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Black Hills 10-K 2006 Documents found in this filing:UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 Form 10-K
BLACK HILLS CORPORATION
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
Documents Incorporated by Reference
TABLE OF CONTENTS
2 PART I
Through our Internet website, www.blackhillscorp.com, we make available free of charge our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.
Safe Harbor for Forward-Looking Information
This Annual Report on Form 10-K includes “forward-looking statements” as defined by the Securities and Exchange Commission (SEC). We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in this Form 10-K and the following:
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New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly our forward-looking statements, whether as a result of new information, future events or otherwise.
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Black Hills Corporation, a South Dakota corporation, is a diversified energy company. Our predecessor company, Black Hills Power and Light Company, was incorporated and began providing electric utility service in 1941 and began selling and marketing various forms of energy on an unregulated basis in 1956. We operate principally in the United States with two major business groups: retail electric and gas service and wholesale energy.
Retail Services Group
In 2005, our retail services group conducted business in three segments:
Electric Utility. Through Black Hills Power, Inc. (Black Hills Power), our electric utility segment engages in the generation, transmission and distribution of electricity to approximately 63,500 customers in South Dakota, Wyoming and Montana, and the sale of electric energy and capacity on a wholesale, or “off-system,” basis.
Combination Electric and Gas Utility. On January 21, 2005, we acquired Cheyenne Light, Fuel and Power Company (Cheyenne Light), our combination electric and gas utility segment, which serves approximately 38,700 electric and 32,500 natural gas customers in Cheyenne, Wyoming and vicinity.
Communications. On June 30, 2005, we sold Black Hills Fiber Systems, Inc., through which we operated our communications segment, to PrairieWave Communications, Inc. Our communication segment offered broadband telecommunications services and operated a telephone directory business.
Wholesale Energy Group
Our wholesale energy group, which operates through Black Hills Energy, Inc. (Black Hills Energy) and its subsidiaries, conducts business in four segments:
Power Generation. We engage in the production and sale of electric capacity and energy through a diversified portfolio of generating plants predominantly in the Rocky Mountain and Western regions of the United States.
Oil and Gas. We produce and sell natural gas and crude oil primarily in the Rocky Mountain region of the United States.
Coal Mining. We mine and sell coal at our Wyodak coal mine located near Gillette, Wyoming.
Energy Marketing and Transportation. We market and transport fuel products primarily in the Western and Mid-continent regions of the United States and in Western Canada.
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Our Retail Services group consists of two business segments – our regulated electric utility, Black Hills Power, and our regulated electric and gas utility, Cheyenne Light, which was acquired in late January 2005. It also consisted of our communications segment, Black Hills FiberCom and related businesses, which was sold June 30, 2005 and is reported as discontinued operations.
Electric Utility Segment
Our electric utility, Black Hills Power, is engaged in the generation, transmission and distribution of electricity. It provides us with a solid foundation of revenues, earnings and cash flow.
Distribution and Transmission. Black Hills Power’s distribution and transmission businesses serve approximately 63,500 electric customers, with an electric transmission system of 447 miles of high voltage lines and 511 miles of lower voltage lines. In addition, Black Hills Power jointly owns 47 miles of high voltage lines with Basin Electric Cooperative. Black Hills Power’s service territory covers a 9,300 square mile area of western South Dakota, northeastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 90 percent of Black Hills Power’s retail electric revenues in 2005 were generated in South Dakota.
The following are characteristics of Black Hills Power’s distribution and transmission businesses:
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Power Sales Agreements. We sell a portion of Black Hills Power’s current load under long-term contracts. Our key contracts include:
These consumers are integrated into Black Hills Power’s control area and are treated as firm native load. Black Hills Power also provides 20 megawatts of unit contingent energy and capacity to MEAN under a contract that expires in 2013.
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Regulated Power Plants and Purchased Power. Black Hills Power’s electric load is primarily served by its generating facilities in South Dakota and Wyoming, which provide 435 megawatts of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 50 percent of Black Hills Power’s capacity is coal-fired, 39 percent is oil- or gas-fired, and 11 percent is supplied under the following purchased power contracts with PacifiCorp:
Since 1995, Black Hills Power has been a net producer of energy. Black Hills Power reached its peak system load of 401 megawatts in July 2005. None of Black Hills Power’s generation is restricted by hours of operation, thereby providing it the ability to generate power to meet demand whenever necessary and economically feasible.
The following table describes Black Hills Power’s portfolio of power plants:
Ben French. Ben French is a wholly owned coal-fired plant located in Rapid City, South Dakota, with a capacity of 25 megawatts. This plant was put into service in 1960 and has since been operating as a baseload plant. The plant purchases coal from our Wyodak mine, which is delivered by truck.
Ben French Diesel Units 1-5. The Ben French Diesel Units 1-5 are wholly owned diesel-fired plants located in Rapid City, South Dakota, with an aggregate capacity of 10 megawatts. These plants were placed into service in 1965, and operate as peaking plants.
Ben French CTs 1-4. The Ben French Combustion Turbines 1-4 are wholly owned gas- and/or oil-fired units with an aggregate capacity of 100 megawatts located in Rapid City, South Dakota. These facilities were placed into service from 1977 to 1979, and operate as peaking units.
Lange CT. The Lange Combustion Turbine is a wholly owned 40 megawatt gas-fired plant located near Rapid City, South Dakota. The plant was placed into service in 2002 and provides peaking capacity and voltage support for the area.
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Neil Simpson I and II. Neil Simpson I and II are wholly owned, air-cooled, coal-fired facilities located near Gillette, Wyoming. Neil Simpson I has a capacity of 21.8 megawatts and was placed into service in 1969. Neil Simpson II has a capacity of 91 megawatts and was placed into service in 1995. These plants operate as baseload facilities, and are mine-mouth plants, receiving their coal directly from our Wyodak mine.
Neil Simpson CT. The Neil Simpson Combustion Turbine is a wholly owned gas-fired plant located near Gillette, Wyoming with a capacity of 40 megawatts. This plant was placed into service in 2000, and provides peaking capabilities.
Osage. The Osage plant is a wholly owned coal-fired plant in Osage, Wyoming with a total capacity of 34.5 megawatts. This plant, which was placed into service from 1948 to 1952, has three turbine generating units and operates as a baseload plant. The plant purchases coal from our Wyodak mine, which is delivered by truck.
Wyodak. Wyodak is a 362 megawatt mine mouth coal-fired plant owned 80 percent by PacifiCorp and 20 percent (or 72.4 net megawatts) by Black Hills Power. Our Wyodak mine furnishes all the coal fuel supply for the Wyodak plant. The plant, which is operated by PacifiCorp, was placed into service in 1978 and operates as a baseload plant.
Combination Electric and Gas Utility Segment
We acquired Cheyenne Light in January 2005, and report its operations as a new segment within the retail services group.
Electric System. Cheyenne Light’s electric system serves approximately 38,700 customers in Cheyenne, Wyoming and vicinity, and has a peak load of 163 megawatts. Power is supplied to Cheyenne Light under an all-requirements contract with PSCo, which expires at the end of 2007. For power needs after 2007, Cheyenne Light has a contract for 40 megawatts of energy and capacity from our Gillette CT, until August 2011, and 60 megawatts of energy and capacity from our Wygen I plant until the first quarter of 2013. Cheyenne Light is also in the construction phase of a coal-fired plant (Wygen II) near Gillette, Wyoming, which is expected to be in service the first quarter of 2008.
Natural Gas System. Cheyenne Light’s natural gas distribution system serves approximately 32,500 natural gas customers in Cheyenne, Wyoming and vicinity. Cheyenne Light’s annual natural gas sales and transportation from January 21, to December 31, 2005 were approximately 12.4 million Dekatherms (Dth), with sales to commercial and residential customers accounting for approximately 4.1 million Dth and transportation accounting for approximately 8.3 million Dth.
Cheyenne Light purchases natural gas from independent suppliers. The natural gas supplies are delivered to the respective delivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliers directly to certain transportation customers. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at Cheyenne Light’s city gate meter station and a small amount is received directly from wellhead sources.
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Our wholesale energy group, which operates through Black Hills Energy, Inc. and its subsidiaries, engages in the production and sale of electric capacity and energy through ownership of a diversified portfolio of generating plants, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing, storage and transportation of energy products. The wholesale energy group consists of four business segments for reporting purposes:
Power Generation Segment
Our power generation segment acquires, develops and operates unregulated power plants. We currently hold varying interests in independent power plants in Colorado, Nevada, Wyoming, California and Idaho with a total net ownership of 978 megawatts as of December 31, 2005, and minority interests in several power-related funds with a net ownership interest of 22 megawatts. In April 2005, we sold our 40 megawatt plant in Massachusetts.
How We Manage Our Portfolio. We maintain a geographically diverse portfolio of power plants in our wholesale business group, with a focus on the western region of the United States. The fuel mix of our unregulated portfolio is approximately 91 percent natural gas-fired and 9 percent coal-fired. We sell capacity and energy under a combination of mid- to long-term contracts, which helps mitigate the impact of a potential downturn in power prices in the future. We also make certain “spot” sales into the energy markets. Currently, we sell approximately 99 percent of our unregulated generating capacity under contracts having terms of greater than one year, and we sell additional power into the wholesale power markets from our generating capacity when available and when it is economic to do so. We also mitigate our financial exposure in the power generation segment by selling a majority of our unregulated capacity and energy under “tolling” agreements, or agreements under which the power purchaser is responsible for supplying fuel for the facility, thus assuming fuel price risk.
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Rocky Mountain and West Coast Facilities. As of December 31, 2005, we had approximately 978 net megawatts of name plate generating capacity in the Western Electricity Coordinating Council (WECC) states of Colorado, Nevada, Wyoming, California and Idaho, as follows:
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Fountain Valley, Arapahoe and Valmont Facilities. Our Fountain Valley, Arapahoe and Valmont plants are wholly owned gas-fired peaking facilities in the Front Range of Colorado, with a total capacity of 450 megawatts. The Fountain Valley and Valmont facilities operate in simple cycle, and the Arapahoe facility operates in combined cycle. We sell all of the output from these plants to PSCo under tolling contracts expiring in 2012.
