UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 Form 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES X EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ___________________ to _________________ Commission File Number 333-52664 BLACK HILLS CORPORATION Incorporated in South Dakota IRS Identification Number 46-0458824 625 Ninth Street Rapid City, South Dakota 57701 Registrant's telephone number, including area code (605) 721-1700 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered ------------------- ------------------- Common stock of $1.00 par value New York Stock Exchange Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES X NO --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X State the aggregate market value of the voting stock held by non-affiliates of the Registrant. At February 28, 2002 $734,526,500 Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date. Class Outstanding at February 28, 2002 ----- -------------------------------- Common stock, $1.00 par value 26,694,625 shares Documents Incorporated by Reference 1. Definitive Proxy Statement of the Registrant filed pursuant to Regulation 14A for the 2002 Annual Meeting of Stockholders to be held on May 29, 2002, is incorporated by reference in Part III.
TABLE OF CONTENTS <TABLE> <CAPTION> Page <S> <C> <C> ITEMS 1 & 2. BUSINESS AND PROPERTIES.....................................................................................3 General...................................................................................................3 Industry Overview.........................................................................................5 Strategy..................................................................................................6 Integrated Energy.........................................................................................8 Power Generation........................................................................................9 Fuel Production.........................................................................................14 Fuel Marketing..........................................................................................15 Electric Utility - Black Hills Power, Inc.................................................................17 Communications............................................................................................20 Competition...............................................................................................20 Risk Management...........................................................................................21 Regulation................................................................................................21 Energy Regulation.......................................................................................22 Environmental Regulation................................................................................22 Exploration and Production..............................................................................26 Other Properties..........................................................................................26 Employees.................................................................................................26 ITEM 3. LEGAL PROCEEDINGS...........................................................................................27 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........................................................27 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.......................................28 ITEM 6. SELECTED FINANCIAL DATA.....................................................................................29 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.........................................................................30 BUSINESS STRATEGY.........................................................................................30 RESULTS OF OPERATIONS.....................................................................................31 CRITICAL ACCOUNTING POLICIES..............................................................................39 LIQUIDITY AND CAPITAL RESOURCES...........................................................................40 MARKET RISK DISCLOSURES...................................................................................46 RATE REGULATION...........................................................................................51 NEW ACCOUNTING PRONOUNCEMENTS.............................................................................52 SAFE HARBOR FOR FORWARD LOOKING INFORMATION...............................................................53 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................................54 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE......................................................................87 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................................87 ITEM 11. EXECUTIVE COMPENSATION......................................................................................88 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..............................................88 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................................88 ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.............................................88 SIGNATURES..................................................................................................92 </TABLE> 2
FORWARD-LOOKING STATEMENTS This Form 10-K includes "forward-looking statements" as defined by the Securities and Exchange Commission. These statements concern our plans, expectations and objectives for future operations. 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. The words "believe," "plan," "intend," "anticipate," "estimate" "project" and similar expressions are also intended to identify forward-looking statements. These forward-looking statements include, among others, such things as: o expansion and growth of our business and operations; o future financial performance; o future acquisition and development of power plants; o future production of coal, oil and natural gas; o reserve estimates; and o business strategy. 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 which could cause actual results to differ materially from those contained in the forward-looking statements, including the following factors: o prevailing governmental policies and regulatory actions with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition; o changes in and compliance with environmental and safety laws and policies; o weather conditions; o population growth and demographic patterns; o competition for retail and wholesale customers; o pricing and transportation of commodities; o market demand, including structural market changes; o changes in tax rates or policies or in rates of inflation; o changes in project costs; o unanticipated changes in operating expenses or capital expenditures; o capital market conditions; o technological advances; o competition for new energy development opportunities; and o legal and administrative proceedings that influence our business and profitability. PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES General We are a growth oriented, diversified energy holding company operating principally in the United States. Our regulated and unregulated businesses have expanded significantly in recent years. Our integrated energy group produces and markets power and fuel. We produce and sell electricity in a number of markets, with a strong emphasis on the western United States. We also produce coal, natural gas and crude oil primarily in the Rocky Mountain region and market fuel products nationwide. Our electric utility serves approximately 59,200 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communication services to residential and business customers in Rapid City and the northern Black Hills region of South Dakota. Our predecessor 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. 3
As the following table illustrates, we have experienced significant growth over the last five years, primarily as a result of the expansion of our integrated energy business and increases in wholesale electric sales. <TABLE> <CAPTION> - ---------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 - ---------------------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> <C> Net income available for common (in thousands): Integrated energy $ 56,246 $ 28,213 $ 11,588 $ 10,068 $ 10,471 Electric utility 45,238 37,100 27,362 24,825 22,106 Communications (12,300) (11,382) (968) (280) (218) Corporate expenses and intersegment eliminations (1,634) (1,161) (915) - - Oil and gas write-down - - - (8,805) - -------- --------- -------- -------- -------- $ 87,550 $ 52,770 $ 37,067 $ 25,808 $ 32,359 ======== ========= ======== ======== ======== Earnings per share - diluted $3.42 $2.37 $1.73 $1.60(2) $1.49 Total assets (in thousands) $1,658,767 $1,320,320 $668,492 $559,417 $508,741 Capital expenditures (in thousands) $594,156 $173,517(1) $154,609 $27,225 $28,319 The following is unaudited: Generating capacity (megawatts) Utility (owned generation) 395 393 353 353 353 Utility (purchased capacity) 65 70 75 75 75 Independent power generation 617 250 - - - ---------- ---------- -------- --------- --------- Total generating capacity 1,077 713 428 428 428 ========== ========== ======== ========= ========= Utility electric sales (megawatt-hours): Regulated utility Firm electric sales 2,012,354 1,973,066 1,920,005 1,923,331 1,932,347 Wholesale off-system 965,030 684,378 445,712 371,104 279,612 ---------- ---------- ---------- ---------- ---------- Total utility electric sales 2,977,384 2,657,444 2,365,717 2,294,435 2,211,959 ========== ========== ========== ========== ========== Oil and gas reserves (Mmcfe) 48,401 44,882 44,114 30,160 24,022 Oil and gas production sold (Mmcfe) 7,293 5,278 4,698 4,120 3,541 Tons of coal sold (thousands of tons) 3,518 3,050 3,180 3,280 3,251 Average daily marketing volumes: Natural gas (MMbtus) 1,047,700 860,800 635,500 524,800 231,000 Crude oil (barrels) 36,500 44,300 19,270 19,000 12,600(3) Coal (tons) 6,100 4,400 4,500 4,400(3) - Communications: Residential customers 15,660 8,368 143 - - Business customers 2,250 646 110 - - Fiber optic backbone miles 242 210 200 - - Hybrid fiber coaxial cable miles 737 588 100 - - - ---------------------------------------------------------------------------------------------------------------------- </TABLE> (1) Excludes the non-cash acquisition of Indeck Capital, Inc. (2) Excludes impact of $0.41 per share non-cash write-down of oil and gas properties due to historically low oil prices, lower natural gas prices and a decline in the value of unevaluated properties. (3) Since date of inception of marketing operations. For additional information on our business segments see - "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and Note 14 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS." 4
