
(5)
As provided in Mr. Abel’s employment agreement, should it be deemed under Section 280G of the Internal Revenue Code that termination payments constitute excess parachute payments arising from a change in control and are therefore subject excise tax, we will gross up such payments to cover the excise tax and any additional taxes associated with such gross-up. Based on computations prescribed under Section 280G and related regulations, we believe that none of the termination scenarios are subject to any excise tax.
Patrick J. Goodman
Mr. Goodman’s employment agreement entitles him to receive two years base salary continuation and payments in respect of average bonuses for the prior two years in the event we terminate his employment other than for cause. The payments are to be paid ratably in 24 monthly installments, unless such termination is on or after a change in control, in which case the amount is to be paid as a lump sum with no discount for present valuation.
In addition, if Mr. Goodman’s employment is terminated due to death, permanent disability or other than for cause, including a change in control, he is entitled to continuation of his senior executive employee benefits (or the economic equivalent thereof) for one year. If Mr. Goodman resigns, we must pay him any accrued but unpaid base salary, unless he resigns for good reason, in which case he will receive the same benefits as if he were terminated other than for cause.
Payments made in accordance with the employment agreement are contingent on Mr. Goodman complying with the confidentiality and post-employment restrictions described therein. The term of the agreement expires on April 21, 2007, but is extended automatically for additional one year terms thereafter subject to Mr. Goodman’s election to decline renewal at least 365 days prior to the then current date or termination.
The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments, life insurance benefits and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2006, and are payable as lump sums unless otherwise noted.
______________
(1)
The cash severance payments are determined in accordance with Mr. Goodman’s employment agreement and would be paid in 24 equal monthly installments (beginning one month after termination), provided such termination occurred prior to a change in control. However, if these same events occurred on or after a change in control, Mr. Goodman would receive the same payments described herein in a single lump sum without any discount to reflect present value.
(2)
Amounts represent the unvested portion of Mr. Goodman’s LTIP account, which becomes 100% vested upon his death or disability.
(3)
Life insurance benefits are equal to two times base salary, as of the preceding June 1st, less the benefits otherwise payable in all other termination scenarios, which are equal to the total cash value of the policies less cumulative premiums paid by us.
(4)
Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table. Mr. Goodman’s voluntary termination, retirement, involuntary without cause, and change in control termination scenarios are based on a 66 2/3% joint and survivor annuity commencing at age 55 (reductions for termination prior to age 55 and commencement prior to age 65). Mr. Goodman’s disability scenario is based on a 66 2/3% joint and survivor annuity commencing at age 55 (no reduction for termination prior to age 55, reduced for commencement prior to age 65). Mr. Goodman’s death scenario is based on a 100% joint and survivor with 15-year certain annuity commencing immediately (no reduction for termination prior to age 55 and commencement prior to age 65).
(5)
Includes health and welfare, life and disability insurance and financial planning and tax preparation benefits for one year. The health and welfare benefit amounts are estimated using the rates we currently charge employees terminating employment but electing to continue their medical, dental and vision insurance after termination. These amounts are grossed-up for taxes and then reduced by the amount Mr. Goodman would have paid if he had continued his employment. The life and disability insurance benefit amounts are based on the cost of individual policies offering benefits equivalent to our group coverage and are grossed-up for taxes. These amounts also assume benefit continuation for the entire one year period, with no offset by another employer. We will also continue to provide financial planning and tax preparation reimbursement, or the economic equivalent thereof, for one year or pay a lump sum cash amount to keep Mr. Goodman in the same economic position on an after-tax basis. The amount included is based on an annual estimated cost using the most recent three-year average annual reimbursement.
(6)
As provided in Mr. Goodman’s employment agreement, should it be deemed under Section 280G of the Internal Revenue Code that termination payments constitute excess parachute payments arising from a change in control and are therefore subject excise tax, we will gross up such payments to cover the excise tax and any additional taxes associated with such gross-up. Based on computations prescribed under Section 280G and related regulations, we believe that only the Involuntary Without Cause and Voluntary With Good Reason termination scenarios are subject to any excise tax.
Douglas L. Anderson
The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2006, and are payable as lump sums unless otherwise noted.
______________
(1)
Amounts represent the unvested portion of Mr. Anderson’s LTIP account, which becomes 100% vested upon his death or disability.
(2)
Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table.
Maureen E. Sammon
The following table sets forth the estimated enhancements to payments pursuant to the termination scenarios indicated. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments and cash balance pension amounts that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2006, and are payable as lump sums unless otherwise noted.
______________
(1)
Amounts represent the unvested portion of Ms. Sammon’s LTIP account, which becomes 100% vested upon her death or disability.