Las Vegas Cogeneration Facilities. Our Las Vegas I facility is a 53 megawatt, combined-cycle, gas-fired plant northeast of Las Vegas, Nevada, and is a Qualifying Facility, or QF, under the Public Utility Regulatory Policies Act of 1978 (PURPA). We sell 45 megawatts of power from this plant to Nevada Power under a long-term contract that expires in 2024. Under the terms of the Nevada Power contract, we assume the fuel price risk associated with the energy generation. Prior to December 31, 2005, we had a 50 percent ownership in this plant, however under accounting principles generally accepted in the United States; we were required to consolidate 100 percent of the plant and its operations into our financial statements. On December 31, 2005, we purchased the remaining 50 percent interest in this facility that we did not already own (See Note 23 of Item 8., Financial Statements and Supplementary Data). Our Las Vegas II facility is a wholly owned, 224 megawatt, combined-cycle, gas-fired plant that became operational early in 2003. In December 2003, we executed a new long-term tolling agreement with Nevada Power for the capacity and power from this plant, which expires December 31, 2013. Regulatory approval for the new contract was obtained in March 2004 and we commenced selling to Nevada Power under the contract on April 1, 2004.
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Gillette CT. The Gillette CT, is a wholly owned simple-cycle, gas-fired combustion turbine located near Gillette, Wyoming at the same site as our Wygen I plant and Wyodak mine. The Gillette CT has a total capacity of 40 megawatts and became operational in May 2001. Prior to our ownership of Cheyenne Light, we entered into a 10-year power purchase agreement with Cheyenne Light, which expires in August 2011, for the sale of energy and capacity from this facility. In connection with PSCo’s execution of an all-requirements power purchase agreement with Cheyenne Light, the Gillette CT power purchase agreement was assigned by Cheyenne Light to PSCo for the term of the all-requirements agreement, which expires December 31, 2007. Upon expiration of PSCo’s all-requirements power purchase agreement with Cheyenne Light, the Gillette CT power purchase agreement reverts back to Cheyenne Light. During the remaining term of the temporary assignment, we assume intra-month fuel price risk under this agreement since the fuel price is fixed at the outset of each month and PSCo has the right to dispatch the facility on a day-ahead basis. We are permitted to remarket the energy that is not prescheduled by PSCo.
Wygen I Plant. The Wygen I plant is a mine-mouth, coal-fired plant with a total capacity of 90 megawatts, which commenced operations in the first quarter of 2003. We have agreements to sell 60 megawatts of unit contingent capacity and energy from this plant to Cheyenne Light with a term of 10 years, expiring in the first quarter of 2013, and 20 megawatts of unit contingent capacity and energy to the Municipal Energy Agency of Nebraska (MEAN) for a term of 10 years, expiring February 2013. As with the Gillette CT power purchase agreement, Cheyenne Light has temporarily assigned the Wygen I power purchase agreement to PSCo for the term of its all-requirements power purchase agreement, which expires December 31, 2007. We are the lessee of the Wygen I plant under a synthetic lease arrangement, but under accounting principles generally accepted in the United States, we consolidate the plant and its operating activity in our financial statements.
Ontario Cogeneration Facility. Our Ontario facility, a QF, is a 12 megawatt, “Cheng-cycle,” gas-fired power plant in Ontario, California, which we currently operate as a baseload plant. Electrical output from the plant is subject to a 25-year power purchase agreement with Southern California Edison (SCE), which expires in December 2009. The project also sells steam production to Sunkist Growers, Inc. under a five-year agreement, which terminates in November 2007. Prior to December 31, 2005, we had a 50 percent ownership in this plant, however under accounting principles generally accepted in the United States we were required to consolidate 100 percent of the plant and its operations into our financial statements. On December 31, 2005, we purchased the remaining 50 percent interest in this facility that we did not already own (See Item 8., Financial Statements and Supplementary Data).
Harbor Cogeneration Facility. Harbor Cogeneration is a 98 megawatt, combined-cycle, gas-fired plant located at the Port of Long Beach, California. Through October 2004, the facility sold capacity and energy under a summer tolling agreement with SCE. We entered into a new tolling agreement with SCE commencing April 1, 2005, under which SCE purchases all of the capacity and energy of the facility through May 31, 2008. Under a termination agreement with SCE pertaining to a long-term contract that was previously terminated, Harbor Cogeneration also receives payments pursuant to a termination payment schedule for a period ending on October 1, 2008.
Idaho Cogeneration Facilities. On December 31, 2005, we purchased a 50 percent interest in two QF facilities in Rupert and Glenns Ferry, Idaho (See Item 8., Financial Statements and Supplementary Data). Rupert and Glenns Ferry are both 11 megawatt, combined-cycle, gas-fired plants. Electrical output from the facilities is sold to Idaho Power Company under 20-year Energy Sales Agreements, which expire in late 2016. The projects also sell steam production to Idaho Fresh-Pak, Inc. under Thermal Energy Service Agreements, which also expire in late 2016. We had previously held notes receivable from the prior 50 percent owner secured by a pledge of the 50 percent interests; as such, while we did not own these interests prior to the acquisition, under accounting principles generally accepted in the United States, we accounted for, and continue to account for, 50 percent of the facilities operations in our financial statements under the equity method of accounting.
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Northeast Facilities. During 2003, we decided to exit the Eastern market and divest our assets in that region. In September 2003, we completed the sale of our ownership interests in seven hydroelectric plants in New York. These plants had a combined nameplate capacity of approximately 80 megawatts. Additionally in April 2005, we sold our remaining assets in this region with the disposition of a 40 megawatt gas-fired plant located in Pepperell, Massachusetts.
Power Funds. In addition to our ownership of the power plants described above, we hold various indirect interests in power plants through our investment in energy and energy-related funds, both domestic and international, with a total net capacity of approximately 22 megawatts. We account for our investment in the funds under the equity method of accounting and as of December 31, 2005, had a $10.8 million investment balance in the funds.
Project Development Program. Through our active project development program, we are pursuing the acquisition or development of a number of additional unregulated generation projects, ranging from the expansion of existing generating capacity, or “brownfield development,” to the acquisition or development of new generating facilities. Our primary geographic focus has been, and is likely to remain, in the North American Electric Reliability Council region known as the WECC. Among the factors we consider important in evaluating new or expanded generation opportunities are the following:
Our goal is to sell a substantial portion of the independent power generation portfolio under long-term contracts, while reserving the balance for merchant or spot sales. Our strategy is to seek long-term contracts with either utilities serving native customer loads under state utility commission-approved contracts, or other investment-grade counterparties. We cannot assure you that we will be successful in completing any or all of the projects currently under consideration.
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Oil and Gas Segment
Our oil and gas segment, which operates through our Black Hills Exploration and Production, Inc. subsidiary, is involved in the acquisition, exploration, development and production of natural gas and crude oil. As of December 31, 2005, we hold operated interests in oil and gas properties totaling approximately 527 wells located in the San Juan Basin of New Mexico and Colorado, the Powder River and Big Horn Basins of Wyoming, the Piceance Basin of Colorado, and the Denver Basin of Colorado and Nebraska. Unique to our San Juan Basin operations in New Mexico, we also own and operate a natural gas gathering pipeline along with associated gas compression and treating facilities. We hold non-operated interests in oil and natural gas properties totaling approximately 495 wells located in California, Colorado, Louisiana, Montana, North Dakota, Oklahoma, Texas and Wyoming.
We also own a 44.7 percent interest in the Newcastle gas processing plant located in Weston County, Wyoming adjacent to certain of our producing properties in that area. The plant is operated by Western Gas Resources.
The majority of our reserves are located in select oil and natural gas producing basins in the Rocky Mountain region. Approximately 57 percent of our reserves are located in the San Juan Basin of northwestern New Mexico, primarily in the East Blanco Field of Rio Arriba County and 26 percent are located in the Powder River Basin of Wyoming, primarily in the Finn-Shurley Field area of Weston and Niobrara counties. An expanding area of operated interests is in the Plateau and DeBeque Fields of the Piceance Basin of Colorado. In December 2005, the Company completed the acquisition of certain Piceance Basin gas assets from Red Oak Capital Management, LLC, Plateau Creek Partners, LP and other working interest owners in the Plateau Field, Mesa County, Colorado. In the transaction, the Company acquired approximately 13,000 net acres of oil and gas leasehold, and interests in a number of producing and shut-in wells. The acreage is mostly undeveloped. As of December 31, 2005, natural gas and oil comprise 76 percent and 24 percent of our total proved reserves, respectively. At December 31, 2005, we had total reserves of approximately 169.6 Bcfe.
On March 6, 2006, we entered into a definitive agreement to acquire certain oil and gas assets of Koch Exploration Company, LLC, including approximately 40.0 billion cubic feet of proved reserves, which are almost entirely natural gas, and associated midstream and gathering assets. The associated acreage position is in the Piceance Basin in Colorado and is comprised of leases covering more than 31,000 gross and 18,000 net acres, of which more than 48 percent of the lands are presently undeveloped. The acquisition includes 63 wells, of which 58 are operated by Koch Exploration. The acquisition is subject to further due diligence and is expected to close in the first quarter of 2006.
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Summary Oil and Gas Reserve Data
The following table sets forth summary information concerning our estimated proved oil and gas reserves and the 10 percent discounted present value of estimated future net revenues as of December 31, 2005, based on a report prepared by Ralph E. Davis Associates, Inc., an independent consulting and engineering firm. Reserves were determined using year-end product prices, held constant for the life of the properties. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results.
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Drilling Activity
The following table reflects the wells completed through our drilling activities for the year ended December 31, 2005. In 2005, we participated in drilling 135 gross (70.87 net) development and exploratory wells, with a success rate of approximately 93 percent. Gross wells represent the total wells we participated in, regardless of ownership interest, with net wells representing our fractional ownership interests within those wells.
As of December 31, 2005, we were participating in the drilling of 27 gross (13.43 net) wells, which had been commenced but not yet completed.
Recompletion Activity
The following table reflects our recompletion activities for the year ended December 31, 2005.
Productive Wells
The following table summarizes our gross and net productive wells at December 31, 2005.
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Acreage
The following table summarizes our undeveloped, developed and total acreage by state as of December 31, 2005 (in thousands).
For more information on our oil and gas operations, see Note 25 to our Notes to Consolidated Financial Statements.
Coal Mining Segment
Our coal mining segment, which operates through our Wyodak Resources Development Corp. subsidiary, mines and processes low-sulfur, sub-bituminous coal at our Wyodak coal mine near Gillette, Wyoming. The Wyodak mine, which we acquired in 1956 from Homestake Gold Mining Company, is located in the Powder River Basin, one of the largest coal reserves in the United States. We produced approximately 4.7 million tons of coal in 2005. Mining rights to the coal are based on four federal leases and one state lease. We pay royalties of 12.5 percent and 9.0 percent, respectively, of the selling price on all federal and state coal. As of December 31, 2005, we had coal reserves of approximately 290 million tons, based on an updated internal reserve study completed in 2005. The reserve life is equal to approximately 60 years at current production levels.