Industry Overview In the last decade, many U.S. regulatory bodies have taken steps to transform the energy sectors which they regulate to encourage competition, introduce customer choice and, in some cases, to improve the operational performance of strategic energy assets. In particular, the electric power industry is undergoing substantial change as a result of regulatory initiatives at the federal and state levels. As early as the mid-1990's, new regulatory initiatives to increase competition in the domestic power generation industry had been adopted or were being considered at the federal level and by many states. The primary focus of such efforts was to increase competition through the disaggregation of the traditional utility functions of generation, transmission, distribution and marketing of electricity into competitive or partially regulated businesses. This resulted in new investment opportunities to enter previously non-competitive or closed markets. In 1992, the Federal Energy Regulatory Commission (FERC) issued Order 636, followed by Order 888 in 1996, to increase competition by easing entry into natural gas and electricity markets. These orders require owners and operators of natural gas and power transmission systems to make transmission service available on a non-discriminatory basis to energy suppliers. In order to better assure competitive access to the transmission network on a non-discriminatory basis, FERC issued Order 2000 in December 1999, which encourages electric utilities with power transmission assets to voluntarily form regional transmission organizations to provide regional management and control of transmission assets independent of firms that sell electricity. The electric power industry has also witnessed growing consumer demand and frequent regional shortages of electricity over the past several years. The summers of 1998, 1999 and 2000 and the winter of 2000-2001 have all been characterized by very high peak prices for electricity in a number of recently created wholesale electricity markets. Mild weather patterns in the summer of 2001 and winter of 2001-2002 and the current recession have mitigated most regional energy shortages. However, we believe that the reduction in demand for energy is temporary and there remains a long-term need for new electric generating capacity to relieve shortages of electricity and to replace inefficient and obsolete facilities. The oil and gas industry has experienced volatile changes in commodity prices in the last year. Price increases have been driven in part by several years of modest drilling activity combined with strong growth in demand for energy commodities. Price decreases have been driven by weather patterns, the recession and actions by OPEC. Natural gas is expected to remain the fuel of choice and demand for natural gas is expected to be strong in the future as an increasing number of gas-fired power plants are brought into service. The telecommunications industry is currently undergoing widespread changes brought about by, among other things, the Telecommunications Act of 1996, the decisions of federal and state regulators to open the monopoly local telephone and cable television markets to competition and the need for higher speed, higher capacity networks to meet the increasing consumer demand for expanded telecommunications services, including broader video choices and high speed data and Internet services. The convergence of these trends and the inherent limitations of most existing networks have created opportunities for new types of communications companies capable of providing a wide range of voice, video and data services through new and advanced high speed, high capacity telecommunications networks. As a result of historical and anticipated regulatory initiatives and the increasing demand for electricity, fuel and broadband services, we believe there are significant opportunities for the development and growth of our integrated energy businesses, our regulated utility and our communications business. 5
Strategy Our strategy is to build long-term shareholder value by adding and augmenting revenue streams from our diverse integrated energy operations. We have implemented a balanced, integrated and risk managed approach to fuel production, energy marketing and independent power. We expect our integrated energy businesses to operate nationwide, with an integrated regional emphasis on the western half of the United States. Built on the strength of our electric utility, we have enhanced our local operations by providing broadband communications. Our utility and communications businesses intend to continue focusing their retail operations primarily in Rapid City and the northern Black Hills region of South Dakota, with wholesale power sales concentrated primarily in the Rocky Mountain and West Coast regions and the ability to move a limited amount of power to the eastern markets. Our diverse operations avoid reliance on any single element to achieve our growth objective. This diversity provides a measure of stability in volatile or cyclical periods. Our strategy includes the following key elements: o grow our power generation segment by developing and acquiring power projects in targeted western markets; o expand the generating capacity of our existing sites through a strategy known as "brownfield development;" o sell a large percentage of the production from our independent power projects through long-term contracts in order to secure attractive investment returns; o increase our reserves and production of natural gas and crude oil; o maintain abundant clean coal reserves to assure low-cost generation capability; o exploit our fuel cost advantages and our operating and marketing expertise to remain a low-cost power producer; o exploit our knowledge and market expertise while managing the risks inherent in fuel marketing; o build and maintain strong relationships with wholesale energy customers; and o capitalize on our utility's established market presence, relationships and customer loyalty. Grow our Power Generation Segment by Developing and Acquiring Power Projects in Targeted Western Markets. Our aim is to continue the development of 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 aims 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 region 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: o Demand for electricity in the western regions will grow and new generation capacity will be required over the next several years. o New electric generation construction will be predominantly gas-fired, which may create further competitive cost advantages for new and existing coal-fired generation assets. 6
o Transmission construction will significantly lag new generation development, favoring new development located near load centers or existing, unconstrained transmission locations. o Disaggregation of the electric utility industry from traditionally vertically integrated utilities into separate generation, transmission, distribution and marketing entities will continue, thereby creating opportunities for acquisitions and joint ventures. Expand the Generating Capacity of Our Existing Sites Through a Strategy Known as "Brownfield Development." 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: o proximity to existing transmission systems; o operating cost advantages related to ownership of shared facilities; o a less costly and time consuming permitting process; and o potential ability to share infrastructure with existing facilities at the same site. We are currently expanding our capacity with brownfield development underway at our Arapahoe, Las Vegas and Wyodak sites, and believe that our Fountain Valley, Wyodak and Las Vegas sites in particular provide further opportunities for a significant expansion of our gas- and coal-fired generating capacity over the next several years. Sell a Large Percentage of the Production From Our Independent Power Projects Through Long-Term Contracts in Order to Secure Attractive Investment 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. Approximately 90 percent of our power generation assets are under long-term contracts. Increase Our Reserves and Production of Natural Gas and Crude Oil and Maintain Abundant Clean Coal Reserves to Assure Low-Cost Generation Capability. We aim to support the fuel requirements of our growing portfolio of power plants as well as power plants owned by others by emphasizing natural gas and coal production. Our strategy is to expand our natural gas reserves through a combination of acquisitions and drilling programs and 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 and 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: o substantially increase our natural gas reserves while minimizing exploration risk by focusing on lower-risk exploration and development drilling as well as acquisitions of proven reserves; o exploit our belief that the long-term demand for natural gas will remain strong by emphasizing natural gas in our acquisition and drilling activities; o add natural gas reserves and increase production by focusing on various shallow gas plays in the Rocky Mountain region, where the added production can be integrated with our fuel marketing and/or power generation activities; 7
o increase coal production and sales from our Wyodak mine by continuing to develop additional mine-mouth generating facilities at the site, including the Wygen plant, which is scheduled for completion in first quarter 2003; and o pursue future sales of coal from the Wyodak mine to rail-served customers by reducing the moisture content of our coal so that we can ship it greater distances. Exploit Our Fuel Cost Advantage and Our Operating and Marketing Expertise to Remain a Low-Cost Power Producer. We expect to expand our portfolio of power plants having relatively low marginal costs of producing energy and related products and services. We intend to utilize a low-cost power production strategy, together with access to coal and natural gas reserves, to protect our revenue stream as an increasing number of gas-fired power plants are brought into operation. 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 have aggressively managed each of these factors to achieve very low production costs, especially at our coal-fired and hydroelectric generating facilities. Our primary competitive advantage is our coal mine, which is located in close proximity to our retail service territory. 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. Exploit Our Knowledge and Market Expertise While Managing the Risks Inherent in Fuel Marketing. We aim to apply our knowledge of and expertise in the natural gas transmission system and trading markets in the western and northwestern regions of the United States and western Canada in order to exploit market inefficiencies and maximize our profits in our fuel marketing businesses. Our fuel marketing operations require effective management of price, counterparty and operational risks. To mitigate these risks, we have implemented risk management policies and procedures for each of our marketing companies that establish price risk exposure levels, counterparty credit limits and committees to monitor compliance with our policies. We also limit exposure to energy marketing risks by maintaining separate credit facilities for each of our marketing companies. Build and Maintain Strong Relationships with Wholesale Energy 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. Capitalize On Our Utility's Established Market Presence, Relationships and Customer Loyalty. As a result of its firmly established market presence, our electric utility has built solid brand recognition and customer loyalty in the Black Hills region. By ensuring a reliable supply of power to retail customers in our South Dakota and Wyoming service territory at rates below the national average, we have developed a strong, supportive relationship with our utility regulators. Our utility provides a solid foundation of support for the expansion of our integrated energy and communications businesses. In addition, industry, technical and market expertise from our utility supports the growth of our integrated energy businesses, and our strong brand recognition assists us in achieving rapid customer acceptance of our bundled communications services in our Black Hills service territory. Integrated Energy Our integrated energy group engages in the production and sale of electric power 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 of fuel products nationwide. Net income from the integrated energy group exceeded net 8