(2)
Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits Table.
Director Compensation
Our directors are not paid any fees for serving as directors. All directors are reimbursed for their expenses incurred in attending Board of Directors meetings.
Compensation Committee Report and Compensation Committee Interlocks and Insider Participation
Our Compensation Committee is comprised of Messrs. Warren E. Buffett and Walter Scott, Jr. The Compensation Committee is responsible for the establishment and oversight of our compensation policy. In certain circumstances, the Compensation Committee delegates compensation decisions to the CEO and the President, who make recommendations to the Compensation Committee, at least annually, regarding merit increases and incentive and performance awards. Approval of compensation decisions is made by the Compensation Committee, unless specifically delegated.
Mr. Warren E. Buffett is the Chairman of the Board and Chief Executive Officer of Berkshire Hathaway, our majority owner. Mr. Walter Scott, Jr. is a former officer of ours. None of our executive officers serve as a member of the Compensation Committee of any other company that has an executive officer serving as a member of our Board of Directors. None of our executive officers serve as a member of the board of directors of any other company that has an executive officer serving as a member of our Compensation Committee. See also Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Beneficial Ownership
We are a consolidated subsidiary of Berkshire Hathaway. The remainder of our common stock is owned by a private investor group comprised of Mr. Scott, Mr. Sokol and Mr. Abel. The following table sets forth certain information regarding beneficial ownership of our shares of common stock held by each of our directors, executive officers and all of our directors and executive officers as a group as of January 31, 2007:
(1)
Unless otherwise indicated, each address is c/o MEHC at 666 Grand Avenue, 29th Floor, Des Moines, Iowa 50309.
(2)
Includes shares of 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)
Such beneficial owner’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.
(4)
Excludes 3,228,000 shares held by family members and family controlled trusts and corporations (“Scott Family Interests”) as to which Mr. Scott disclaims beneficial ownership. Mr. Scott’s address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.
(5)
Includes options to purchase 549,277 shares of common stock that are presently exercisable or become exercisable within 60 days.
(6)
Includes options to purchase 524,052 shares of common stock that are presently exercisable or become exercisable within 60 days. Excludes 10,041 shares reserved for issuance pursuant to a deferred compensation plan.
(7)
Excludes 65,433,130 shares of common stock held by Berkshire Hathaway as to which Messrs. Buffett and Hamburg disclaim beneficial ownership.
The following table sets forth certain information regarding beneficial ownership of Class A and Class B shares of Berkshire Hathaway’s common stock held by each of our directors, executive officers and all of our directors and executive officers as a group as of January 31, 2007:
(1)
Unless otherwise indicated, each address is c/o MEHC 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)
Does not include 10 Class A shares owned by Mr. Scott’s wife. Mr. Scott’s address is 1000 Kiewit Plaza, Omaha, Nebraska 68131.
(4)
In accordance with a shareholders agreement, as amended on December 7, 2005, based on an assumed value for our common stock and the closing price of Berkshire Hathaway common stock on January 31, 2007, Mr. Scott and the Scott Family Interests and Messrs. Sokol and Abel would be entitled to exchange their shares of our common stock and their shares acquired by exercise of options to purchase our common stock for either 13,040, 1,875 and 1,193, respectively, shares of Berkshire Hathaway Class A stock or 391,328, 56,275 and 35,792, respectively, shares of Berkshire Hathaway Class B stock. Assuming an exchange of all available MEHC shares into either Berkshire Hathaway Class A shares or Berkshire Hathaway Class B shares, Mr. Scott and the Scott Family Interests would beneficially own 1.17% of the outstanding shares of Berkshire Hathaway Class A stock or 2.95% of the outstanding shares of Berkshire Hathaway Class B stock, and each of Messrs. Sokol and Abel would beneficially own less than 1% or more of the outstanding shares of either class of stock.
(5)
Includes 350,000 Class A shares and 3,139,820 Class B shares owned directly and beneficially by Warren E. Buffett. Also includes 23,322 Class A shares and 177 Class B shares owned by the estate of Susan T. Buffett of which Mr. Buffett is the executor but with respect to which Mr. Buffett disclaims any beneficial interest. Mr. Buffett’s address is 1440 Kiewit Plaza, Omaha, Nebraska 68131.
Other Matters
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 nominate two additional directors.