Substantially all of our coal production is currently sold under long-term contracts to:
We also expect to increase our coal production to supply:
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Our coal mining segment sells coal to Black Hills Power for all of its requirements under an agreement that limits earnings from all coal sales to Black Hills Power, including the 20 percent share on the Wyodak plant and all sales to Black Hills Powers’ other plants, to a specified return on our coal mine’s cost-depreciated investment base. The return is 4 percent (400 basis points) above A-rated utility bonds, to be applied to our coal mining investment base as determined each year. Black Hills Power made a commitment to the South Dakota Public Utilities Commission (SDPUC), the Wyoming Public Service Commission (WPSC) and the City of Gillette that coal would be furnished and priced as provided by that agreement for the life of Black Hills Power’s Neil Simpson II plant, which Black Hills Power placed into service in 1995.
The price for unprocessed coal sold to PacifiCorp for its 80 percent interest in the Wyodak plant is determined by a coal supply agreement which terminates in 2022.
Energy Marketing and Transportation Segment
We market natural gas and crude oil in specific regions of the United States and Canada. We offer physical and financial wholesale energy marketing and price risk management products and services to a variety of customers. The customers of our energy marketing and transportation segment include:
Our average daily marketing physical volumes for the year ended December 31, 2005 were approximately 1.4 million MMBtu, or million British thermal units of gas, and 37,600 barrels of oil.
The following table identifies the location of our fuel marketing operations and sales offices:
Enserco Energy Inc. Our energy marketing operations focus primarily on producer services, end use origination and wholesale marketing services. Our producer marketing services include purchases of wellhead gas, risk transfer and hedging products for gas producers in the Rocky Mountain region. Our gas marketing efforts are concentrated in the Rocky Mountain, Western and Mid-continent regions of the United States and in Canada. We hold, under contract, natural gas storage capacity and both long- and short-term transportation capacity on several major pipelines in the western and mid-continent regions of the United States and in Western Canada.
Black Hills Energy Resources, Inc. On January 5, 2006, we entered into an agreement with Sunoco Logistics Partners, L.P. to sell the operating assets of our crude oil marketing and oil pipeline systems. The transaction was completed on March 1, 2006. The sale included crude oil marketing and transportation operations headquartered in Houston, Texas, the 200-mile Millennium Pipeline System, the 190-mile Kilgore Pipeline System and related facilities.
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The independent power, fuel production and energy marketing industries are characterized by numerous strong and capable competitors, some of which may have more extensive operating experience, larger staffs or greater financial resources than us.
The Federal Energy Regulatory Commission, or FERC, has implemented and continues to favor regulatory initiatives to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity and to enhance competition in wholesale electricity markets. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. The pace of restructuring slowed significantly following public and governmental reactions to issues associated with deregulation efforts in California and the collapse of its wholesale electric energy market in 2001. In some instances, states are reevaluating their steps taken towards deregulation. South Dakota and Wyoming have not implemented retail competition.
In addition, Congress passed the Energy Policy Act of 2005. The Energy Policy Act of 2005 repealed the Public Utility Holding Company Act of 1935 and transferred oversight of holding companies to FERC effective February 8, 2006. On December 8, 2005 FERC issued final rules implementing the enactment of the Public Utility Holding Company Act of 2005, which are effective as of February 8, 2006. We cannot predict the long-term effect of such regulation or how FERC will interpret the new rules with any degree of certainty. As a result of these regulatory changes, significant additional competitors could become active in the utility, generation and power marketing segments of our industry.
Our business operations require effective management of price, counterparty performance and operational risks. Price risk arises from the volatility of energy prices. Counterparty performance risk is the risk that a counterparty will fail to satisfy its contractual obligations to us, and includes credit risk. Operational risk is the risk that we will be unable to perform on our contractual obligations to our counterparties. We have implemented controls to mitigate each of these risks.
Our energy marketing operations are conducted in accordance with guidelines established through separate risk management policies and procedures for each marketing company and through our credit policy and procedures. These policies and procedures specify various maximum risk exposure levels within which each respective marketing company must operate. These policies are established and approved by our executive risk committee and reviewed by our board of directors. The policies are reviewed on a regular basis and monitored as described below.
We have an active risk management committee, which oversees our marketing companies, and a credit committee, which oversees credit for the entire corporate organization. The risk management committee oversees the implementation of risk management procedures and the monitoring of our compliance with established policies. The credit committee monitors credit exposure levels and reviews compliance with established credit policies.
We further limit the exposure of our parent holding company, Black Hills Corporation, to energy marketing risks by maintaining separate credit facilities within each of our energy marketing companies. These credit facilities have security interests solely against the assets of the respective marketing company. In addition, we limit the number and amount of any parent guarantees for the marketing companies.
A potential risk related to power sales is the price risk arising from the sale of wholesale power that exceeds our generating capacity. Short positions can arise from unplanned plant outages or from unanticipated load demands. To manage such risks, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities exceed our anticipated load requirements plus a required reserve margin.
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We are subject to a broad range of federal, state and local energy and environmental laws and regulations applicable to the development, ownership and operation of our projects, and our utility operations are subject to federal and state rate regulation. These laws and regulations generally require that a wide variety of permits and other approvals be obtained before construction or operation of a project commences and that, after completion, the facility operate in compliance with such requirements. Our public utilities operate subject to tariffs and rate schedules that must be filed with, and approved by, state and federal regulatory commissions. We strive to comply with the terms of all such laws, regulations, permits, licenses, rate schedules, and tariffs and believe that all of our operations are in material compliance with all such applicable requirements.
Energy Regulation
Energy Policy Act of 2005. The Energy Policy Act of 2005 (EPA 2005) was signed into law on August 8, 2005. EPA 2005 repealed the Public Utility Holding Company Act of 1935 effective February 8, 2006 and transferred oversight of public utility holding companies to FERC. The rules under EPA 2005 require us to register with FERC as a public utility holding company and impose record keeping requirements and provide for oversight of affiliate transactions and service company allocations. EPA 2005 amended portions of the Federal Power Act and also amended portions of the PURPA relating to QFs including the elimination of ownership restrictions and a prospective repeal of the mandatory purchase and sale requirements for a QF if FERC finds that the QF has nondiscriminatory access to other markets.
Public Utility Holding Company Act of 1935. On December 28, 2004, we became a registered holding company under the Public Utility Holding Company Act of 1935. As a registered holding company, we were subject to regulatory oversight by the SEC. The rules and regulations imposed a number of restrictions on the operations of registered holding company systems. These restrictions included, subject to certain exceptions, a requirement that the SEC approve securities issuances, payments of dividends out of capital or unearned surplus, sales and acquisitions of utility assets or of securities of utility companies, and acquisitions of other businesses. In connection with our registration, we formed a service company, Black Hills Service Company, L.L.C., to provide common services to affiliates such as accounting, administrative, information systems, engineering, financial, legal, maintenance and other services. With the passage of the Energy Policy Act of 2005, PUHCA was repealed and the oversight of public utility holding companies was transferred to FERC effective February 8, 2006.
Federal Power Act. The Federal Power Act gives FERC exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction are required to file tariffs and rate schedules with FERC prior to commencement of wholesale sales or interstate transmission of electricity. Public utilities are also subject to accounting, record-keeping and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their unregulated affiliates.
The Energy Policy Act of 1992. The passage of the Energy Policy Act of 1992 further encouraged independent power production by providing certain exemptions from regulation for exempt wholesale generators, or EWGs. An EWG is an entity that is directly or indirectly, and exclusively, in the business of owning or operating, or both owning and operating, eligible facilities and selling electric energy at wholesale. An EWG is subject to FERC regulation, including rate regulation. All of our EWGs have been granted market-based rate authority, which allows FERC to waive certain accounting, record-keeping and reporting requirements imposed on public utilities with cost-based rates. However, FERC customarily reserves the right to suspend, upon complaint, market-based rate authority on a prospective basis if it is subsequently determined that any of our EWGs exercised market power. If FERC were to suspend market-based rate authority for any of our EWGs, those EWGs most likely would be required to file, and obtain FERC acceptance of, cost-based power sales rate schedules. Also, the loss of market-based rate authority would subject the EWGs to the accounting, record keeping and reporting requirements that are imposed on public utilities with cost-based rate schedules.
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In addition, if a “material change” in facts occurs that might affect any of our subsidiaries’ eligibility for EWG status, within 60 days of the material change, the relevant EWG must (1) file a written explanation of why the material change does not affect its EWG status, (2) file a new application for EWG status, or (3) notify FERC that it no longer wishes to maintain EWG status.
PURPA. The enactment of PURPA in 1978 provided incentives for the development of qualifying cogeneration facilities and small power production facilities that utilized certain alternative or renewable fuels, referred to as qualifying facilities (QFs). Prior to the enactment of EPA 2005, FERC’s regulations under PURPA required that (1) electric utilities purchase electricity generated by QFs at a price based on the purchasing utility’s full avoided cost of producing power, (2) the electric utilities must sell back-up, interruptible, maintenance and supplemental power to the QF on a non-discriminatory basis, and (3) the electric utilities must interconnect with any QF in its service territory, and, if required, transmit power if they do not purchase it. We operate our Las Vegas I and Ontario facilities as QFs and the enactment of EPA 2005 does not affect the existing contracts for these facilities.
State Energy Regulation. In areas outside of wholesale rate regulation (such as financial or organizational regulation), some state utility laws may give their public utility commissions broad jurisdiction over steam sales or EWGs that sell power in their service territories. The actual scope of the jurisdiction over steam or independent power projects depends on state law and varies significantly from state to state.
Retail Rate Regulation
Black Hills Power. The rate freeze granted by the SDPUC, which had been in effect for Black Hills Power since 1995, expired on January 1, 2005. During this ten-year term, Black Hills Power was prohibited, subject to certain limited exceptions, from filing for any increase in its rates or invoking any fuel and purchased power adjustment tariff which would take effect during the freeze period. While the rate freeze has expired, Black Hills Power cannot raise rates without initiating a proceeding before the SDPUC and the WPSC and receiving approval from these commissions. As such, Black Hills Power’s rates in place during the freeze period remain in effect.