income derived from our electric utility in 2001. We expect that earnings growth from the integrated energy group over the next few years will be driven primarily by our continued expansion in the power generation and oil and gas segments. The integrated energy group consists of four segments: power generation, oil and gas, coal mining and fuel marketing. Power Generation. Our power generation segment acquires, develops and expands unregulated power plants. We hold varying interests in operating independent power plants in California, New York, Massachusetts, Wyoming, Nevada and Colorado with a total net ownership of 593 megawatts, as well as minority interests in several power-related funds with a net ownership interest of 24 megawatts. Project Development Program. Power generation projects currently under construction include: o Arapahoe CC5, a 50 megawatt combined cycle expansion of our gas-fired turbines at the Arapahoe site located in the Front Range of Colorado, which is expected to be placed in service in mid-2002; o Las Vegas Cogeneration expansion, a 224 megawatt gas-fired co-generation power plant project located near Las Vegas, Nevada, which is expected to be placed in service in the third quarter of 2002; and o Wygen, a 90 megawatt coal-fired plant under construction at our Wyodak, Wyoming site which is expected to be operational in the first quarter of 2003. We will lease this plant. We also have an active acquisition and development program through which we are pursuing a number of additional generation projects in early stages of development, including a coal-fired mine-mouth power plant with generating capacity of up to 500 megawatts, to be located at our Wyodak site near Gillette, Wyoming. No assurance can be given that we will be successful in completing any or all of the projects currently under consideration. How We Manage Our Portfolio. We strive to maintain diversification and balance in our portfolio of regulated and unregulated power plants. Our portfolio (including plants currently operating and those under construction) is diversified in terms of fuel mix and geographic location, with 87 percent of net unregulated capacity being gas-fired, 9 percent coal-fired, and the remainder hydroelectric. Our independent power plants are located in California, Wyoming, Colorado, Nevada, New York and Massachusetts. In contrast, our electric utility capacity is approximately 50 percent coal-fired, 38 percent oil or gas-fired, and 12 percent under purchased power contracts, with plants located in South Dakota and Wyoming. We also have a diversified mix of revenue sources. We typically sell two types of products: energy and capacity, including ancillary services. Although these are separate products, both are typically sold together. Energy refers to the actual electricity generated by our facilities for ultimate transmission and distribution to consumers of electricity. Energy is the only one of our products that is subsequently distributed to consumers. Capacity refers to the physical capability of a facility to produce energy. Ancillary services generally are capacity support products used to ensure the safe and reliable operation of the electric power supply system. Examples of ancillary services include: o automatic generation control, which is used to balance energy supply with energy demand, referred to in our industry as "load," on a real-time basis; and o operating reserves, which are used on an hourly or daily basis to generate additional energy if demand increases or if major generating resources go off-line or if transmission facilities become unavailable. Our output is sold under contracts of varying length and subject to merchant pricing, thereby allowing us to take advantage of current favorable price trends, while hedging the impact of a potential downturn in prices in the future. We currently sell energy and capacity under a combination of short- and long-term contracts as well as direct sales into the merchant energy markets. Currently, we sell approximately 90 percent of our unregulated generating capacity 9
in operation under contracts greater than one year in duration. We sell the remainder of this capacity under short-term contracts or directly into the merchant markets. Substantially all of the energy and capacity to be generated by our projects under construction is also under long-term contracts. How We Develop and Acquire Power Plants. We plan to actively pursue power plant acquisitions and development opportunities in areas we view as attractive throughout North America. Our current focus has been, and is likely to remain, in the North American Reliability Council region known as the Western Systems Coordinating Council, or "WSCC." Among those factors we consider critical in evaluating the relative attractiveness of new generation opportunities are the following: o electric demand growth potential in the targeted region; o requirements for permitting and siting; o proximity of the proposed site to high transmission capacity corridors; o fuel supply reliability and pricing; o the local regulatory environment; and o the potential to exploit market expertise and operating efficiencies relating to geographic concentration of new generation with our existing power plant portfolio. Our goal is to sell approximately 80 percent of the independent power generation portfolio under long-term contracts, while leaving the remainder available for merchant, or "spot" sales. We aim to secure long-term power sales contracts in conjunction with project financing. This enables us to minimize our liability and to design a debt repayment schedule to closely match the term of the power sales contracts so that at the end of the contract term, the debt has largely been repaid. Independent Power Plants General. Power facilities are often classified by cost of production. Facilities that have the lowest costs of production relative to other power plants in the region are usually the facilities that are first used to provide energy. These plants are known as "baseload" facilities and typically operate more than 60 percent of the time they are available. Our hydroelectric assets in New York and the Wygen coal-fired facility under construction in Wyoming are examples of low-cost, baseload plants. As demand for electricity rises during the year or even during the course of a day, power plants that have higher costs of production are dispatched to supply additional energy. Facilities that regularly provide additional energy during a day and that are typically used between 10 percent and 60 percent of the time are known as "intermediate" facilities. Power plants with the highest costs of production are called upon only in times of exceptionally high demand and are known as "peaking units." Peaking units are generally dispatched less than 10 percent of the time they are available. Rocky Mountain and West Coast Facilities. We own approximately 525 megawatts of generating capacity in the WSCC states of California, Colorado, Nevada and Wyoming, and are in the process of constructing or acquiring another 364 megawatts in the region. All of these facilities in operation are gas-fired, with all but our Harbor Cogeneration facility in California operating under long-term power purchase or tolling agreements whereby the purchaser assumes the fuel risk. The Harbor Cogeneration facility currently operates as a merchant peaking plant selling ancillary services and energy into the California market. 10
<TABLE> <CAPTION> WSCC Facilities Total Net Fuel Capacity Capacity Start Power Plant Type State (MWs) Interest (MWs) Date ---- ----- -------- -------- -------- ----- <S> <C> <C> <C> <C> <C> <C> In Operation: Fountain Valley Gas CO 240.0 100% 240.0 2001 Arapahoe Unit 5 Gas CO 40.0 100% 40.0 2000 Arapahoe Unit 6 Gas CO 40.0 100% 40.0 2000 Valmont Unit 7 Gas CO 40.0 100% 40.0 2000 Valmont Unit 8 Gas CO 40.0 100% 40.0 2001 Las Vegas I Gas NV 53.0 50% 26.5 1994 Ontario Gas CA 12.0 50% 6.0 1984 Harbor Gas CA 80.0 53.3% 42.6 1989 Harbor Expansion Gas CA 18.0 53.3% 9.6 2001 Gillette CT Gas WY 40.0 100% 40.0 2001 ----- ----- Total in Operation 603.0 524.7 ----- ----- Under Construction: Arapahoe CC5 Gas CO 50.0 100% 50.0 2002 Las Vegas II Gas NV 224.0 100% 224.0 2002 Wygen Coal WY 90.0 100% 90.0 2003 ----- ----- Total in Construction 364.0 364.0 ----- ----- Total WSCC 967.0 888.7 ===== ===== </TABLE> Arapahoe, Valmont and Fountain Valley Facilities In Operation: 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 400 megawatts, including 280 megawatts which became operational during the summer of 2001. We sell all of the output from these plants to Public Service Company of Colorado under tolling contracts expiring in May 2012. These contracts also cover the Arapahoe expansion project described below. Under Construction: We expect to increase our capacity by 50 megawatts at the Arapahoe plant by mid 2002. Las Vegas Cogeneration Facility In Operation: Las Vegas Cogeneration, is a 53 megawatt, gas-fired plant northeast of Las Vegas, Nevada. Most of the power from this plant is sold to Nevada Power under a long-term contract that expires in 2024. We own 50 percent of this plant, however under generally accepted accounting principles, we consolidate 100 percent. Under Construction/Expansion: We are currently expanding the Las Vegas Cogeneration facility by an additional 224 megawatts. The expansion is expected to become fully operational during the third quarter of 2002. The power generated by the expansion will be sold under a long-term contract with Allegheny Energy Supply L.L.C. that expires in 2017. We own 100 percent of the expansion project. Wygen Facility Under Construction: The Wygen facility is a leased mine-mouth coal-fired plant with a total capacity of 90 megawatts, which is expected to be completed by first quarter 2003. The Wygen plant will be substantially identical in design to our electric utility's Neil Simpson II facility, completed in 1995. The plants will run on pulverized low-sulfur coal fed by conveyor from our adjacent Wyodak mine. The plant will burn approximately 11