Pursuant to a shareholders agreement, as amended on December 7, 2005, Mr. Scott or any of the Scott Family Interests and Messrs. Sokol and Abel are able to require Berkshire Hathaway to exchange any or all of their respective shares of our common stock for shares of Berkshire Hathaway common stock. The number of shares of Berkshire Hathaway stock to be exchanged is based on the fair market value of our common stock divided by the closing price of the Berkshire Hathaway stock on the day prior to the date of exchange.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Certain Relationships and Related Transactions
The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the MEHC Code of Business Conduct, or the Codes, which apply to all of our directors, officers and employees and those of our subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which we or any of our subsidiaries participate and in which one or more of our directors, executive officers, holders of more than five percent of our voting securities or any of such persons’ immediate family members have a direct or indirect material interest.
Under the Codes, all of our directors and executive officers (including those of our subsidiaries) must disclose to our legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with our interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For our chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway’s audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with our interests. Transactions with Berkshire Hathaway require the approval of our Board of Directors.
Under a subscription agreement with us, which expires in March 2007, Berkshire Hathaway has agreed to purchase, under certain circumstances, additional shares of 11% trust issued mandatorily redeemable preferred securities to be issued by our wholly owned subsidiary trust in the event that certain of our other outstanding trust preferred securities which were outstanding prior to the closing of our acquisition by a private investor group on March 14, 2000 are tendered for conversion to cash by the current holders.
At December 31, 2006 and 2005, Berkshire Hathaway and its affiliates held 11% mandatorily redeemable preferred securities due from certain of our wholly owned subsidiary trusts with liquidation preferences of $1,055.2 million and $1,289.2 million, respectively. Principal repayments and interest expense on these securities totaled $234.0 million and $133.8 million, respectively, during 2006.
On February 9, 2006, following the effective date of the repeal of PUHCA 1935, Berkshire Hathaway converted its 41,263,395 shares of our no par zero-coupon convertible preferred stock into an equal number of shares of our common stock.
On March 1, 2006, we entered into the Berkshire Equity Commitment with Berkshire Hathaway pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of our common equity upon any requests authorized from time to time by our Board of Directors. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due our debt obligations and (b) funding the general corporate purposes and capital requirements of our regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011.
On March 6, 2006, we issued 450,000 shares of our common stock, no par value, to Mr. Sokol upon the exercise by Mr. Sokol of 450,000 of his outstanding common stock options. The common stock options were exercisable at a price of $29.01 per share and the aggregate exercise price paid by Mr. Sokol was $13.1 million. This issuance was pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended. Additionally, on March 6, 2006, we repurchased 344,274 shares of our common stock from Mr. Sokol for a purchase price of $50.0 million.
On March 21, 2006, Berkshire Hathaway and certain other of our existing shareholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of our common stock in order to provide equity funding for the PacifiCorp acquisition. The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by our shareholders.
On March 28, 2006, we repurchased 11,724,138 shares of our common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.
On November 15, 2006, we issued 200,000 shares of our common stock, no par value, to Mr. Sokol upon the exercise by Mr. Sokol of 200,000 of his outstanding common stock options. The common stock options were exercisable at a price of $34.69 per share and the aggregate exercise price paid by Mr. Sokol was $6.9 million. We also issued, on November 15, 2006, 125,000 shares of our common stock, no par value, to Mr. Abel upon the exercise by Mr. Abel of 125,000 of his outstanding common stock options. The common stock options were exercisable at a weighted-average price of $17.68 per share and the aggregate exercise price paid by Mr. Abel was $2.2 million. These issuances were pursuant to private placements and were exempt from the registration requirements of the Securities Act of 1933, as amended.
Director Independence
Based on the standards of the New York Stock Exchange, on which the common stock of our majority owner, Berkshire Hathaway, is listed, our Board of Directors has determined that none of our directors are considered independent because of their employment by Berkshire Hathaway or MEHC or their ownership of our common stock.
Item 14.
Item 14. Principal Accountant Fees and Services.
The following table shows the Company’s fees paid or accrued for audit services and fees paid for audit-related, tax and all other services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the “Deloitte Entities”) for each of the last two years (in millions):
(1)
Audit fees include fees for the audit of the Company’s consolidated financial statements and interim reviews of the Company’s quarterly financial statements, audit services provided in connection with required statutory audits of certain of MEHC’s subsidiaries and comfort letters, consents and other services related to SEC matters.
(2)
Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain subsidiary employee benefit plans and consultations on various accounting and reporting matters.
(3)
Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits.