Unless and until Black Hills Power files for and receives a rate increase, it is undertaking the risks of:
Cheyenne Light. Our Cheyenne Light electric and natural gas distribution utility, which we acquired in January 2005, is subject to the jurisdiction of the WPSC with respect to its facilities, rates, accounts, services and issuance of securities. Cheyenne Light is subject to the jurisdiction of FERC with respect to accounting practices and the transmission of electricity in interstate commerce. All electric demand, purchased power and transmission costs are recoverable through an energy cost adjustment clause subject to WPSC jurisdiction. All purchased gas and transportation costs are recoverable through a gas cost adjustment clause, also subject to WPSC jurisdiction. Differences in costs incurred from costs recovered in rates, including interest, are deferred and recovered through prospective adjustments to rates. Rate changes for cost recovery require WPSC approval before going into effect. In October 2005, the Wyoming Public Service Commission approved our application to increase Cheyenne Light’s base rates for gas and electric service effective on January 1, 2006.
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Environmental Regulation
The construction and operation of power projects, coal mines, oil and gas properties, gas transportation and crude oil handling facilities are subject to extensive environmental protection and land use regulation in the United States. These laws and regulations often require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies. If such laws and regulations are changed and our facilities are not “grandfathered,” extensive modifications to project technologies and facilities could be required.
General. Based on current trends, we expect that environmental and land use regulation will continue to be stringent. Accordingly, we actively review proposed construction projects that could subject us to stringent pollution controls imposed on “major modifications,” as defined under the Clean Air Act, and changes in “discharge characteristics,” as defined under the Clean Water Act. The goal of these actions is to achieve compliance with applicable regulations, administrative consent orders and variances from applicable air-quality related regulations.
Air Quality. Our Neil Simpson II, Neil Simpson CT, Gillette CT, Wygen I, Arapahoe, Valmont, Fountain Valley, Las Vegas II, Lange CT and Wyodak plants are all subject to Title IV of the Clean Air Act, which requires certain fossil-fuel-fired combustion devices to hold sulfur dioxide (SO2) “allowances” for each ton of sulfur dioxide emitted. We currently hold sufficient allowances credited to us as a result of sulfur removal equipment previously installed at the Wyodak plant to apply to the operation of all units subject to Title IV through 2035 without requiring the purchase of any additional allowances. With respect to any future plants, we plan to comply with the need for holding the appropriate number of allowances by reducing sulfur dioxide emissions through the use of low sulfur fuels, installation of “back end” control technology, use of banked allowances left over from our unused portion of Wyodak allowances and if necessary, the purchase of allowances on the open market. We expect to integrate the costs of obtaining the required number of allowances needed for future projects into our overall financial analysis of such projects.
In July 1999, the United States Environmental Protection Agency (EPA) finalized rules designed to protect and improve visibility impairment resulting from air emissions. Among other things, the regulations required states to identify sources of emissions (including certain coal-fired generating units built between 1962 and 1977) by 2004 that would be subject to “Best Available Retrofit Technology,” known as BART. These sources would be required to implement BART within five years after the EPA approves state plans adopted to combat visibility impairment. Subsequent litigation has removed EPA’s requirement mandating that states adopt and impose BART requirements; however, it remains an option for states to use in addressing visibility impairment. We believe our only existing plant which may be required to comply with the BART requirements is our Neil Simpson I plant in Wyoming. Late in 2003, the State of Wyoming elected to manage visibility impairment through 40 CFR Part 51.309 (Grand Canyon Visibility Transport States), or the 309 program. Under this program, there is a Backstop SO2 Emission Trading Program that eliminates the need for BART in the states that opt into the 309 program. Therefore, Neil Simpson I will not have to implement BART controls, but all of our plants will fall under the Backstop SO2 Emission Trading Program if it is triggered to be implemented. The trading program would be triggered if annual SO2 emission reductions do not remain in a declining trend. After discussions with Wyoming regulatory staff, we believe this program will not have a material adverse effect on our financial position or results of operations. We are aware of a February 18, 2005 decision by the United States Court of Appeals for the District of Columbia Circuit that grants a petition for review of this rule. Until this issue is ultimately resolved, we are unable to evaluate its impact. We are aware that other states in which we have power plants are required to submit their visibility impairment plans to EPA between 2004 and 2008 and that compliance is due within five years of EPA approval. We believe that any capital expenditures associated with future compliance requirements would not have a material adverse effect on our financial position or results of operations.
Title V of the Clean Air Act imposes federal requirements, which dictate that all of our fossil fuel-fired generation facilities must obtain operating permits. All of our existing facilities subject to this requirement have submitted Title V permit applications and either have received or are in the process of receiving permits.
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On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities for alleged violations of the Clean Air Act’s “new source review” (NSR) requirements related to modifications of air emissions sources at electric generating stations located in the southern and midwestern regions of the United States. Several states joined these lawsuits. In addition, the EPA has also issued administrative notices of violation alleging similar violations at additional power plants owned by some of the same utilities named as defendants in the Department of Justice lawsuit. The EPA has also issued requests for information pursuant to the Clean Air Act to numerous other electric utilities seeking to determine whether those utilities also engaged in activities that may have been in violation of the Clean Air Act’s NSR requirements. In May 2003, the EPA notified PacifiCorp that it is investigating similar activities at their Wyodak Plant, in which we hold a 20 percent ownership interest. We are receiving copies of all information provided to EPA. At this time no legal proceedings have commenced. No such NSR proceedings have been initiated or requests for information issued with respect to any of our other facilities, but we cannot assure you that we will not be subject to similar proceedings in the future.
In March, 2005 the EPA issued mercury emission requirements for fossil fuel fired steam electric power plants. Wygen II and subsequent power plants will be subject to the emission standards as well as the monitoring, cap and trade requirements. Wygen I and Neil Simpson II will be subject to the monitoring, cap and trade requirements. Testing at Wygen I is planned for early 2006, to help gain understanding and knowledge of the mercury control and monitoring technology. Also there are several pending legal actions involving other parties, challenging various aspects of the mercury rule. Until these efforts are finalized, we are not able to fully evaluate the impact of mercury regulations on the operation of our facilities.
Since the adoption of the United Nations Framework on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas emissions, in particular carbon dioxide. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations, where the basis of a climate change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United States would be required, between 2008 and 2012 to reduce its greenhouse gas emissions by 7 percent from 1990 levels. The treaty has never been ratified by the United States, although discussions continue regarding climate change issues. Although legislative developments on the state level related to controlling greenhouse gas emissions have occurred, we are not aware of any similar developments in the states in which we operate. If we should become subject to limitations on emissions of carbon dioxide from our power plants, these requirements could have a significant impact on our operations.
Clean Water Act. Our existing facilities are also subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges and protection of surface waters from oil pollution. Generally, such regulations are promulgated under authority of the Clean Water Act and govern overall water/wastewater discharges through National Pollutant Discharge Elimination System, or NPDES, permits. Under current provisions of the Clean Water Act, existing NPDES permits must be renewed every five years, at which time permit limits are extensively reviewed and can be modified to account for changes in regulations or program initiatives. In addition, the permits have re-opener clauses which allow the permitting authority (which may be the United States or an authorized state) to attempt to modify a permit to conform to changes in applicable laws and regulations. Some of our existing facilities have been operating under NPDES permits for many years and have gone through one or more NPDES permit renewal cycles. All of our facilities required to have NPDES permits have those permits in place and are in compliance with discharge limitations. There are no proposed regulations that we are aware of that will have a significant impact on our operations. The stream that receives discharges from the Ben French Plant is expected to be re-classified within the next few years. If that occurs, we expect that discharge limits will become more restrictive. At this time we are unable to assess those impacts until more information is known. Additionally, the EPA regulates surface water oil pollution prevention through its oil pollution prevention regulations. All facilities regulated under this program have their required plans in place.
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Solid Waste Disposal. We dispose of all solid wastes collected as a result of burning coal at our power plants in approved solid waste disposal sites. Each disposal site has been permitted by the state of its location in compliance with law. Ash and wastes from flue gas and sulfur removal from the Wyodak, Wygen I, Neil Simpson I, Ben French and Neil Simpson II plants are deposited in mined areas at our Wyodak Coal Mine. These disposal areas are located below some shallow water aquifers in the mine. The State of Wyoming is currently re-evaluating this practice and may, in the future, limit ash disposal to mined areas that are above future groundwater aquifers. This will result in increased costs, although those costs cannot be quantified until the exact requirements are known. None of the solid wastes from the burning of coal are classified as hazardous material, but the wastes do contain minute traces of metals that could be perceived as polluting if such metals leached into underground water. Investigations have concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we cannot assure you that no pollution will occur over time. In this event, we could experience material costs to mitigate any resulting damages. Agreements in place require PacifiCorp to be responsible for any such costs that would be related to the solid waste from its 80 percent interest in the Wyodak plant.
Additional unexpected material costs could also result in the future if any regulator determines that solid waste from the burning of coal contains some hazardous material that requires special treatment, including previously disposed of solid waste. In that event, the government regulator could consequently hold those entities that disposed of such waste responsible for such treatment.
Pipeline Operations. The operations of pipelines and other facilities for gathering, transporting, processing or storing natural gas and crude oil is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with federal, state and local laws that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. Costs of constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws, regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures.
Mine Reclamation. Under federal and state laws and regulations, we are required to submit to the regulation by, and receive approval from, the Wyoming Department of Environmental Quality (DEQ) for a mining and reclamation plan which provides for orderly mining, reclamation and restoration of our entire Wyodak Coal Mine in conformity with state laws and regulations. We have an approved mining permit and are otherwise in compliance with other permitting programs administered by various regulatory agencies.
Based on extensive reclamation studies, we have accrued approximately $16.0 million on our accompanying Consolidated Balance Sheets for these reclamation costs. No assurance can be given that additional requirements in the future will not be imposed that would cause an unexpected material increase in reclamation costs.
One situation that could result in substantial unexpected increases in costs relating to our reclamation permit concerns three depressions—the “South” depression, the “Peerless” depression and the “Clovis” depression—that have or will result from our mining activities at the Wyodak Mine. Because of the thick coal seam and relatively shallow overburden, the current restoration plan would leave these depressions, which have limited reclamation potential, with interior drainage only. Although the DEQ has accepted the current plan to limit reclamation of these depressions, it has reserved the right to review and evaluate future reclamation plans or to reevaluate the existing reclamation plan. If, as a result of our mining activities, surplus overburden becomes available, the DEQ may require us to conduct additional reclamation of the depressions, particularly if the DEQ finds that the current limited reclamation is resulting in exceedances in the DEQ’s water quality standards.
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PCBs. Under the federal Toxic Substances Control Act, the EPA has issued regulations that control the use and disposal of polychlorinated biphenyls, or PCBs. PCBs were widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the Toxic Substances Control Act prohibited any further manufacture of PCB equipment. We remove and dispose of PCB-contaminated equipment in compliance with law as it is discovered.