500,000 tons of coal per year, and will use the latest available environmental control technology. We intend to sell the majority of the power from the facility under long-term unit contingent capacity and energy sales contracts, under which delivery is not required during plant outages. We have entered into a contract to sell 60 megawatts of unit contingent capacity from this plant to Cheyenne Light, Fuel and Power Company with a term of 10 years from the date the plant becomes operational. We have also signed a contract to sell an additional 20 megawatts of unit contingent capacity and energy to the Municipal Electric Agency of Nebraska for a term of 10 years. Gillette CT The Gillette CT facility, a gas-fired combustion turbine facility located at the same site as our Wygen plant, has a total capacity of 40 megawatts and became operational in May 2001. The energy and capacity from this facility is sold to Cheyenne Light, Fuel and Power Company under a 10-year tolling agreement. Ontario Cogeneration Facility Ontario Cogeneration Company is a 12 megawatt, gas-fired power plant in Ontario, California, which is currently being operated as a baseload plant. Electrical output from the plant is subject to a 25-year power purchase agreement with Southern California Edison, which expires in January 2010. The project also sells all of its steam production to Sunkist Growers, Inc. under a five-year agreement, which terminates in November 2002. For a description of certain issues relating to our operation of this plant, see "--Regulation--Environmental Regulation--Clean Air Act." Harbor Cogeneration Facility Harbor Cogeneration, a gas-fired plant located in Wilmington, California, is currently being operated as a merchant peaking plant selling ancillary services and energy into the California Independent System Operator, or "CAISO," market. It formerly operated under a 30-year power purchase agreement with Edison Mission Energy. This contract was terminated in February 1999 under a settlement agreement with Southern California Edison. Under the buyout agreement, Harbor Cogeneration will receive payments pursuant to a termination payment schedule for an amount equal to the total payment under the original contract due for the 11-year period beginning April 1, 1997 and ending on October 1, 2008. During 2001, we completed an expansion of the Harbor Cogeneration plant adding 18 megawatts (10 megawatt net ownership interest). The plant has sold the peaking capacity from its expansion to the CAISO for the peak summer periods of 2001 through 2003 under an agreement that provides for payments to us of approximately $0.6 million per year of the contract. We plan to sell the remaining capacity and all of the energy from this plant in the California market on a merchant basis. Northeast Facilities. We currently own approximately 68 net megawatts of generation capacity in eight plants in the Northeast region, all of which are located in New York and Massachusetts. Fifty-nine percent of this generation is "run-of-river" hydroelectric, with the remainder being gas-fired peaking capacity. 12
<TABLE> <CAPTION> Total Net Fuel Capacity Capacity Start Power Plant Type State (MWs) Interest (MWs) Date ---- ----- -------- -------- -------- ----- <S> <C> <C> <C> <C> <C> <C> Northeast New York State Dam Hydro NY 11.4 100% 11.4 1990 Middle Falls Hydro NY 2.3 50% 1.2 1989 Sissonville Hydro NY 3.0 100% 3.0 1990 Warrensburg Hydro NY 2.9 100% 2.9 1988 Hudson Falls Hydro NY 41.9 33.0% 13.8 1995 South Glens Falls Hydro NY 13.9 30.2% 4.2 1994 Fourth Branch Hydro NY 3.4 100% 3.4 1988 Pepperell Gas MA 40.0 70.7% 28.3 1990 ----- ---- Total Northeast 118.8 68.2 ===== ==== </TABLE> Adirondack Hydro Development The seven "run-of-river" hydroelectric plant interests are: o New York State Dam, an 11.4 megawatt plant located in Waterford and Cohoes, New York; o Middle Falls, a 2.3 megawatt plant located in Easton, New York; o Sissonville, a 3.0 megawatt plant located in Potsdam, New York; o Warrensburg, a 2.9 megawatt plant located in Warrensburg, New York; o Hudson Falls, a 41.9 megawatt plant located in Moreau, New York; o South Glens Falls, a 13.9 megawatt plant located in South Glens Falls, New York; and o Fourth Branch, a 3.4 megawatt plant located in Waterford, New York. The seven projects were initially covered by long-term power purchase contracts with Niagara Mohawk Power Corporation for all or most of their output. Currently, four projects have been restructured to allow the power purchase contracts to be bought out and for us eventually to sell power into the New York Independent System Operator (ISO). The New York State Dam, Sissonville, Fourth Branch and Warrensburg facilities are currently subject to short-term transition power sales agreements expiring in 2002 and 2003, at which point these plants will sell directly into the market on a merchant basis. The remaining three New York plants, Hudson Falls, South Glens Falls and Middle Falls, continue to operate under long-term power purchase agreements with Niagara Mohawk. Pepperell Facility The Pepperell facility is a 40 megawatt gas-fired combined-cycle plant located in Pepperell, Massachusetts. The plant has capacity contracts covering 2002 and sells merchant wholesale energy into the New England ISO. The facility also has a steam sales agreement with the Pepperell Paper Company expiring in December 2002. 13
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, as described below: <TABLE> <CAPTION> Left to Total be Number Total Net Amount Funded of Capacity Capacity Fund Name ($MM) ($MM) Plants (MWs) Interest (MWs) - ------------------------------- --------- ------- -------- ---------- -------- ---------- <S> <C> <C> <C> <C> <C> <C> Energy Investors Fund I $159.5 $0 5 76.0 12.6% 9.6 Energy Investors Fund II $115.0 $0 5 66.6 6.9% 4.6 Project Finance Fund III $101.0 $0 3 136.8 5.3% 7.3 Caribbean Basin $75.0 $60 2 60.3 3.7% 2.2 ----- ---- Total Fund Interests 339.7 23.7 ===== ==== </TABLE> Financing of Our Independent Power Projects. We have financed our principal independent power generation facilities primarily with non-recourse debt that is repaid solely from the project's revenues. This type of financing is referred to as "project financing." These financings generally are secured by the physical assets, major project contracts and agreements, cash accounts and, in certain cases, our ownership interest, in the related project. True project financing is not available for all projects, including some assets purchased out of bankruptcy, some merchant plants and some purchases of minority stock positions in publicly traded companies. Even in those instances, however, we may still be able to finance a smaller portion of the total cost with project financing, with the remainder financed with debt that is either raised or supported at the corporate rather than the project level. Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to pay operating expenses, senior debt service and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service. These project financing structures are designed to prevent the lenders from relying on us or our other projects for repayment; that is, they are "non-recourse" to us and our affiliates not involved in the project, unless we or another affiliate expressly agree to undertake liability. In the event of a foreclosure after a default, our project affiliate owning the facility would only retain an interest in the assets, if any, remaining after all debts and obligations were paid. In addition, the debt of each operating project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge securing the project's debt and to transfer restrictions set forth in the relevant financing agreements. Also, our ability to transfer or sell our interest in certain projects or the project's power is restricted by certain purchase options or rights of first refusal in favor of our partners and certain change of control restrictions in the project financing documents. We may also choose to finance these projects from time to time by other means including using our short-term credit facilities on an interim basis. Fuel Production Coal Our coal production segment mines and processes low-sulfur sub-bituminous coal 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 believe the Wyodak mine is the oldest operating surface coal mine in the nation, with an annual production of approximately 3.5 million tons. 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, 14
respectively, of the selling price on all federal and state coal. As of December 31, 2001, we had coal reserves of 276.6 million tons, enough to satisfy present contracts for approximately 70 years. Substantially all of our coal production is currently sold under long-term contracts to Black Hills Power, Inc., our electric utility, and to PacifiCorp. Our coal segment's agreement with Black Hills Power limits earnings from all coal sales to Black Hills Power to a specified return on our original cost depreciated investment base. Black Hills Power made a commitment to the South Dakota Public Utilities Commission, the Wyoming Public Service Commission and the City of Gillette that coal would be furnished and priced as provided by that agreement for the life of our Neil Simpson II plant. The price for unprocessed coal sold to PacifiCorp for its 80 percent interest in the Wyodak Plant is determined by a coal supply agreement terminating in 2022. This is a new agreement that began January 1, 2001 and was part of a litigation settlement with PacifiCorp. Over the next several years, we expect to increase coal production to supply: o the Wygen 90 megawatt mine-mouth power plant, which is scheduled for completion in 2003; o additional mine mouth generating capacity of up to 500 megawatts at the same site as the Wygen plant, which is in the early stages of development; and o future sales of coal to rail-served customers. In addition, if our coal enhancement K-Fuel plant is re-started, we expect to increase production from the Wyodak mine and market any low-moisture, high-heat content coal we produce to an expanded customer base. Natural Gas and Crude Oil Our oil and gas exploration and production segment operates approximately 385 oil and gas wells, all of which are located in Wyoming, Colorado and Nebraska. The majority of these wells are in the Finn-Shurley Field area, located in Weston and Niobrara Counties in Wyoming. We also own a working interest in, but do not operate, an additional 428 wells located in California, Montana, Louisiana, Colorado, North Dakota, Texas, Wyoming, Oklahoma and offshore in the Gulf of Mexico. In addition, we have accumulated significant acreage in the Rocky Mountain region, which we plan to utilize for oil and gas exploration. We plan to substantially increase our natural gas reserves and minimize exploration risk by focusing on lower-risk exploration and development drilling and acquisitions of proven producing properties. A key component of this strategy is the pursuit of shallow gas opportunities in the Rocky Mountain region. We also expect to modestly increase our Mid-continent area production in the future but do not plan to serve as the operator for those production activities. As of December 31, 2001, we had proved reserves of 4.0 million barrels of oil and 24.1 billion cubic feet of natural gas, with approximately 63 percent of current production consisting of natural gas. In 2001, our oil and gas production increased 38 percent over 2000 levels, with strong drilling results, acquisitions and year-end reserves. In April 2001, we purchased certain operating and non-operating interests in 74 oil and gas wells located primarily in Colorado and Wyoming from Stewart Petroleum Corporation. These properties added to our proved reserves approximately 8.7 billion cubic feet of natural gas and approximately 200,000 barrels of oil. Fuel Marketing. We market natural gas, oil and coal in specific regions of the United States. We offer physical and financial wholesale fuel marketing and price risk management products and services to a variety of customers. These customers include natural gas distribution companies, municipalities, industrial users, oil and gas producers, electric 15