The audit committee reviewed and approved the services rendered by the Deloitte Entities in and for fiscal 2006 as set forth in the above table and concluded that the non-audit services were compatible with maintaining the principal accountant’s independence. Under the Sarbanes-Oxley Act of 2002, all audit and non-audit services performed by the Company’s principal accountant require the approval in advance by the audit committee in order to assure that such services do not impair the principal accountant’s independence from the Company. Accordingly, the audit committee has an Audit and Non-Audit Services Pre-Approval Policy (the “Policy”) which sets forth the procedures and the conditions pursuant to which services to be performed by the principal accountant are to be pre-approved. Pursuant to the Policy, certain services described in detail in the Policy may be pre-approved on an annual basis together with pre-approved maximum fee levels for such services. The services eligible for annual pre-approval consist of services that would be included under the categories of Audit Fees, Audit-Related Fees and Tax Fees. If not pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being performed by the principal accountant. In addition, any services that receive annual pre-approval but exceed the pre-approved maximum fee level also will require separate approval by the audit committee prior to being performed. The Policy does not delegate the audit committee’s responsibilities to pre-approve services performed by the principal accountant to management.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
Schedule I
MidAmerican Energy Holdings Company
Parent Company Only
Condensed Balance Sheets
As of December 31, 2006 and 2005
(Amounts in millions)
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
Schedule I
MidAmerican Energy Holdings Company
Parent Company Only (continued)
Condensed Statements of Operations
For the three years ended December 31, 2006
(Amounts in millions)
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
Schedule I
MidAmerican Energy Holdings Company
Parent Company Only (continued)
Condensed Statements of Cash Flows
For the three years ended December 31, 2006
(Amounts in millions)
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
Schedule II
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2006
(Amounts in millions)
The notes to the consolidated MEHC financial statements are an integral part of this financial statement schedule.
(1)
Acquisition reserves represent the reserves recorded at PacifiCorp at the date of acquisition.
(2)
Reserves not deducted from assets relate primarily to estimated liabilities for losses retained by MEHC for workers compensation, public liability and property damage claims.
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 on this 1st day of March 2007.
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
Title
Date
/s/ David L. Sokol*
Chairman of the Board,
March 1, 2007
David L. Sokol
Chief Executive Officer, and Director
/s/ Gregory E. Abel*
President, Chief Operating Officer
March 1, 2007
Gregory E. Abel
and Director
/s/ Patrick J. Goodman
Senior Vice President and
March 1, 2007
Patrick J. Goodman
Chief Financial Officer
/s/ Walter Scott, Jr.*
Director
March 1, 2007
Walter Scott, Jr.
/s/ Marc D. Hamburg*
Director
March 1, 2007
Marc D. Hamburg
/s/ Warren E. Buffett*
Director
March 1, 2007
Warren E. Buffett
* By: /s/ Douglas L. Anderson
Attorney-in-Fact
March 1, 2007
Douglas L. Anderson
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
No annual report to security holders covering MidAmerican Energy Holdings Company’s last fiscal year or proxy material has been sent to security holders.
EXHIBIT INDEX
Exhibit No.
3.1
Second Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective March 2, 2006 (incorporated by reference to Exhibit 3.1 to MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
3.2
Amended and Restated Bylaws of MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 3.2 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.1
Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, as Trustee relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.2
First Supplemental Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 4.625% Senior Notes due 2007 and the 5.875% Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.3
Second Supplemental Indenture, dated as of May 16, 2003, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 3.50% Senior Notes due 2008 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Holdings Company’s Registration Statement No. 333-105690 dated May 23, 2003).
4.4
Third Supplemental Indenture, dated as of February 12, 2004, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee, relating to the 5.00% Senior Notes due 2014 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Holdings Company Registration Statement No. 333-113022 dated February 23, 2004).
4.5
Fourth Supplemental Indenture, dated as of March 24, 2006, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.125% Senior Bonds due (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 28, 2006).
4.6
Indenture dated as of February 26, 1997, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee relating to the 6 ¼% Convertible Junior Subordinated Debentures due 2012 (incorporated by reference to Exhibit 10.129 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1995).
4.7
Indenture, dated as of October 15, 1997, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Holdings Company Current Report on Form 8-K dated October 23, 1997).
4.8
Form of First Supplemental Indenture, dated as of October 28, 1997, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 7.63% Senior Notes in the principal amount of $350,000,000 due 2007 (incorporated by reference to Exhibit 4.2 to MidAmerican Energy Holdings Company’s Current Report on Form 8-K dated October 23, 1997).
Exhibit No.
4.9
Form of Second Supplemental Indenture dated as of September 22, 1998 by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the principal amount of $450,000,000 due 2008, and 8.48% Senior Notes in the principal amount of $475,000,000 due 2028 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated September 17, 1998.)
4.10
Form of Third Supplemental Indenture dated as of November 13, 1998, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 7.52% Senior Notes in the principal amount of $100,000,000 due 2008 (incorporated by reference to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated November 10, 1998).