Release of PCB-contaminated fluids, especially any involving a fire or a release into a waterway, could result in substantial cleanup costs. Several years ago, we began a testing program of potential PCB-contaminated transformers, and in 1997 completed testing of all transformers and capacitors which are not located in our electric substations. We have not completed the testing of sealed potential transformers and bushings located in our electric substations as the testing of this equipment requires their destruction. Release of PCB-contaminated fluid, if present, from our equipment is unlikely and the volume of fluid in such equipment is generally less than one gallon. Moreover, any release of this fluid would be confined to our substation site. Cheyenne Light, acquired in early 2005, has PCB test data provided by the previous owner, however we are implementing a program to retest and confirm results for all potentially PCB containing electrical equipment, except those requiring destruction of the device.
Regulation of Natural Gas and Crude Oil Exploration and Production
Our oil and gas exploration and production operations are subject to various types of regulation at the federal, state, tribal and local levels. They include:
Our operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, certain state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill. In addition, various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants and the protection of public health, natural resources, wildlife and environment affect our exploration, development and production operations and our related costs.
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In addition to the other properties described herein, we own an eight-story office building in Rapid City, South Dakota with approximately 47,000 square feet. Also in Rapid City, we own one additional office building consisting of approximately 19,900 square feet and a warehouse building and shop with approximately 25,200 square feet. In Cheyenne, Wyoming, we own a business office with approximately 13,356 square feet, and a service center and garage with an aggregate of approximately 28,271 square feet. We lease an aggregate of 36,182 square feet of office space in Golden, Colorado.
At February 28, 2006, we had 803 full-time employees. We have experienced no labor stoppages or significant labor disputes at our facilities. The following table sets forth the number of employees by business:
The following specific risk factors and other risk factors that we discuss in our periodic reports filed from time to time with the SEC should be considered for a better understanding of our Company. These factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.
We must rely on cash distributions from our subsidiaries to make and maintain dividends and debt payments. There may be changes in the regulatory environment that restrict future dividends from our subsidiaries.
We are a holding company and thus our investments in our subsidiaries are our primary assets. Consequently, our operating cash flow and our ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any contractual or regulatory restrictions that may be applicable to it, which may include requirements to maintain minimum levels of cash, working capital or debt service funds.
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Our utility operations are regulated by utility commissions in the States of South Dakota, Wyoming and Montana. These commissions generally possess broad powers to ensure that the needs of the utility customers are being met and that we maintain a reasonable capital structure. As a result of the energy crisis in California and the financial troubles at a number of energy companies, some state utility commissions have imposed restrictions on the ability of the utilities they regulate to pay dividends or make advances to their parent holding companies. If the utility commissions in South Dakota or Wyoming choose to adopt similar restrictions, our utilities’ ability to pay dividends or advance funds to us would be limited, which could materially and adversely affect our ability to meet our financial obligations.
We cannot assure you that our results from any acquisition will conform to our expectations. There may be additional risks associated with the operation of any new acquisition.
Successful acquisitions require an assessment of a number of factors, many of which are beyond our control and are inherently uncertain. Factors which may cause our actual results to differ materially from our expected results include:
Our agreements with counterparties that have experienced downgrades in their credit ratings expose us to the risk of counterparty default, which could adversely affect our cash flow and profitability.
We are exposed to credit risks in our power generation, distribution and energy marketing operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. In the past several years, a substantial number of energy companies have experienced downgrades in their credit ratings, some of which serve as our counterparties from time to time. In addition, we have project level financing arrangements in place that provide for the potential acceleration of payment obligations in the event of nonperformance by a counterparty under related power purchase agreements. If these or other counterparties fail to perform their obligations under their respective power purchase agreements, our financial condition and results of operations may be adversely affected. We may not be able to enter into replacement power purchase agreements on terms as favorable as our existing agreements, or at all. If we were unable to enter into replacement power purchase agreements, we would sell the plant’s power at market prices.
Our credit ratings could be lowered below investment grade in the future. If this were to occur, our access to capital and our cost of capital and other costs would be negatively affected.
Our issuer credit rating is Baa3 by Moody’s Investor Services, Inc., or Moody’s, and BBB- by Standard & Poor’s Rating Service. Any reduction in our ratings by Moody’s or Standard & Poor’s would reduce our credit rating with that agency to non-investment grade status, and such reduction could adversely affect our ability to refinance or repay our existing debt and to complete new financings on acceptable terms or at all.
In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations, including borrowings made under our revolving credit facility, our $128.3 million Wygen I plant project financing, and our $26.2 million General Electric Capital Corp. secured financings.
A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under existing or new transactions.
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Geopolitical tensions may impair our ability to raise capital and limit our growth.
Continuing conflict in Iraq and tensions between the United States and other governments could disrupt capital markets and make it more costly or temporarily impossible for us to raise capital, thus hampering the implementation of our stated strategy. In the past, geopolitical events, including the uncertainty associated with the Gulf War in 1991 and the terrorist attacks of September 11, 2001, have been associated with general economic slowdowns. Geopolitical tensions or other factors could retard economic growth and reduce demand for the power and fuel products that we produce or market, which could adversely affect our earnings.
Our utilities may not raise their retail rates without prior approval of the South Dakota Public Utilities Commission or the Wyoming Public Services Commission. If either utility seeks rate relief, it could experience delays in obtaining approvals and could have rate recovery disallowed in rate proceedings.
Our rate freeze agreement with the SDPUC for our Black Hills Power electric utility expired on January 1, 2005. Until such time as we petition the SDPUC or the WPSC for rate relief, or either commission requires that we do so, neither Black Hills Power nor Cheyenne Light may increase its retail rates. Additionally, Black Hills Power may not invoke any fuel and purchased power adjustment tariff that would take effect prior to the completion of a rate proceeding, absent extraordinary circumstances. As part of the process for obtaining approval to acquire Cheyenne Light, we agreed with the WPSC that Cheyenne Light would not raise retail rates for its customers prior to January 1, 2006. Because our utilities are generally unable to increase their base rates without prior approval from the SDPUC and the WPSC, our returns could be threatened by plant outages, machinery failure, increases in purchased power costs over which our utilities have no control, acts of nature, acts of terrorism or other unexpected events that could cause operating costs to increase and operating margins to decline. Moreover, in the event of unexpected plant outages or machinery failures, Black Hills Power may be required to purchase replacement power in wholesale power markets at prices that exceed the rates it is permitted to charge its retail customers. Finally, our utilities’ costs would be subject to the review of the SDPUC or the WPSC, and the commissions could find certain costs not to be recoverable, thus negatively affecting our revenues.
Because prices for our products and services and other operating costs for our business are volatile, our revenues and expenses may fluctuate.
A substantial portion of our net income in recent years has been attributable to sales of wholesale electricity and natural gas into a robust market. The prices of electricity in the wholesale power markets have stabilized at lower levels after the price volatility experienced in the second half of 2000 and the first half of 2001. Power prices are influenced by many factors outside our control, including:
Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable.
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The success of our oil and gas operations will depend somewhat upon the prevailing market prices of oil and natural gas. Historically, oil and natural gas prices and markets have also been volatile, and they are likely to continue to be volatile in the future. A decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. A decline in fuel price volatility could also affect our revenues and returns from energy marketing, which historically tend to increase when markets are volatile.
Construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve significant risks which could lead to lost revenues or increased expenses.
The construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve many risks, including:
The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damage payments.
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Our power project development, expansion and acquisition activities may not be successful, which would impair our ability to execute our growth strategy.
The growth of our independent power business through development, expansion and acquisition activities is important to our future growth. We may not be able to continue to develop attractive opportunities or to complete acquisitions or development projects we undertake. Factors that could cause our activities to be unsuccessful include:
Estimates of the quantity and value of our proved oil and gas reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves.
There are many uncertainties inherent in estimating quantities of proved reserves and their values. The process of estimating oil and natural gas reserves requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and gas reserves and prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and these variances may be significant. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from our estimates. In addition, results of drilling, testing and production and changes in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.
Estimates of the quality and quantity of our coal reserves may change materially due to numerous uncertainties inherent in three dimensional structural modeling.
There are many uncertainties inherent in estimating quantities of coal reserves. The process of coal volume estimation requires interpretations of drill hole log data and subsequent computer modeling of the intersected deposit. Any significant inaccuracies in these interpretations or modeling could materially affect the quantity and quality of our reserves. The accuracy of reserve estimates is a function of engineering and geological interpretations and judgment of known data, assumptions used regarding structural limits and mining extents, conditions encountered during actual reserve recovery, and undetected deposit anomalies. Variance from the assumptions used and drill hole modeling density could result in additions or deletions from our volume estimates. In addition, future environmental, economic or geologic changes may occur or become known that can result in reserve revisions either upward or downward from prior reserve estimates.
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Our business is subject to substantial governmental regulation and permitting requirements as well as on-site environmental liabilities we assumed when we acquired some of our facilities. We may be adversely affected by any future inability to comply with existing or future regulations or requirements or the potentially high cost of complying with such requirements.
Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant additional costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business.
In acquiring some of our facilities, we assumed on-site liabilities associated with the environmental condition of those facilities, regardless of when such liabilities arose and whether known or unknown, and in some cases agreed to indemnify the former owners of those facilities for on-site environmental liabilities. We strive at all times to be in compliance with all applicable environmental laws and regulations. However, steps to bring our facilities into compliance, if necessary, could be expensive, and thus could adversely affect our results of operation and financial condition. Furthermore, with the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate, we expect our environmental expenditures to be substantial in the future.
Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.
The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:
FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could negatively affect our ability to expand our asset base.
In addition, the independent system operators who oversee many of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of those generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.
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None.
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” subcaption within Item 8, Note 20, “Commitments and Contingencies”, of our Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
No matter was submitted to a vote of security holders during the fourth quarter of 2005.
David R. Emery, age 43, was elected Chairman in April 2005 and President and Chief Executive Officer and a member of the Board of Directors in January 2004. Prior to that, he was our President and Chief Operating Officer – Retail Business Segment from April 2003 to January 2004 and Vice President-Fuel Resources from January 1997 to April 2003. Mr. Emery has 16 years of experience with us.
Thomas M. Ohlmacher, age 54, has been the President and Chief Operating Officer of our Wholesale Energy Group since November 2001. He served as Senior Vice President-Power Supply and Power Marketing from January 2001 to November 2001 and Vice President - Power Supply from 1994 to 2001. Prior to that, he held several positions with our company since 1974.