utilities, coal mines, energy marketers and retail gas users. Our average daily marketing volumes for the year ended December 31, 2001, were 1,047,700 million British thermal units of gas, 36,500 barrels of oil and 6,100 tons of coal. The following table briefly summarizes the location of our fuel marketing operations and sales offices: <TABLE> <CAPTION> Marketing Company Fuel Operations Sales Offices - ------------------------------ ----------- ----------- ------------------------------------- <S> <C> <C> <C> Enserco Energy Natural Gas Golden, CO Calgary, Alberta, Canada Black Hills Energy Resources Crude Oil Houston, TX Tulsa, OK; Midland, TX; Longview, TX Black Hills Coal Network Coal Mason, OH St. Clairsville, OH </TABLE> Gas Marketing Our natural gas marketing operations are headquartered in Golden, Colorado, with a satellite office in Calgary, Canada. Our gas marketing operations focus primarily on wholesale marketing and producer marketing services. Producer services include providing for direct purchases of wellhead gas and for risk transfer and hedging products. Our gas marketing efforts are concentrated in the Rocky Mountain and West Coast regions and in Western Canada, which are areas in which we believe we have a competitive advantage due to our knowledge of local markets. We contractually hold natural gas storage capacity and both long and short-term transportation capacity on several major pipelines in the western United States and Canada. We utilize this capacity to move relatively low cost natural gas from the producer regions to more expensive end-use market areas. Oil Marketing and Transportation Our crude oil marketing and transportation operations are headquartered in Houston, Texas and are concentrated primarily in Texas, Oklahoma and Louisiana. At December 31, 2001 we owned a 33 percent interest in Millennium Pipeline Company, L.P., which owns and operates a 200-mile pipeline. In March 2002, we acquired the remaining 67 percent interest in Millennium. The pipeline has a capacity of approximately 65,000 barrels of oil per day, and transports imported crude oil from Beaumont, Texas to Longview, Texas, which is the transfer point to connecting carriers. We also acquired additional ownership interest in Millennium Terminal Company, L.P., which has 1.1 million barrels of crude oil storage connected to the Millennium Pipeline at the Oil Tanking terminal in Beaumont. The Millennium system is presently operating near capacity through shipper agreements. These acquisitions give us 100 percent ownership in the Millennium companies. Coal Marketing We market coal to various industrial customers and power plants located primarily in the Midwest and eastern regions of the United States through our coal marketing subsidiary, Black Hills Coal Network. We formed Black Hills Coal Network in 1998 to acquire the assets and hire the operational management of Coal Network and Coal Niche, based in Mason, Ohio. These predecessor companies were coal brokerage and agency companies with customers located primarily east of the Mississippi River. 16
Electric Utility - Black Hills Power, Inc. Our electric utility, Black Hills Power, is engaged in the generation, transmission and distribution of electricity. It provides a solid foundation of revenues, earnings and cash flow that support utility capital expenditures, dividends, and overall performance and growth. Distribution and Transmission. Our electric utility distribution and transmission businesses serve approximately 59,200 electric customers, with an electric transmission system of 447 miles of high voltage lines and 541 miles of lower voltage lines. In addition, we jointly own 43 miles of high voltage lines with Basin Electric Cooperative. Our utility's service territory covers a 9,300 square mile area of western South Dakota, eastern Wyoming and southeastern Montana with a strong and stable economic base. Over 90 percent of our utility's retail electric revenues are generated in South Dakota. The following are characteristics of our distribution and transmission businesses: o We have a diverse customer and revenue base. Our revenue mix in 2001 is comprised of 22 percent commercial, 17 percent residential, 11 percent industrial, 8 percent long-term contract wholesale, 10 percent short-term contract wholesale, 31 percent wholesale off-system sales and 1 percent municipal. Approximately 65 percent of our large commercial and industrial customers are provided service under long-term contracts. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market and through short-term sales contracts. o In 1999, the South Dakota Public Utilities Commission extended our previous retail rate freeze for another five-years, through January 1, 2005. The rate freeze preserves our 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 from wholesale "off-system" sales, which are not covered by the rate freeze. This provides us with flexibility in allocating our generating capacity to maximize returns in changing market environments. o Forty-one percent of our electric revenues for the year ended December 31, 2001 consisted of off-system and short-term contract wholesale sales compared to 29 percent in 2000 and 8 percent in 1999. Although the demand for power in the western markets has eased from the record levels seen in the first half of 2001, further increases in the volume of off-system sales are expected in the future due to demand growth in the Rocky Mountain region and the early 2002 addition of 40 megawatts of gas-fired generating capacity. o Our system has the capability of connecting to either the eastern or western transmission systems, which provides us with access between the WSCC region and the Mid-Continent Area Power Pool, or "MAPP" region. This allows us the opportunity to improve system reliability and take advantage of power price differentials between the two electric grids. We are able to interconnect up to 80 megawatts of our generation into the MAPP. Alternatively, we can have up to 80 megawatts of our load served from the MAPP region. The available transmission capacity of the MAPP transmission system determines how much of this 80 megawatts can be served from the eastern interconnection. o We have firm transmission access to deliver up to 60 megawatts of power on PacifiCorp's system to wholesale customers in the western region during 2002, scheduled to decline to 50 megawatts by 2004. On October 15, 2000, we indicated to FERC our intent to participate in a regional transmission organization, or RTO. Our transmission system is a part of the western transmission grid governed by the WSCC, and it interconnects with transmission systems operated by the Western Area Power Administration, or WAPA, and by PacifiCorp. WAPA continues to evaluate participation in the RTOs which will involve transmission systems in Colorado and the southwest region, while PacifiCorp is involved in the development of the RTO West which will involve transmission 17
systems in Wyoming and the northwest region. We will continue to monitor the development of these two RTOs and decide in the future which RTO best fits our transmission system and operations. Power Sales Agreements. We sell approximately 50 percent of our utility's current load under long-term contracts. Our key contracts include a 10-year contract expiring in 2007 with Montana-Dakota Utilities Company for the sale of up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming electric service territory, and a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city's first 23 megawatts of capacity and energy. Both contracts are integrated into our control system and are treated as firm native load. In May 2001, we began selling 30 megawatts of firm capacity and energy up to the contract capacity to Public Service Company of Colorado for a period through 2004. We have entered into an agreement with the Municipal Electric Agency of Nebraska for the sale of 30 megawatts of unit contingent energy and capacity for a period through the completion of construction of the Wygen independent power facility, which is expected in first quarter 2003. For the 10-year period beginning with the completion of the Wygen facility, our utility and our power generation segment will each provide 20 megawatts of unit contingent energy and capacity to the Municipal Electric Agency of Nebraska. Our utility's electric load is served by coal-, oil- and natural gas-fired generating units providing 395 megawatts of generation capacity and from the following purchased power and capacity contracts with PacifiCorp: o a power sales agreement expiring in 2023, involving the purchase by us of 60 megawatts of baseload power in 2002, and scheduled to decline to 50 megawatts by 2004; o a reserve capacity integration agreement expiring in 2012, which makes available to us 100 megawatts of reserve capacity in connection with the utilization of the Ben French CT units; and o a capacity option call, which gives us an option to purchase up to 60 megawatts of peaking capacity seasonally through March 31, 2007. Regulated Power Plants. Since 1995, our utility has been a net producer of energy. Our utility owns 395 megawatts of generating capacity with an additional 40 megawatts under construction, all of which is located in the Rocky Mountain region. Our utility's peak system load of 392 megawatts was reached in August 2001. None of our generation is restricted by hours of operation, thereby providing us with the ability to generate power to meet demand whenever necessary and feasible. 18
The following table describes our utility's portfolio of power plants: <TABLE> <CAPTION> Total Net Fuel Capacity Capacity Power Plant Type State (MWs) Interest (MWs) Start Date ----------- ---- ----- ----- -------- ----- ---------- <S> <C> <C> <C> <C> <C> <C> In Operation: ------------ Ben French Coal SD 25.0 100% 25.0 1960 Ben French Diesels 1-5 Diesel SD 10.0 100% 10.0 1965 Ben French CTs 1-4 Gas/Oil SD 100.0 100% 100.0 1977-1979 Neil Simpson I Coal WY 21.8 100% 21.8 1969 Neil Simpson II Coal WY 91.0 100% 91.0 1995 Neil Simpson CT Gas WY 40.0 100% 40.0 2000 Osage Coal WY 34.5 100% 34.5 1948 Wyodak Coal WY 362.0 100% 72.4 1978 ----- ----- Total in Operation 684.3 20% 394.7 ----- ----- Under Construction: ------------------ Lange CT Gas SD 40.0 100% 40.0 2002 ----- ----- Total Utility 724.3 434.7 ===== ===== </TABLE> Ben French Ben French is a wholly owned coal-fired plant situated 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. Coal for the plant is purchased from our Wyodak mine and 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 a capacity of 10 megawatts. These plants were put into service in 1965, and are being operated as peaking plants. Ben French CT's 1-4 The Ben French Combustion Turbines 1-4 are wholly owned gas and oil-fired units with a capacity of 100 megawatts located in Rapid City, South Dakota. These facilities were put into service from 1977 to 1979, and are being operated as peaking units. Neil Simpson I and II Neil Simpson I and II are air-cooled, coal-fired wholly owned facilities located near Gillette, Wyoming. Neil Simpson I has a capacity of 21.8 megawatts and was put into service in 1969. Neil Simpson II has a capacity of 91.0 megawatts and was put into service in 1995. These plants are operated as baseload facilities, and are mine-mouth coal-supplied 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 put into service in 2000, and was installed to provide peaking capabilities. 19