4.11
Indenture, dated as of March 14, 2000, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.9 to MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
4.12
Indenture, dated as of March 12, 2002, by and between MidAmerican Energy Holdings Company and the Bank of New York, Trustee (incorporated by reference to Exhibit 4.11 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2001).
4.13
Amended and Restated Declaration of Trust of MidAmerican Capital Trust III, dated as of August 16, 2002 (incorporated by reference to Exhibit 4.14 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.14
Amended and Restated Declaration of Trust of MidAmerican Capital Trust II, dated as of March 12, 2002 (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.15
Amended and Restated Declaration of Trust of MidAmerican Capital Trust I, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.16 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.16
Indenture, dated as of August 16, 2002, by and between MidAmerican Energy Holdings Company and the Bank of New York, as Trustee (incorporated by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
4.17
Amended and Restated Credit Agreement, dated as of July 6, 2006, by and among MidAmerican Energy Holdings Company, as Borrower, The Banks and Other Financial Institutions Parties Hereto, as Banks, JPMorgan Chase Bank, N.A., as L/C Issuer, Union Bank of California, N.A., as Administrative Agent, The Royal Bank of Scotland PLC, as Syndication Agent, and ABN Amro Bank N.V., JPMorgan Chase Bank, N.A. and BNP Paribas as Co-Documentation Agents (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
4.18
Trust Indenture, dated as of November 27, 1995, by and between CE Casecnan Water and Energy Company, Inc. and Chemical Trust Company of California, Trustee (incorporated by reference to Exhibit 4.1 to the CE Casecnan Water and Energy Company, Inc. Registration Statement on Form S-4 dated January 25, 1996).
4.19
Indenture and First Supplemental Indenture, dated March 11, 1999, by and between MidAmerican Funding LLC and IBJ Whitehall Bank & Trust Company, Trustee, relating to the $700 million Senior Notes and Bonds (incorporated by reference to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1998).
Exhibit No.
4.20
Second Supplemental Indenture, dated as of March 1, 2001, by and between MidAmerican Funding, LLC and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.4 to MidAmerican Funding LLC Registration Statement on Form S-3, Registration No. 333-56624).
4.21
General Mortgage Indenture and Deed of Trust, dated as of January 1, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-1 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
4.22
First Supplemental Indenture, dated as of January 1, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-2 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
4.23
Second Supplemental Indenture, dated as of January 15, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4(b)-3 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1992, Commission File No. 1-10654).
4.24
Third Supplemental Indenture, dated as of May 1, 1993, by and between Midwest Power Systems Inc. and Morgan Guaranty Trust Company of New York, Trustee (incorporated by reference to Exhibit 4.4 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1993, Commission File No. 1-10654).
4.25
Fourth Supplemental Indenture, dated as of October 1, 1994, by and between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.5 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
4.26
Fifth Supplemental Indenture, dated as of November 1, 1994, by and between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.6 to the Midwest Resources Inc. Annual Report on Form 10-K for the year ended December 31, 1994, Commission File No. 1-10654).
4.27
Sixth Supplemental Indenture, dated as of July 1, 1995, by and between Midwest Power Systems Inc. and Harris Trust and Savings Bank, Trustee (incorporated by reference to Exhibit 4.15 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 1995, Commission File No. 1-11505).
4.28
Indenture dated as of December 1, 1996, by and between MidAmerican Energy Company and the First National Bank of Chicago, Trustee (incorporated by reference to Exhibit 4(1) to the MidAmerican Energy Company Registration Statement on Form S-3, Registration No. 333-15387).
4.29
First Supplemental Indenture, dated as of February 8, 2002, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.3 to MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
4.30
Second Supplemental Indenture, dated as of January 14, 2003, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.2 to MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
Exhibit No.
4.31
Third Supplemental Indenture, dated as of October 1, 2004, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.1 to MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 333-15387).