Linden R. Evans, age 43, was appointed President and Chief Operating Officer - Retail Business Segment in October 2004. Mr. Evans had been serving as the Vice President and General Manager of our former communication subsidiary, since December 2003 and served as our Associate Counsel from May 2001 to December 2003. Prior to joining Black Hills, Mr. Evans was an attorney and member with the Rapid City, South Dakota law firm of Truhe, Beardsley, Jensen, Helmers and VonWald from February 1997 to May 2001.
Mark T. Thies, age 42, has been our Executive Vice President and Chief Financial Officer since March 2000. From May 1997 to March 2000, he was our Controller. Mr. Thies has 8 years of experience with us.
Steven J. Helmers, age 49, has been our Senior Vice President, General Counsel since January 2004. He served as our Senior Vice President, General Counsel and Corporate Secretary from January 2001 to January 2004. Prior to joining us, Mr. Helmers was an attorney and a shareholder with the Rapid City, South Dakota law firm of Truhe, Beardsley, Jensen, Helmers & VonWald, from 1997 to January 2001.
Russell L. Cohen, age 45, has been Senior Vice President and Chief Risk Officer since May 2002. Prior to joining Black Hills, Mr. Cohen was General Partner and Chief Financial Officer at Regenesis Group, LLC from December 2000 to April 2002.
Maurice T. Klefeker, age 49, was elected Senior Vice President - Strategic Planning and Development in March 2004. Prior to that he served as Senior Vice President of our subsidiary, Black Hills Generation, Inc. from September 2002 to March 2004 and as Vice President of Corporate Development from July 2000 to September 2002.
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James M. Mattern, age 51, has been the Senior Vice President – Corporate Administration and Compliance since April 2003 and Senior Vice President-Corporate Administration from September 1999 to April 2003. Mr. Mattern has 18 years of experience with us.
Roxann R. Basham, age 44, was elected Vice President – Governance and Corporate Secretary in February 2004. Prior to that, she was our Vice President-Controller from March 2000 to January 2004. Ms. Basham has a total of 22 years of experience with us.
Kyle D. White, age 46, has been Vice President – Corporate Affairs since January 30, 2001 and Vice President – Marketing and Regulatory Affairs since July 1998. Mr. White has 23 years of experience with us.
Garner M. Anderson, age 43, has been our Vice President and Treasurer since July 2003. Mr. Anderson has 17 years of experience with us, including positions as Director – Treasury Services and Risk Manager.
Perry S. Krush, age 47, was appointed Vice President – Controller in December 2004. Mr. Krush has over 16 years of experience with us, including positions as Controller – Retail Operations from 2003 to 2004, Director of Accounting for our subsidiary, Black Hills Energy Inc. and Accounting Manager – Fuel Resources from 1997 to 2003.
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PART II
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on The New York Stock Exchange under the symbol BKH. As of March 1, 2006, we had 5,367 common shareholders of record and approximately 17,200 beneficial owners, representing all 50 states, the District of Columbia and 12 foreign countries.
We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 2006 meeting, our board of directors raised the quarterly dividend to $0.33 per share, equivalent to an annual dividend of $1.32 per share.
The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities, any regulatory restrictions and our future business prospects. Our credit facilities contain restrictions on the payment of cash dividends, the most restrictive of which prohibit the payment of cash dividends if our fixed charge coverage ratio, as calculated in our credit agreements, is less than 2.5:1.0, our recourse leverage ratio exceeds 0.65:1.00 or our consolidated net worth does not exceed the sum of $625 million and 50 percent of our aggregate consolidated net income since January 1, 2005.
Quarterly dividends paid and the high and low common stock prices, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:
UNREGISTERED SECURITIES ISSUED DURING THE FOURTH QUARTER OF 2005
No unregistered securities were issued during the fourth quarter of 2005. 34
ISSUER PURCHASES OF EQUITY SECURITIES
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ITEM 6. SELECTED FINANCIAL DATA
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____________________________________ We have experienced significant change over the last five years, primarily as a result of the expansion of our wholesale energy business, commodity price volatility and volatility in wholesale electric sales and the related margins at our electric utility, Black Hills Power. Unusual conditions in the Western energy markets during the first half of 2001 accounted for approximately $1.40 per share of our earnings in 2001. Impairment charges recorded to reduce the carrying value of long-lived assets to fair value were approximately $33.9 million after-tax in 2005, and approximately $76.2 million after-tax in 2003.
During 2005 we acquired Cheyenne Light, which is referred to as our Electric and gas utility segment. In addition, certain items related to 2001 through 2004 have been restated from prior year presentations to reflect the classification of Black Hills FiberSystems, Inc. as discontinued operations in 2005 (see Notes 1 and 18 of Item 8. Financial Statements and Supplementary Data).
For additional information on our business segments see – ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK AND NOTE 22 OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
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We are a diversified energy company operating principally in the United States with two major business groups – retail services and wholesale energy. We report for our business groups in the following financial segments:
Our retail services group currently consists of our electric utility, Black Hills Power, and our electric and gas utility, Cheyenne Light, which was acquired January 21, 2005. Our electric utility, Black Hills Power, Inc., generates, transmits and distributes electricity to approximately 63,500 customers in South Dakota, Wyoming and Montana. Our electric and gas utility serves approximately 38,700 electric customers and 32,500 natural gas customers in Cheyenne, Wyoming and vicinity. Our wholesale energy group, which operates through Black Hills Energy, Inc. and its subsidiaries, engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term “tolling” contracts; the production of coal, natural gas and crude oil primarily in the Rocky Mountain region; and the marketing and transportation of fuel products.
In June 2005, we sold our subsidiary, Black Hills FiberSystems, Inc., previously reported as our Communications segment. In April 2005, we also sold our Pepperell power plant, our last remaining power plant in the eastern region, which was previously reported in our Power generation segment. In May 2004, we sold our subsidiary, Landrica Development Corp., which held some land and coal enhancement facilities that were previously reported in our coal mining segment. Prior period results have been reclassified to present the financial information as Discontinued operations.
On January 5, 2006, we announced that we had entered into a definitive agreement to sell the operating assets of our oil marketing and transportation business. The transaction was completed on March 1, 2006. These assets and their operating results have been included in this Annual Report on Form 10-K as part of our energy marketing and transportation segment. Beginning with the first quarter of 2006, the assets and their operating results will be classified as part of Discontinued operations.
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Industry Overview
The overall energy industry improved its financial performance in 2005 on steady demand for products and services and strong wholesale prices for natural gas and oil. The industry also experienced significant challenges, such as the devastating effect of hurricanes, which curtailed gas and oil production in and around the Gulf of Mexico and disrupted utilities’ service across vast regions, and the effects of soaring natural gas, oil and coal prices on consumers of those commodities. International tensions, particularly in the Middle East, are contributing to the volatile condition of current energy markets. Uncertainties associated with foreign sources of crude oil imports and increasing demand for crude oil in foreign markets have influenced domestic energy prices in recent months, and future price indexes are at much higher levels than were expected a year ago.
While the energy industry is increasingly competitive due to economic change and technological innovation, the regulatory environment is likely in a transitional phase. The repeal of PUHCA effective in February 2006, and many of its restrictions on utility merger and acquisition activities, suggests that consolidation of utilities could occur in certain parts of the U.S. in the months and years ahead. At the federal level, transmission issues continue to receive significant attention as physical constraints and the need for more infrastructure investment becomes increasingly apparent.
The consequences of electric deregulation efforts of the 1990’s continue to challenge regulators. These efforts were intended to encourage competition, introduce consumer choice and attract additional investment in energy resources. In many states, electric utilities were required to disaggregate traditional functions of generation, transmission, distribution and marketing of electricity to open markets to competition. Due to a number of causes, energy consumers in some jurisdictions have been exposed to significant price increases and deterioration in service in recent years.
In 2005, state-level public utility commissions continued to evaluate the merits of regulated versus non-regulated environments for utilities. Relations between investor owned utilities and regulators seemed to improve and progress was made on multi-year rate cases in several jurisdictions. In a period of high costs of fuel for power generation, industrial use and home heating, it is expected that regulators will strive to keep rates reasonable, including allowing some electric utilities to revert to vertically integrated structures again. Because the benefits of a more competitive industry were not always evident, many regulators are now seeking new policy directions to assure greater stability and end-user value in the future.
A surge in investment in gas-fired power generation facilities occurred in the early 2000’s. Some of that investment led to an overabundance of power capacity in certain regions of the country. In many instances, “merchant” or non-contracted plants became financially distressed as market prices for power fell below the cost of production for extended periods in the 2002-2005 time frame. Many of these plants were deemed impaired and asset values were written down. Several companies abandoned their independent power production (IPP) strategy, sold their plants and exited the sector. IPP facilities under contract with utilities have fared better than those subject to volatile market conditions.
Mild weather over vast sections of the U.S. in recent years, combined with slower regional economic growth, contributed to a slowdown in electric energy demand nationwide. As a result of excess energy supply, wholesale power prices have been relatively soft for much of the last three years. However, in December 2005, power prices surged in response to weather-related demand. Extreme pricing was short-lived as weather returned to a milder pattern. The quick response of the marketplace demonstrates that a resurgence of either colder winter months, a hotter than normal summer peaking season or increases in industrial demand could again cause volatile prices. In addition, the availability of hydroelectric power is unpredictable and dependent on precipitation in the northwestern U.S. Power prices in the West can be affected dramatically by changing hydroelectric conditions. In the current winter season of snow pack and moisture accumulation in watersheds feeding reservoirs in the Pacific Northwest, conditions point to improved hydroelectric performance relative to the last few years.
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The energy industry experienced a financial crisis beginning in late 2001, stemming from the collapse of Enron Corporation and the near collapse of several other leading energy companies. The cumulative market capitalization of energy companies fell on the scale of hundreds of billions of dollars, reflecting challenging market conditions and investor attitudes. Investors and consumers lost confidence in the financial health and future prospects of many energy providers as a result of numerous events. Accordingly, energy companies have been subject to much greater scrutiny by regulators, credit rating agencies and investors. In response, companies are moving aggressively to improve liquidity and to restructure their balance sheets. They have abandoned unsuccessful business strategies, sold non-core assets, downsized staffs, issued new equity, canceled acquisitions, postponed or canceled construction projects, reduced significant levels of capital expenditures, accelerated debt repayment and realigned trading around their own generation, mid-stream and transportation assets. In 2005, the energy industry generally showed improved financial condition and stronger balance sheets along with adequate liquidity and access to capital markets.