Osage The Osage plant is a wholly owned coal-fired plant in Osage, Wyoming with a total capacity of 34.5 megawatts and was put into service from 1948 to 1952. This plant has three turbine generation units, and is being operated as a baseload plant. Coal for the plant is purchased from our Wyodak mine and delivered by truck. Wyodak Wyodak is a 362 megawatt mine mouth coal-fired plant owned jointly by PacifiCorp and us and in which we hold a 20 percent (72.4 net megawatt) ownership interest. Our Wyodak mine furnishes all the coal fuel supply for the Wyodak plant. The plant was put into service in 1978, and is currently being operated as a baseload plant. Lange CT The Lange Combustion Turbine is a wholly owned 40 megawatt gas-fired plant under construction near Rapid City, South Dakota. The plant is expected to be placed in service early 2002. The Lange Project was originally planned as an independent power plant, but is being constructed by our utility as a regulated power plant to provide peaking capacity and voltage support for the area. Communications Our communications group, whose primary business is Black Hills FiberCom, was formed to provide state-of-the-art broadband telecommunications services to the underserved markets of Rapid City and the northern Black Hills of South Dakota. We offer residential and business customers a full suite of telecommunications services, including local and long distance telephone service, expanded cable television service, cable modem Internet access and high speed data and video services. We have completed a 242-mile inter- and intra-city fiber optic network and currently operate 737 miles of two-way interactive hybrid fiber coaxial or "HFC" cable. We believe we are one of the first companies in the United States to provide video entertainment service, high-speed Internet access, and local and long distance telephone services over an advanced broadband infrastructure. We have bundled these services into value packages with a single consolidated bill for all of these services. We introduced our broadband communications services to the Rapid City and northern Black Hills areas in November 1999. As of December 31, 2001, we had attracted 15,660 residential customers and 2,250 business customers. Our goal is to attain 60 percent residential and commercial market penetration within our service territory. The construction of our communications network is approximately 85 percent complete and we expect to substantially complete construction of the base network in 2002. Competition The independent power, fuel production and fuel 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. In particular, the independent power industry in recent years has been characterized by increased competition for asset purchases and development opportunities. In addition, Congress has considered various pieces of legislation to restructure the electric industry that would require, among other things, customer choice and/or repeal of the Public Utility Holding Company Act of 1935, or PUHCA. The debate is likely to continue and perhaps intensify. The effect of enacting such legislation cannot be predicted with any degree of certainty. Industry deregulation may encourage the disaggregation of vertically integrated utilities into separate generation, transmission and distribution businesses. As a result of these potential regulatory changes, significant additional competitors could become active in the generation segment of our industry. 20
Our communications unit faces competition from numerous well established companies, including Qwest Communications, Rapid City's incumbent local exchange carrier, Midcontinent Communications, the area's incumbent cable television provider, as well as long distance providers and Internet service providers. Our success in this business will depend upon, among other things, the quality of our customer service, the willingness of residential and business customers to accept us as an alternative provider of broadband communications services, our products and services and our ability to offer an attractive package of bundled products. Risk Management Our fuel marketing operations require effective risk management of price, counterparty performance and operational risks. Price risk is created through 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 arises from a lack of internal controls. We have implemented controls to mitigate each of these risks. Our fuel 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. These policies are established and approved by our board of directors, reviewed on a regular basis and monitored as described below. We maintain a working risk management committee for each of our marketing companies, and a credit committee at the parent company level. The risk management committees focus on implementation of risk management procedures and on monitoring compliance with established policies. The credit committee sets counterparty credit limits, monitors credit exposure levels and reviews compliance with established credit policies. Additionally, we employ a risk manager and a credit manager responsible for overseeing these functions. Our risk management policies and procedures specify maximum price risk exposure levels within which each respective marketing company must operate. These policies and procedures establish relatively low exposure levels and generally prohibit speculative trading strategies. As part of our enterprise-wide risk management strategy, we limit our exposure to energy marketing risks by maintaining separate credit facilities within each of our fuel marketing companies. These credit facilities have security interests solely against the assets of the respective marketing company, with the exception of a $1 million guarantee by our coal mining subsidiary on our coal marketing unit's credit facility. A significant 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 control such risks, we restrict wholesale off-system sales to amounts by which our anticipated generation capabilities exceed our anticipated load requirements plus a required reserve margin. We further control this risk by selling only in the day-ahead power market and by entering into longer-term sales contracts that are made on a "unit contingent" basis, under which delivery is not required during unplanned outages at specified power plants. Regulation 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. These laws and regulations generally require that a wide variety of permits and other approvals be obtained before construction or operation of a power plant commences and that, after completion, the facility operate in compliance with their requirements. We strive to comply with the terms of all such laws, regulations, permits and licenses and believe that all of our operating plants are in material compliance with all such applicable requirements. 21
Energy Regulation 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 rate schedules with FERC prior to commencement of wholesale sales or interstate transmission of electricity. Public utilities with cost-based rate schedules are also subject to accounting, record-keeping and reporting requirements administered by FERC. The Energy Policy Act. The passage of the Energy Policy Act in 1992 further encouraged independent power production by providing certain exemptions from regulation for exempt wholesale generators, or EWGs. All of our subsidiaries that would otherwise be treated as public utilities are currently treated as EWGs under the Energy Policy Act. An EWG is an entity that is exclusively engaged, directly or indirectly, in the business of owning or operating facilities that are exclusively engaged in generation and selling electric energy at wholesale. An EWG will not be regulated under PUHCA, but is subject to FERC and state public utility commission regulatory reviews, including rate approval. Since EWGs are only allowed to sell power at wholesale, their rates must receive initial approval from FERC rather than the states. All of our EWGs to date that have sought rate approval from FERC 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 we or any of our EWGs exercised market power. If FERC were to suspend market-based rate authority, it would most likely be necessary to file, and obtain FERC acceptance of, cost-based rate schedules for any of our EWGs. 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. In addition, if there occurs a "material change" in facts 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. If any of our subsidiaries were to lose EWG status, we, along with our affiliates, would be subject to regulation under PUHCA as a public utility company. Absent a substantial restructuring of our business, it would be difficult for us to comply with PUHCA without a material adverse effect on our business. 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. Environmental Regulation The construction and operation of power projects 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. 22
Clean Air Act. Our Neil Simpson II, Neil Simpson CT, Gillette CT, the Arapahoe, Valmont, Fountain Valley, 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 "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 2031 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 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. On July 14, 2000, the South Coast Air Quality Management District, known as SCAQMD, sent a letter to our affiliate, Black Hills Ontario, L.L.C., the operator of a 12 megawatt natural-gas fired co-generation facility located in Ontario, California, stating that the SCAQMD had determined, as a result of a facility audit completed for the compliance year ended June 1, 1999, that the facility's nitrogen oxide, or NOx, emissions were 28,958 pounds over the facility's NOx allocation established by the SCAQMD's RECLAIM emissions trading program. As a result, the SCAQMD indicated that it would be reducing the facility's NOx allocation by the same number of allowances for the compliance year subsequent to a final determination on this issue. Black Hills Ontario provided documentation to the SCAQMD disputing this proposed reduction and by letter on August 14, 2001, the SCAQMD agreed that Ontario had not exceeded its NOx allocation and stated the issue is now resolved. Black Hills Ontario was able to purchase NOx allowances for the 2001-2002 compliance period and projects that it will need to continue purchasing NOx allowances for all future compliance years. Annual purchases are anticipated to be approximately 30,000 allowances. There is currently significant volatility in the price and supply of RECLAIM NOx allowances; although the SCAQMD has proposed a revision to its regulations to stabilize the RECLAIM market, it is unclear whether these rules will mitigate Black Hills Ontario's potential exposure for its projected allowance shortfall. Accordingly, no assurance can be given at this time regarding whether RECLAIM NOx allowances will be available for purchase to allow Black Hills Ontario to comply with RECLAIM requirements for the year ended June 30, 2002, or, if allowances are available, as to the cost of those allowances. 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 approved state plans adopted to combat visibility impairment. The submission of these plans is due between 2004 and 2008. In January 2001, the EPA proposed guidance to assist states in determining which sources should be subject to the BART requirement. That guidance is currently under review by the Whitehouse Office of Management and Budget and is expected to be final in 2002. Management believes that the only existing plant which may be required to comply with Clean Air Act requirements is our Neil Simpson I plant and that any capital expenditures associated with bringing the plant into compliance 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 are in the process of or have submitted Title V permit applications and either have received or are in the process of receiving permits. 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" 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 have 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, and also issued an administrative order to the Tennessee Valley Authority for similar violations at some of its power plants. The EPA has also issued requests for information pursuant to the Clean Air 23