4.32
Fourth Supplemental Indenture, dated November 1, 2005, by and between MidAmerican Energy Company and the Bank of New York Trust Company, NA, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.33
Fiscal Agency Agreement, dated as of October 15, 2002, by and between Northern Natural Gas Company and J.P. Morgan Trust Company, National Association, Fiscal Agent, relating to the $300,000,000 in principal amount of the 5.375% Senior Notes due 2012 (incorporated by reference to Exhibit 10.47 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
4.34
Trust Indenture, dated as of August 13, 2001, among Kern River Funding Corporation, Kern River Gas Transmission Company and JP Morgan Chase Bank, Trustee, relating to the $510,000,000 in principal amount of the 6.676% Senior Notes due 2016 (incorporated by reference to Exhibit 10.48 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
4.35
Third Supplemental Indenture, dated as of May 1, 2003, among Kern River Funding Corporation, Kern River Gas Transmission Company and JPMorgan Chase Bank, Trustee, relating to the $836,000,000 in principal amount of the 4.893% Senior Notes due 2018 (incorporated by reference to Exhibit 10.49 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
4.36
Trust Deed, dated December 15, 1997 among CE Electric UK Funding Company, AMBAC Insurance UK Limited and The Law Debenture Trust Corporation, p.l.c., Trustee (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
4.37
Insurance and Indemnity Agreement, dated December 15, 1997 by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
4.38
Supplemental Agreement to Insurance and Indemnity Agreement, dated September 19, 2001, by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 30, 2004).
4.39
Fiscal Agency Agreement, dated as of September 4, 1998, by and between Northern Natural Gas Company and Chase Bank of Texas, National Association, Fiscal Agent, relating to the $150,000,000 in principal amount of the 6.75% Senior Notes due 2008 (incorporated by reference to Exhibit 10.69 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.40
Fiscal Agency Agreement, dated as of May 24, 1999, by and between Northern Natural Gas Company and Chase Bank of Texas, National Association, Fiscal Agent, relating to the $250,000,000 in principal amount of the 7.00% Senior Notes due 2011 (incorporated by reference to Exhibit 10.70 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.41
Trust Indenture, dated as of September 10, 1999, by and between Cordova Funding Corporation and Chase Manhattan Bank and Trust Company, National Association, Trustee, relating to the $225,000,000 in principal amount of the 8.75% Senior Secured Bonds due 2019 (incorporated by reference to Exhibit 10.71 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
Exhibit No.
4.42
Indenture, dated as of December 15, 1997, among CE Electric UK Funding Company, The Bank of New York, Trustee, and Banque Internationale A Luxembourg S.A., Paying Agent (incorporated by reference to Exhibit 10.72 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.43
First Supplemental Indenture, dated as of December 15, 1997, among CE Electric UK Funding Company, The Bank of New York, Trustee, and Banque Internationale A Luxembourg S.A., Paying Agent, relating to the $237,000,000 in principal amount of the 6.995% Senior Notes due (incorporated by reference to Exhibit 10.73 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.44
Trust Deed, dated as of February 4, 1998 among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.74 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.45
First Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.75 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.46
Third Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Electricity Distribution plc, Yorkshire Electricity Group plc and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 9.25% Bonds due 2020 (incorporated by reference to Exhibit 10.76 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.47
Indenture, dated as of February 1, 1998, and Second Supplemental Indenture, dated as of February 25, 1998, each among Yorkshire Power Finance Limited, Yorkshire Power Group Limited, The Bank of New York, Trustee, and Banque Internationale du Luxembourg S.A., Paying Agent, relating to the $300,000,000 in principal amount of the 6.496% Notes due 2008 (incorporated by reference to Exhibit 10.77 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.48
Indenture, dated as of February 1, 2000, among Yorkshire Power Finance 2 Limited, Yorkshire Power Group Limited and The Bank of New York, Trustee (incorporated by reference to Exhibit 10.78 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.49
First Supplemental Trust Deed, dated as of September 27, 2001, among Northern Electric Finance plc, Northern Electric plc, Northern Electric Distribution Limited and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.81 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.50
Trust Deed, dated as of January 17, 1995, by and between Yorkshire Electricity Group plc and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 9 1/4% Bonds due 2020 (incorporated by reference to Exhibit 10.83 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
Exhibit No.
4.51
Master Trust Deed, dated as of October 16, 1995, by and between Northern Electric Finance plc, Northern Electric plc and The Law Debenture Trust Corporation p.l.c., Trustee, relating to the £100,000,000 in principal amount of the 8.875% Guaranteed Bonds due 2020 (incorporated by reference to Exhibit 10.70 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2004).
4.52
Fiscal Agency Agreement, dated April 14, 2005, by and between Northern Natural Gas Company and J.P. Morgan Trust Company, National Association, Fiscal Agent, relating to the $100,000,000 in principal amount of the 5.125% Senior Notes due 2015 (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated April 18, 2005).
4.53
£100,000,000 Facility Agreement, dated April 4, 2005 among CE Electric UK Funding Company, the subsidiaries of CE Electric UK Funding Company listed in Part 1 of Schedule 1, Lloyds TSB Bank plc and The Royal Bank of Scotland plc (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated April 20, 2005).