The oil and gas industry has experienced significant price volatility in the past several years, from a relatively lower-price environment in 2002 and 2003 to significantly higher prices for both commodities in 2005. In the 2000’s, natural gas has emerged as the national industrial fuel of choice because of its emissions characteristics, and demand has expanded significantly. For example, most of the recent increase in power generation capacity has been gas-fired, which in turn has exposed the generation companies’ financial performance to greater risk due to fuel price volatility. Recent favorable fuel prices have encouraged domestic oil and gas producers to increase production and reserves. In addition, investment in liquefied natural gas port facilities is expected to increase the availability of gas supplies in future years.
The U.S. coal industry has experienced resurgence in the past few years, with favorable commodity prices creating attractive returns. Coal prices in Wyoming’s Powder River Basin have increased dramatically in 2005, despite its lower heat content characteristics and higher transportation costs. From a regional perspective, Powder River Basin coal is a very competitive energy resource. Fossil fuel combustion continues to be an international policy issue, with opponents arguing environmental harm, despite the application of advanced emissions technology. Because coal continues to be an economical resource, its long-term prospects as a significant portion of a national energy mix remains strong.
Business Strategy
We are a customer-focused diversified energy provider. Our business is comprised of fuel assets, electric generation assets and retail utility assets, including electric and gas distribution systems. To optimize the value of those assets, we utilize our energy marketing and transportation expertise. Our focus on customers, whether retail utility customers or wholesale generation or marketing customers, provides us with opportunities to expand our various businesses. The diversity of our operations avoids reliance on any single business to achieve our strategic objectives. This diversity is expected to provide a measure of stability to our business and financial performance in volatile or cyclical periods. It should help us reduce our total corporate risk and allow us to achieve stronger returns over the long term. The strength and stability of our balance sheet is critical in today’s market. Access to capital, sufficient liquidity and quality of earnings are our key drivers.
Our balanced, integrated approach to fuel production, power generation, energy marketing and retail utility operations is supported by disciplined risk management practices.
Our long-term strategy is to continue growing our core retail utility, generation and fuel asset businesses, supplemented by our energy marketing operations. We will do this primarily by focusing on providing superior economic and performance value to customers and increasing our customer base. In the retail area, we will focus on acquiring new customers through the acquisition of additional retail utility properties, while maintaining our high customer service and reliability standards. In the power generation area, we will focus on long-term contractual relationships with key wholesale customers, as well as new customers, to allow us to expand existing generation sites, or to construct or acquire new generation facilities. In the fuel area, we will continue to strive to maintain our positive relationships with mineral owners and regulatory authorities and work to develop additional markets for our production, including the development of additional power plants at our mine site. The expertise of our energy marketing business will continue to enable us to optimize the value of our asset businesses.
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The following are key elements of our business strategy:
Operate our lines of business as retail and wholesale energy components. The retail component consists of electric and natural gas products and services. The wholesale component consists of fuel production, marketing, mid-stream assets and power production facilities. Through the retail and wholesale groups of our business, operating efficiencies are achieved. In the retail group, the integration of customer service and marketing and promotional efforts streamline operating processes and improve productivity. In the wholesale group, the fuel production, marketing and generation segments integrate balanced, yet diverse strategic operations.
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Review Black Hills Power’s Rate Structure for our Residential, Commercial and Industrial Customers While Retaining the Flexibility to Selectively Market Excess Generating Capacity Off-System to Maximize Returns in Changing Market Environments. Through a settlement with the SDPUC Black Hills Power has been under a retail rate freeze since 1995. The rate freeze agreement terminated on January 1, 2005. The rate freeze preserved Black Hills Power’s low-cost rate structure at levels below the national average for our retail customers while allowing us to retain the benefits from cost savings and wholesale “off-system” sales. This has provided us with flexibility in allocating Black Hills Power’s power supply resources to maximize returns in changing market environments. We have historically optimized the utilization of Black Hills Power’s power supply resources by selling wholesale power to other utilities and to power marketers in the spot market and through short-term sales contracts. Absent any request for a rate change by us or the SDPUC, rates will remain unchanged from those in place during the rate freeze. We will continue to monitor our rate structure and when appropriate, we will file a rate case.
Invest in Rate-Base Generation to Serve our Electric Utilities. Our Company’s original business was a vertically integrated electric utility. This business model remains a core strength today, where we operate efficient power generation resources to transmit and distribute electricity to our customers. By doing so, we provide power at reasonable and stable rates to our customers and earn solid returns to our investors. Rate-based generation assets offer several advantages for consumers, regulators and investors. First, they assure consumers that rates have been reviewed and approved by government authorities who are safeguarding the public interest. Second, regulators are given the opportunity to participate in a planning process where long-term investments are designed to match long-term energy demand. Third, investors are assured that a long-term, reasonable, stable rate of return may be earned on their investment. A lower risk profile may also improve credit ratings which, in turn, can benefit both consumers and investors, by lowering the cost of capital to the Company.
Expand Retail Operations Through Selective Acquisitions of Electric and Gas Utilities Consistent with our Regional Focus and Strategic Advantages. For more than 60 years, we have provided strong retail services, based on delivering quality and value to our customers. That tradition and accomplishment is expected to support efforts to expand our retail operations in other markets, most likely in the West and in regions that permit us to take advantage of our intrinsic competitive advantages, such as baseload power generation and system reliability. The January 2005 acquisition of Cheyenne Light and the November 2005 non-binding offer to combine with Northwestern Corporation are examples of such expansion efforts. Retail operations also can augment other important business development, including transmission and pipelines and storage infrastructure, which could lead to advancing other wholesale operations. Regulated retail operations can contribute substantially to the stability of our long-term cash flows and earnings.
Build and Maintain Strong Relationships With Wholesale Power Customers. We strive to build strong relationships with utilities, municipalities and other wholesale customers, who we believe will continue to be the primary providers of electricity to retail customers in a deregulated environment. We further believe that these entities will need products, such as capacity, in order to serve their customers reliably. By providing these products under long-term contracts, we are able to meet our customers’ energy needs. Through this approach, we also believe we can earn more stable revenues and greater returns over the long term than we could by selling energy into the more volatile spot markets.
Conduct Business with a Diversified Group of Creditworthy or Sufficiently Collateralized Counterparties. Our operations require effective management of counterparty credit risk. We mitigate this risk by conducting business with a diversified group of creditworthy counterparties. In certain cases where creditworthiness merits security, we require prepayment, secured letters of credit or other forms of financial collateral. We accomplish this by establishment of counterparty credit limits, continuous credit monitoring, and regular review of compliance with our credit policy by our executive risk committee that reports to our board of directors.
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Sell a Large Percentage of our Capacity and Energy Production From Independent Power Projects Through Mid- and Long-Term Contracts Primarily to Load Serving Utilities in Order to Secure a Stable Revenue Stream and Attractive Returns. By selling the majority of our energy and capacity under mid- and long-term contracts, we believe that we can satisfy the requirements of our customers while earning more stable revenues and greater returns over the long term than we could by selling our energy into the more volatile spot markets. When possible, we structure long-term contracts as tolling arrangements, whereby the contract counterparty assumes the fuel risk. Our goal is to sell a majority of our unregulated power generation under long-term, pre-approved contracts primarily to load serving utilities.
Grow our Power Generation Segment by Developing and Acquiring Power Generating Assets in Targeted Western Markets and, in Particular, by Expanding Generating Capacity of our Existing Sites Through a Strategy Known as “Brownfield Development.” We aim to develop power plants in regional markets based on prevailing supply and demand fundamentals in a manner that complements our existing fuel assets and fuel and energy marketing capabilities. This approach seeks to capitalize on market growth while managing our fuel procurement needs. Over the next few years, we intend to grow through a combination of disciplined acquisitions and development of new power generation facilities primarily in the western regions where we believe we have the detailed knowledge of market fundamentals and competitive advantage to achieve attractive returns. We believe the following trends will provide us with growth opportunities in the future:
We believe that existing sites with opportunities for brownfield expansion generally offer the potential for greater returns than development of new sites through a “greenfield” strategy. Brownfield sites typically offer several competitive advantages over greenfield development, including:
We expanded our capacity with brownfield development at our Valmont and Wyodak sites in 2001, Arapahoe and Las Vegas sites in 2002 and our Wyodak site in 2003 and currently with the ongoing construction of the Wygen II facility. We believe that our Fountain Valley, Harbor, Wyodak and Las Vegas sites in particular provide further opportunities for significant expansion of our gas- and coal-fired generating capacity over the next several years.
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Exploit our Fuel Cost Advantages and our Operating and Marketing Expertise to Produce Power at Attractive Margins. We expect to expand our portfolio of power plants having relatively low marginal costs of producing energy and related products and services. As an increasing number of gas-fired power plants are brought into operation, we intend to utilize a low-cost power production strategy, together with access to coal and natural gas reserves, to protect our revenue stream. Low marginal production costs can result from a variety of factors, including low fuel costs, efficiency in converting fuel into energy, and low per unit operation and maintenance costs. We aggressively manage each of these factors with the goal of achieving very low production costs.
Our primary competitive advantage is our coal mine, which is located in close proximity to our retail service territories. We are exploiting the competitive advantage of this native fuel source by building additional mine-mouth coal-fired generating capacity. This strengthens our position as a low-cost producer since transportation costs often represent the largest component of the delivered cost of coal.
Increase our Reserves of Natural Gas and Crude Oil and Expand our Production. Our strategy is to expand our natural gas reserves through a combination of acquisitions and drilling programs. We aim to maintain sufficient natural gas production either to directly serve or indirectly hedge the fuel cost exposure of our gas-fired generation plants. Specifically, we plan to:
Increase Margins From our Coal Production Through an Expansion of Mine-Mouth Generation and Increased Coal Sales. Our primary strategy is to expand our coal production through the construction of mine-mouth coal-fired generation plants at our Wyodak mine location. Our objective is to maintain coal reserves to serve our mine-mouth coal-fired generation plants directly. Specifically, we plan to:
Grow our Energy Marketing Operations Primarily Through the Expansion of Producer and End-use Origination Services and, as Warranted by the Market, Natural Gas Storage and Transportation. Our energy marketing business seeks to provide services to producers and end-users of natural gas, and to capitalize on market volatility by utilizing storage, transportation and proprietary trading positions. The service provider focus of our energy marketing activities is what largely differentiates us from other energy marketers. Through our producer services group we assist mostly small to medium sized producers throughout the Western U.S. with marketing and transporting their natural gas to market. Through our wholesale marketing division we work with utilities, municipalities and industrial users of natural gas to provide customized delivery services as well as to support their efforts to optimize their transportation and storage positions. In the future, we may add other energy commodities to our marketing portfolio or seek to acquire mid-stream assets, such as regional pipelines, so we can further facilitate and augment our marketing services.