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 new source review requirements. No such proceedings have been initiated or requests for information issued with respect to any of our facilities, but there can be no assurance that we will not be subject to similar proceedings in the future. In December 2000, the EPA announced its intention to regulate mercury emissions from coal-fired and oil-fired electric power plants under Section 112 of the Clean Air Act. The EPA is committed to proposing a rule to regulate such emissions by no later than 2003. Because we do not know what the EPA may require with respect to this issue, we are not able to evaluate the impact of potential 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 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. However, because of opposition to the treaty in the United States Senate, the Kyoto Protocol has not been submitted to the Senate for ratification. 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 the United States ratifies the Kyoto Protocol or we otherwise become subject to limitations on emissions of carbon dioxide from our plants, these requirements could have a significant impact on our operations. In March 2001, the Bush administration announced that it would not seek to impose any limitations on carbon dioxide emissions. Clean Water Act. Our existing facilities are also subject to a variety of state and federal regulations governing existing and potential water/wastewater discharges. 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 in place and are in compliance with discharge limitations. 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 and Neil Simpson II plants are deposited in mined areas. These disposal areas are located below some shallow water aquifers in the mine. None of the solid wastes from the burning of coal is classified as hazardous material, but the wastes do contain minute traces of metals that would be perceived as polluting if such metals were leached into underground water. Recent investigations have concluded that the wastes are relatively insoluble and will not measurably affect the post-mining ground water quality. While management does not believe that any substances from our solid waste disposal activities will pollute underground water, they can give no assurances that pollution will not 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 the federal or state government determines that solid waste from the burning of coal contains some hazardous material that requires special treatment, including solid waste of which we previously disposed. In that event, the government regulator could consequently hold those entities that disposed of such waste responsible for such treatment. 24
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 all of our Wyodak coal mine in conformity with state laws and regulations. We have an approved mining permit and are otherwise in compliance with other land quality permitting programs. Based on extensive reclamation studies, we currently estimate the cost of reclamation for our mine at approximately $26 million and have currently accrued approximately $18.2 million on our accompanying Consolidated Balance Sheet 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 "North Pit" 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, additional 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. Ben French Oil Spill. In 1990 and 1991, we discovered extensive underground fuel oil contamination at the Ben French plant site. With the help of expert consultants, we worked closely with the South Dakota Department of Environment and Natural Resources to assess and remediate the site. Our assessment and remediation efforts continue today and we continue to monitor the site. All of our underground oil-carrying facilities from which the contamination occurred are now above ground. There have been no significant recoveries of free fuel oil product since 1994. Soil borings and monitoring wells on the perimeters of our Ben French plant property provide no indication of contamination beyond the property's limits. Management believes that the underground spill has been sufficiently remedied so as to prevent any oil from migrating off site. However, due to underground gypsum deposits in this area, the fuel oil has the potential of migrating to area waterways. In such event, cleanup costs could be greatly increased. Management believes that sufficient remediation efforts to prevent such a migration are currently in place, but due to the uncertainties of underground geology, no assurance can be given. Cleanup costs recognized to date total approximately $0.5 million, of which amount $0.4 million has been reimbursed by the South Dakota Petroleum Release Compensation Fund. To date, no penalties, claims or actions have been taken or threatened against us because of this oil spill. In late 2001, the South Dakota Department of Environment and Natural Resources started preparing a review, which is directed at permanently closing numerous monitoring wells which have shown no contamination for several years. 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. 25
Exploration and Production Our oil and gas exploration and production operations are subject to various types of regulation at the federal, state and local levels. They include: o requiring permits for the drilling of wells; o maintaining bonding requirements in order to drill or operate wells; o submitting and implementing spill prevention plans; o submitting notification relating to the presence, use and release of certain contaminants incidental to oil and gas operations; o regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities; and o regulating surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. 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, 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. Other Properties In addition to the other properties described herein, we own an eight-story office building consisting of approximately 47,000 square feet of office space in Rapid City, South Dakota. We occupy approximately 75 percent of this building and lease the remainder to others. Employees At December 31, 2001, we had 785 employees, approximately 287 of who are employed in our utility business, 236 of who are employed in our integrated energy businesses, 209 of who are employed in our communications business and 53 of who are employed by the parent company. Approximately one-half of our utility employees are covered by collective bargaining agreements with the International Brotherhood of Electrical Workers, which expire on April 1, 2003. We have experienced no significant labor stoppages or labor disputes at our facilities. 26
ITEM 3. LEGAL PROCEEDINGS There are currently no pending material legal proceedings to which we are a party. There are currently no pending material legal proceedings to which an officer or director is a party or has a material interest adverse to us or our subsidiaries. There are also no material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which we are or would be a party. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders during the fourth quarter of 2001. 27
PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock ($1 par value) is traded on The New York Stock Exchange. Quotations for the common stock are reported under the symbol BKH. At year-end, the Company had 5,509 common shareholders of record and approximately 16,000 beneficial owners. All 50 states and the District of Columbia plus 10 foreign countries are represented. We have declared common stock dividends payable in cash in each year since our predecessor's incorporation in 1941. At our January 2002 meeting, the Board of Directors raised the quarterly dividend to 29 cents per share, equivalent to an annual increase of 4 cents per share. This regular quarterly dividend is payable March 1, 2002. Dividend payment dates are normally March 1, June 1, September 1 and December 1. 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: Year ended December 31, 2001 <TABLE> <CAPTION> 1st 2nd 3rd 4th --- --- ---- --- <S> <C> <C> <C> <C> Dividends paid per share $0.28 $0.28 $0.28 $0.28 Common stock prices High High $45.74 $58.50 $45.55 $34.20 Low $31.00 $39.50 $27.76 $26.00 Year ended December 31, 2000 1st 2nd 3rd 4th --- --- ---- --- Dividends paid per share $0.27 $0.27 $0.27 $0.27 Common stock prices High High $25.19 $25.19 $30.13 $46.06 Low $20.44 $20.88 $22.00 $27.00 </TABLE> 28
ITEM 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> Years ended December 31, 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- <S> <C> <C> <C> <C> <C> TOTAL ASSETS (in thousands) $1,658,767 $1,320,320 $668,492 $559,417 $508,741 PROPERTY AND INVESTMENTS (in thousands) Total property and investments $1,626,519 $1,122,266 $710,488 $619,549 $598,306 Accumulated depreciation and depletion 328,400 277,848 246,299 229,942 197,179 Capital expenditures 594,156 173,517* 154,609 27,225 28,319 CAPITALIZATION (in thousands) Long-term debt $415,798 $307,092 $160,700 $162,030 $163,360 Preferred stock equity 5,549 4,000 - - - Common stock equity 509,615 278,346 216,606 206,666 205,403 -------- -------- -------- -------- -------- Total capitalization $930,962 $589,438 $377,306 $368,696 $368,763 ======== ======== ======== ======== ======== CAPITALIZATION RATIOS Long-term debt 44.7% 52.1% 42.6% 43.9% 44.3% Preferred stock equity 0.6 0.7 - - - Common stock equity 54.7 47.2 57.4 56.1 55.7 ----- ----- ----- ----- ----- Total 100.0% 100.0% 100.0% 100.0% 100.0% ===== ===== ===== ===== ===== TOTAL OPERATING REVENUES (in thousands) $1,558,558 $1,623,836 $791,875 $679,254 $313,662 NET INCOME AVAILABLE FOR COMMON STOCK (in thousands) $87,550 $52,770 $37,067 $25,808** $32,359 DIVIDENDS PAID ON COMMON STOCK (in thousands) $28,517 $23,527 $22,602 $21,737 $20,540 COMMON STOCK DATA (in thousands) Shares outstanding, average 25,374 22,118 21,445 21,623 21,692 Shares outstanding, average diluted 25,771 22,281 21,482 21,665 21,706 Shares outstanding, end of year 26,652 22,921 21,372 21,578 21,705 (in dollars) Basic earnings per average share $ 3.45 $ 2.39 $ 1.73 $ 1.19** $ 1.49 Diluted earnings per average share $ 3.42 $ 2.37 $ 1.73 $ 1.19** $ 1.49 Dividends paid per share $ 1.12 $ 1.08 $ 1.04 $ 1.00 $ 0.95 Book value per share, end of year $ 19.12 $ 12.14 $ 10.14 $ 9.58 $ 9.46 RETURN ON COMMON STOCK EQUITY (year-end) 17.2% 19.0% 17.1% 12.5%** 15.8% </TABLE> *Excludes the non-cash acquisition of Indeck Capital, Inc. **Includes impact of $8.8 million, or 41 cents per average share, write-down of certain