4.54
Trust Deed dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.55
Reimbursement and Indemnity Agreement dated May 5, 2005 amoung Northern Electric Finance plc, Northern Electric Distribution Limited and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.2 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.56
Trust Deed, dated May 5, 2005 among Yorkshire Electricity Distribution plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.3 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.57
Reimbursement and Indemnity Agreement, dated May 5, 2005 between Yorkshire Electricity Distribution plc and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.4 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.58
Supplemental Trust Deed, dated May 5, 2005 among CE Electric UK Funding Company, Ambac Assurance UK Limited and The Law Debenture Trust Corporation plc (incorporated by reference to Exhibit 99.5 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.59
Second Supplemental Agreement to Insurance and Indemnity Agreement, dated May 5, 2005 by and between CE Electric UK Funding Company and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.6 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.60
Credit Agreement, dated as of November 18, 2004, among MidAmerican Energy Company, the Lending Institutions Party Hereto, Banks, Union Bank of California, N.A., Syndication Agent, and JPMorgan Chase Bank, N.A., Administrative Agent, and Union Bank of California, N.A. and J.P.Morgan Securities, Inc. Co-Lead Arrangers and Co-Book Runners (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.61
Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
Exhibit No.
4.62
Amendment No. 1 to Shareholders Agreement, dated December 7, 2005 (incorporated by reference to Exhibit 4.17 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.63
Equity Commitment Agreement, dated as of March 1, 2006, by and between Berkshire Hathaway, Inc. and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 10.72 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.64
Fiscal Agency Agreement, dated February 12, 2007, by and between Northern Natural Gas Company and Bank of New York Trust Company, N.A., Fiscal Agent, relating to the $150,000,000 in principal amount of the 5.80% Senior Bonds due 2037 (incorporated by reference to Exhibit 99.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated February 12, 2007).
4.65
Indenture, dated as of October 1, 2006, by and between MidAmerican Energy Company and the Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
4.66
First Supplemental Indenture, dated as of October 6, 2006, by and between MidAmerican Energy Company and the Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30,2006).
4.67
Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and JP Morgan Chase Bank (formerly known as The Chase Manhattan Bank), Trustee, Ex. 4-E, Form 8-B, File No. 1-5152, as supplemented and modified by 19 Supplemental Indentures as follows:
Exhibit Number
File Type
File Date
File Number
(4)(b)
8-K
January 9,
33-31861
(4)(a)
8-K
September 11,
1-5152
4(a)
8-K
January 7,
1-5152
4(a)
10-Q
Quarter ended March 31, 1992
1-5152
4(a)
10-Q
Quarter ended September 30, 1992
1-5152
4(a)
8-K
April 1,
1-5152
4(a)
10-Q
Quarter ended September 30, 1993
1-5152
(4)b
10-Q
Quarter ended June 30, 1994
1-5152
(4)b
10-K
Year ended December 31, 1994
1-5152
(4)b
10-K
Year ended December 31, 1995
1-5152
(4)b
10-K
Year ended December 31, 1996
1-5152
(4)b
10-K
Year ended December 31, 1998
1-5152
99(a)
8-K
November 21,
1-5152
4.1
10-Q
Quarter ended June 30, 2003
1-5152
8-K
September 8,
1-5152
8-K
August 24,
1-5152
8-K
June 13,
1-5152
8-K
August 14,
1-5152
10.1
Amended and Restated Employment Agreement, dated May 10, 1999, by and between MidAmerican Energy Holdings Company and David L. Sokol (incorporated by reference to Exhibit 10.1 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.2
Amendment No. 1 to the Amended and Restated Employment Agreement, dated March 14, 2000, by and between MidAmerican Energy Holdings Company and David L. Sokol (incorporated by reference to Exhibit 10.2 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
Exhibit No.
10.3
Non-Qualified Stock Option Agreements of David L. Sokol, dated March 14, 2000 (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
10.4
Amended and Restated Employment Agreement, dated May 10, 1999, by and between MidAmerican Energy Holdings Company and Gregory E. Abel (incorporated by reference to Exhibit 10.3 to MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.5
Non-Qualified Stock Option Agreements of Gregory E. Abel, dated March 14, 2000 (incorporated by reference to Exhibit 10.5 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
10.6
Employment Agreement, dated April 21, 1999, by and between MidAmerican Energy Holdings Company and Patrick J. Goodman (incorporated by reference to Exhibit 10.5 to MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.7
MW Power Plant-Mahanagdong Agreement, dated September 18, 1993, among Philippine National Oil Company-Energy Development Corporation and CE Philippines Ltd. and MidAmerican Energy Holdings Company, as amended by the First Amendment to Mahanagdong Agreement, dated June 22, 1994, the Letter Agreement dated July 12, 1994, the Letter Agreement dated July 29, 1994, and the Fourth Amendment to Mahanagdong Agreement, dated March 3, 1995 (incorporated by reference to Exhibit 10.100 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1993).