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Manage the Risks Inherent in Energy Marketing by Maintaining Position Limits That Minimize Price Risk Exposure. Our energy marketing operations require effective management of price and operational risks related to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we have implemented risk management policies and procedures for our marketing operations that establish price risk exposure levels. We formed oversight committees to monitor compliance with our policies. We also limit exposure to energy marketing risks by maintaining credit facilities separate from our corporate facility.
Prospective Information
We expect long-term growth through the expansion of integrated, balanced and diverse energy operations. We recognize that sustained growth requires continued capital deployment. We believe that we are strategically positioned to take advantage of opportunities to acquire and develop energy assets consistent with our investment criteria and a prudent capital structure.
Retail Services Group
Electric Utility
Firm electric business at our electric utility, Black Hills Power, remained strong in 2005. We believe that Black Hills Power will produce modest growth in revenue, and absent unplanned plant outages, it will continue to produce stable earnings for the next several years. We forecast firm energy sales in our retail service territory to increase over the next 10 years at an annual compound growth rate of approximately one percent, with the system demand forecasted to increase at a rate of two percent. These forecasts are derived from studies conducted by us whereby we examined and analyzed our service territory to estimate changes in the needs for electrical energy and demand over a 20-year period. These forecasts are only estimates, and the actual changes in electric sales may be substantially different. Weather deviations can also affect energy sales significantly when compared to forecasts based on normal weather. The portion of the utility’s future earnings that will result from wholesale off-system sales will depend on many factors, including native load growth, plant availability, electricity demand and commodity prices.
On January 1, 2005, the South Dakota retail rate freeze under which Black Hills Power has operated since January 1, 2000, expired. The current South Dakota retail electric rates, along with the Wyoming retail electric rates, have been in place since the summer of 1995. These rates, which have remained flat for more than 10 years, do not include fuel and/or purchased power adjustment clauses, but allow Black Hills Power to retain the benefits of off-system wholesale sales and cost reductions. Black Hills Power’s return is affected by changes in fuel prices, inflation, capital investment, capital markets, and retail and wholesale power sales. We will monitor these potential impacts in order to ensure that our return remains adequate for its investment to serve customers. If necessary, increases to rates will be sought through the regulatory process.
Electric and Gas Utility
We acquired Cheyenne Light on January 21, 2005. We requested and received approval from the WPSC for a rate increase that went into effect on January 1, 2006 and will increase annual revenues by an expected $4.8 million. We also expect additional costs in 2006 related to allocated corporate costs to total approximately $2.7 million. We began construction on Wygen II, a 90-megawatt baseload coal-fired power plant. The plant will be a regulated asset of Cheyenne Light. The facility is expected to cost approximately $169 million, including interim financing costs during construction. This power plant is expected to be in commercial operation in early 2008 and will require a future rate review with the WPSC in order to recover capital and provide a return on invested capital. Presently, power is provided by Public Service Company of Colorado under an all-requirements contract, which expires December 31, 2007.
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Wholesale Energy Group
Power Generation
We expect lower earnings, excluding the impairment charges in 2005, from our Power Generation segment in 2006 primarily as a result of maintenance issues at our Las Vegas facility. In January 2006, the Las Vegas II plant was taken off line for diagnosis and initiation of repairs of both of its heat recovery steam turbine generators. We have restored two-thirds of the plant capacity and energy availability through simple-cycle generation but expect the maintenance period to extend into the second quarter of 2006. The negative financial impact of this unplanned outage is under evaluation, and is currently expected to be in the range of $0.05 to $0.08 per share. At the Las Vegas I power plant, an extensive maintenance program initiated in the fourth quarter of 2005 continues, and plant repairs and upgrades are expected to be completed in April 2006.
Significant earnings provided by power fund investments in 2005 are not expected in 2006 and beyond. During 2005 two of the funds in which we invest liquidated a substantial portion of their underlying power plant investments, generally realizing large gains over the expected fair market value, and a third fund achieved certain performance thresholds that triggered an “equity flip” increasing our ownership interest, from which we recorded a benefit.
Oil and Gas
We expect that earnings from this segment over the next few years will be driven primarily by increased oil and gas production. Driven by our March 2003 acquisition of Mallon Resources and the ongoing subsequent development of these properties, our compound annual production growth on a per Mcfe basis has been approximately 23 percent since our 2002 pre-acquisition level. Our long-term compound annual production growth target is 10 percent. In 2006 we expect to achieve our production growth target and benefit from a strong pricing environment, even while drilling and completion costs continue to rise, as shortages persist in the industry.
We expect to deploy approximately $70-$75 million of capital in 2006 developing our current properties, including the Piceance Basin gas assets acquired from Red Oak Capital Management, LLC in December 2005. This forecast does not include the acquisition or future development costs of the Koch properties that we entered into a definitive agreement to acquire during March 2006. Our drilling program is focused on both proved reserves and the further delineation of existing fields. We have also commenced an oil well development drilling program on our existing properties in northeast Wyoming.
Energy Marketing and Transportation
On March 1, 2006 we completed the sale of our crude oil marketing and transportation assets with a sales price of approximately $41.0 million. We expect to record a gain on the sale and cash proceeds are expected to be used for debt reduction or other corporate purposes. Beginning with the first quarter of 2006, operating results from these assets will be classified as Discontinued operations and will not contribute to the earnings of this segment in 2006. Earnings from these operations were approximately $2.5 million in 2005. In addition, due to the required gross presentation of crude oil marketing revenues and cost of sales, future revenues and operating expenses will decrease significantly while having no significant impact on earnings. During 2005, revenues and cost of sales generated from the operating assets sold were $778.1 million and $765.2 million, respectively.
Coal Mining
We expect lower earnings from our Coal Mining operations in 2006 resulting from a major planned outage at the Wyodak power plant, the mine’s largest customer. The outage is expected to last approximately six weeks and occur during the second quarter of 2006.
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Results of Operations
Consolidated Results
Overview
Revenue and income (loss) from continuing operations provided by each business group were as follows (in thousands):
In June 2005, we sold our subsidiary, Black Hills FiberSystems, Inc., previously reported as our communications segment. In April 2005, we also sold our Pepperell power plant, our last remaining power plant in the eastern region, which was previously reported in our power generation segment.
In May 2004, we sold our subsidiary, Landrica Development Corp., which held some land and coal enhancement facilities that were previously reported in our coal mining segment.
In September 2003, we sold our hydroelectric power plants located in upstate New York. These discontinued operations were previously reported in the power generation segment.
Results of operations for 2004 and 2003 have been restated to reflect the operations discontinued.
2005 Compared to 2004
Consolidated income from continuing operations for 2005 was $35.8 million, compared to $61.2 million in 2004, or $1.07 per share in 2005, compared to $1.86 per share in 2004. Loss from discontinued operations was $(2.3) million or $(0.07) per share in 2005, compared to loss of $(3.2) million or $(0.10) per share in 2004. Return on average common equity in 2005 and 2004 was 4.5 percent and 8.1 percent, respectively.
The wholesale energy group’s income from continuing operations decreased $16.8 million in 2005 compared to 2004. Decreased earnings from power generation of $28.1 million and from coal mining of $0.5 million were offset by increased income from continuing operations of $5.7 million at our oil and gas operations and $6.1 million from energy marketing and transportation operations.
The retail services group’s income from continuing operations increased $0.9 million in 2005 compared to 2004. Earnings from the electric and gas utility, acquired January 21, 2005, were $2.1 million and earnings from continuing operations from the electric utility decreased $1.2 million. 47
Corporate costs for the year ended December 31, 2005 increased $9.6 million after tax, compared to 2004. The increase is primarily due to the write-off of approximately $6.4 million, after-tax of certain capitalized project development costs and the expensing of other development costs, which are included in Administrative and general operating expenses on the accompanying consolidated statements of income. These costs were partially offset by allocating increased compensation and debt retirement costs down to the subsidiary level. In addition, the Company’s subsidiary, Daksoft, Inc., recorded a $1.0 million pre-tax gain in 2004, on the sale of its campground reservation system.
Consolidated operating expenses for 2005 increased $359.8 million compared to 2004. Increased operating expenses reflect a $251.7 million increase in fuel and purchased power, a $52.2 million impairment charge at our power generation segment and a $33.3 million increase in administrative and general costs. Higher fuel and purchased power costs were primarily the result of the increased cost of crude oil marketed and the cost of sales of electricity and gas at Cheyenne Light, which was acquired during 2005. The increase in administrative and general costs was primarily the result of higher corporate development costs, including the write-off of previously capitalized development costs, higher legal and professional fees resulting from ongoing litigation, the additional administrative and general costs of Cheyenne Light, and higher compensation costs.
2004 Compared to 2003
Consolidated income from continuing operations for 2004 was $61.2 million, compared to $62.3 million in 2003, or $1.86 per share in 2004, compared to $2.01 per share in 2003. Loss from discontinued operations was $(3.2) million or $(0.10) per share in 2004, compared to income of $4.1 million or $0.13 per share in 2003. Return on average common equity in 2004 and 2003 was 8.1 percent and 9.9 percent, respectively.
The wholesale energy group’s income from continuing operations decreased $0.4 million in 2004 compared to 2003. Increased income from continuing operations of $3.8 million at our oil and gas operations and $3.5 million from energy marketing and transportation operations were offset by decreased earnings from power generation of $6.8 million and from coal mining of $0.9 million.
The retail services group’s income from continuing operations decreased $4.8 million in 2004 compared to 2003. Earnings from continuing operations from the electric utility decreased $4.9 million due to lower margins received, increased maintenance expense and general and administrative costs partially offset by lower interest expense.
Corporate costs for the year ended December 31, 2004 decreased $4.1 million after tax, compared to 2003. The decrease is primarily due to increased allocations to subsidiaries and a $1.0 million pre-tax gain on sale of assets, partially offset by increased costs related to Sarbanes-Oxley compliance, and holding company structuring and higher pension, insurance and interest expense.
Discussion of results from our operating segments is included in the following pages.
The following business group and segment information does not include discontinued operations or intercompany eliminations. Accordingly, 2004 and 2003 information has been revised to remove information related to operations that were discontinued.
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Retail Services Group
Electric Utility
The following table provides certain electric utility operating statistics:
We established a new summer peak load of 401 megawatts in July 2005 and a new winter peak load of 356 megawatts in December 2005. We own 435 megawatts of electric utility generating capacity and purchase an additional 50 megawatts under a long-term agreement expiring in 2023. 49
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