10.8
Credit Agreement, dated as of June 30, 1994, by and between CE Luzon Geothermal Power Company, Inc. and Export-Import Bank of the United States (incorporated by reference to Exhibit 10.102 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1993).
10.9
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 MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1993).
10.10
Overseas Private Investment Corporation Contract of Insurance, dated July 29, 1994, among Overseas Private Investment Corporation and MidAmerican Energy Holdings 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 MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1993).
10.11
MW Power Plant-Malitbog Agreement, dated September 10, 1993, between Philippine National Oil Company-Energy Development Corporation 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 MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 1993).
10.12
Amended and Restated Casecnan Project Agreement, dated June 26, 1995, between the National Irrigation Administration and CE Casecnan Water and Energy Company Inc. (incorporated by reference to Exhibit 10.1 to the CE Casecnan Water and Energy Company, Inc. Registration Statement on Form S-4 dated January 25, 1996).
10.13
Supplemental Agreement, dated as of September 29, 2003, by and between CE Casecnan Water and Energy Company, Inc. and the Philippines National Irrigation Administration (incorporated by reference to Exhibit 98.1 to the MidAmerican Energy Holdings Company Current Report on Form 8-K dated October 15, 2003).
Exhibit No.
10.14
Sixth Amendment to 180 MW Power Plant-Mahanagdong Agreement, dated August 31, 2003, by and between Philippine National Oil Company-Energy Development Corporation and CE Luzon Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.44 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
10.15
Third Amendment to 231 MW Power Plant-Malitbog Agreement, dated August 31, 2003, by and between Philippine National Oil Company-Energy Development Corporation and Visayas Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.45 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
10.16
Seventh Amendment to 125 MW Power Plant-Upper Mahiao Agreement, dated August 31, 2003, by and between Philippine National Oil Company-Energy Development Corporation and CE Cebu Geothermal Power Company, Inc. (incorporated by reference to Exhibit 10.46 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
10.17
CalEnergy Company, Inc. Voluntary Deferred Compensation Plan, effective December 1, 1997, First Amendment, dated as of August 17, 1999, and Second Amendment effective March 14, 2000 (incorporated by reference to Exhibit 10.50 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
10.18
MidAmerican Energy Holdings Company Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.51 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
10.19
MidAmerican Energy Company First Amended and Restated Supplemental Retirement Plan for Designated Officers dated as of May 10, 1999 (incorporated by reference to Exhibit 10.52 to the MidAmerican Energy Holdings Company Registration Statement No. 333-101699 dated December 6, 2002).
10.20
MidAmerican Energy Company Restated Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.6 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.21
MidAmerican Energy Holdings Company Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
10.22
MidAmerican Energy Company Combined Midwest Resources/Iowa Resources Restated Deferred Compensation Plan-Board of Directors (incorporated by reference to Exhibit 10.63 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K/A for the year ended December 31, 1999).
10.23
MidAmerican Energy Holdings Company Executive Incremental Profit Sharing Plan (incorporated by reference to Exhibit 10.2 to the MidAmerican Energy Holdings Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2003).
10.24
MidAmerican Energy Holdings Company Amended and Restated Long-Term Incentive Partnership Plan dated as of January 1, 2004 (incorporated by reference to Exhibit 10.71 to the MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2004).
10.25
Stock Purchase Agreement, dated as of May 23, 2005, by and among Scottish Power plc, PacifiCorp Holdings, Inc. and MidAmerican Energy Holdings Company (incorporated by reference to Exhibit 99.1 to MidAmerican Energy Holdings Company Current Report on Form 8-K dated May 24, 2005).
Exhibit No.
10.26
Amendment No. 1 to Stock Purchase Agreement, dated as of March 21, 2006, by and among Scottish Power plc, PacifiCorp Holdings, Inc. and PPW Holdings LLC (as successor in interest to MidAmerican Energy Holdings Company) (incorporated by reference to Exhibit 10.1 to MidAmerican Energy Holdings Company Current Report on Form 8-K dated March 21, 2006).
10.27
Summary of Key Terms of Compensation Arrangements with MidAmerican Energy Holdings Company Named Executive Officers and Directors.
14.1
MidAmerican Energy Holdings Company Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to MidAmerican Energy Holdings Company Annual Report on Form 10-K for the year ended December 31, 2003).
21.1
Subsidiaries of the Registrant.
24.1
Power of Attorney.
31.1
Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.