oil and gas properties 29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We are a growth oriented, diversified energy holding company operating principally in the United States. Our unregulated and regulated businesses have expanded significantly in recent years. Our integrated energy group, Black Hills Energy, Inc. (formerly Black Hills Energy Ventures, Inc.), produces and markets electric power and fuel. We produce and sell electricity in a number of markets, with a strong emphasis in the western United States. We also produce coal, natural gas and crude oil, primarily in the Rocky Mountain region, and market fuel products nationwide. Our electric utility, Black Hills Power, Inc., serves approximately 59,200 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communications services to residential and business customers in Rapid City and the northern Black Hills region of South Dakota through Black Hills FiberCom, LLC. Business Strategy We are executing a long-term growth strategy by adding and augmenting revenue streams from our diverse integrated energy operations. We have implemented a balanced, integrated and risk-managed approach to fuel production, energy marketing and power generation. Built on the strength of our electric utility, we have enhanced our local operations by providing broadband communications. Our diverse operations help to avoid reliance on any single element to achieve our growth objective. This diversity provides a measure of stability in volatile or cyclical periods. We believe the strength of our low-cost assets and the expertise of our management team together forge sustained opportunity for growth and success. Prospective Information We reaffirm our goal of long-term annual earnings per share growth of 10 percent to 15 percent off a "normalized" 2000 earnings per share base of $2.00, which adjusts for the impact of high energy prices at that time. However, due to the current low price environment in energy markets, near-term results may be lower than our long-term objective. Net income from the integrated energy group exceeded net income derived from our electric utility in 2001. We expect that earnings growth from the integrated energy group over the next few years will be driven primarily by our continued expansion in the power generation and oil and gas production segments. The following key elements are an integral part of our plan to achieve this objective: o grow our power generation segment by developing and acquiring power projects in targeted western markets, and, in particular, by expanding the generation capacity of our existing sites through a strategy known as "brownfield development;" o sell a large percentage of our production from new projects through long-term contracts in order to secure revenue stability at attractive returns; o increase our reserves of natural gas and crude oil and expand our fuel production; o manage the risks inherent in fuel marketing by maintaining position limits that minimize price risk exposure; o conduct business with a diversified group of counterparties of high credit quality; o exploit our fuel cost advantages and our operating and marketing expertise to remain a low-cost power producer; o increase margins from our coal production through an expansion of mine mouth generation and increased coal sales; o build and maintain strong relationships with wholesale energy customers; and o capitalize on our utility's established market presence, relationships and customer loyalty to expand our integrated energy businesses. Although we believe our integrated energy group will continue to grow as our largest business group, we are unable to predict the price environment and growth in the energy markets. Our electric utility has continued to produce modest growth in revenue and earnings from the retail business over the past two years. We believe that this trend is stable and that, absent unplanned system outages, it will continue for the 30
next several years due to the extension of our electric utility's rate freeze until January 1, 2005. (See Rate Regulation.) 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 and electricity demand and commodity prices in the western markets. Although our broadband communications business significantly increased residential and business customers in 2001, we expect it will sustain approximately $6.5 million in net losses in 2002, with annual losses decreasing thereafter and profitability expected by 2004. The recovery of capital investment and future profitability are dependent primarily on our ability to attract new customers, including customers from incumbent providers. Our goal is to attain 60 percent penetration for both residential and commercial customers within our service territory. If we are unable to attract additional customers or technological advances make our network obsolete, we could have a material write-down of assets. While we do not anticipate being regulated in the local markets, we are unable to predict future markets, future government impositions and future economic and competitive conditions that could affect the profitability of the communications operations. Results of Operations Consolidated Results Overview Revenue and net income (loss) provided by each business group as a percentage of our total revenue and net income were as follows: 2001 2000 1999 ---- ---- ---- Revenue: Integrated energy 85% 89% 83% Electric utility 14 11 17 Communications 1 - - --- --- --- 100% 100% 100% === === === Net Income (Loss): Integrated energy 63% 55% 31% Electric utility 51 70 74 Communications (14) (25) (5) --- --- --- 100% 100% 100% === === === 2001 Compared to 2000 Consolidated net income for 2001 was $87.6 million, compared to $52.8 million in 2000, or $3.42 per average common share in 2001, compared to $2.37 per average common share in 2000. This equates to a 17.2 percent and 19.0 percent return on year-end common equity in 2001 and 2000, respectively. The return on year-end common equity in 2001 was diluted due to the net proceeds of $163 million from the public stock offering in 2001. We reported record earnings in 2001, primarily due to strong natural gas marketing activity, increased fuel production, expanded power generation and increased wholesale off-system electric utility sales. Strong results in our integrated energy business group and electric utility business group were partially offset by losses in our communications business. Unusual energy market conditions stemming primarily from gas and electricity shortages in the West contributed to our strong financial performance in 2001 and 2000. There was approximately a $1.40 and a $0.40 31
contribution to 2001 and 2000 earnings per share, respectively, due to prevailing prices of gas and electricity and unusually wide gas trading margins in the last part of year 2000 and first half of 2001. Consolidated revenues were slightly lower in 2001 at $1.56 billion compared to $1.62 billion in 2000. Revenue increases in fuel production, independent power generation, the electric utility and communications were offset by a decrease in fuel marketing revenue. The effects of decreases in energy prices beginning in late spring 2001 were partially offset by higher sales volumes. Daily volumes of natural gas marketed increased 22 percent from 860,800 million British thermal units per day in 2000 to 1,047,700 million British thermal units in 2001. Prices of financial and physical natural gas marketed decreased from an average of $2.77 per million British thermal units in 2000 to $2.14 per million British thermal units in 2001. Earnings in 2001 included a $4.4 million after-tax charge ($0.17 per share) for a financial exposure to Enron Corporation and certain of its subsidiaries now in bankruptcy. The exposure is primarily related to the value of a long-term swap to provide natural gas to a power plant. We have taken action to mitigate this exposure. By negotiations or by appropriate legal action filed in U.S. Bankruptcy Court, Southern District of New York, we will seek authority to "net," or offset, certain obligations with Enron and its subsidiaries, both payable and receivable, among our subsidiaries. If we are successful in these efforts, substantially all of the financial value of the fuel swap could be recovered, and we would not have any remaining exposure to Enron and its bankrupt subsidiaries. Earnings in 2001 also reflect a $0.12 per share charge for employee stock bonus awards and the funding of a new non-profit foundation to advance our charitable and philanthropic endeavors. Both of these transactions were funded with Black Hills Corporation common stock. 2000 Compared to 1999 Consolidated net income for 2000 was $52.8 million, compared to $37.1 million in 1999, or $2.37 per average common share in 2000, compared to $1.73 per average common share in 1999. This equates to a 19.0 percent and 17.1 percent return on year-end common equity in 2000 and 1999, respectively. Earnings growth in 2000 was primarily due to strong natural gas marketing activity, increased fuel production, expanded power generation and increased wholesale off-system electric utility sales. Strong results in our integrated energy business group were partially offset by losses in our communications business. Unusual energy market conditions stemming primarily from gas and electricity shortages in the West during the last part of 2000 contributed to our strong financial performance. There was approximately a $0.40 contribution to 2000 earnings per share due to higher prevailing prices of gas and electricity and unusually wide gas trading margins. Consolidated revenues more than doubled in 2000 to $1.6 billion compared to 1999. The growth in revenues in 2000 was a result of high energy commodity prices and increased volumes of fuel marketed, primarily as a result of extreme price volatility in the western markets, acquisitions and growth in the integrated energy business group and increases in off-system sales by our electric utility. Prices of financial and physical natural gas marketed increased from an average of $1.38 per million British thermal units in 1999 to $2.77 per million British thermal units in 2000. The following business group and segment information does not include intercompany eliminations. 32
Integrated Energy Group 2001 2000 1999 ---- ---- ---- (in thousands) Revenue: Fuel marketing $1,185,049 $1,366,970 $614,228 Power generation 94,294 39,660 - Oil and gas 33,408 20,328 13,052 Coal mining 31,800 30,530 31,095 ---------- ---------- -------- Total revenue 1,344,551 1,457,488 658,375 Expenses 1,245,109 1,398,461 645,123 ---------- ---------- -------- Operating income $ 99,442 $ 59,027 $ 13,252 ========== ========== ======== Net income $ 56,246 $ 28,213 $ 11,588 ========== ========== ======== EBITDA $ 137,715 $ 63,389 $ 23,807 ========== ========== ======== EBITDA represents earnings before interest, income taxes, depreciation and amortization. EBITDA is used by management and some investors as an indicator of a company's historical ability to service debt. Management believes that an increase in EBITDA is an indicator of improved ability to service existing debt, to sustain potential future increases in debt and to satisfy capital requirements. However, EBITDA is not intended to represent cash flows for the period, nor has it been presented as an alternative to either operating income, or as an indicator of operating performance or cash flows from operating, investing and financing activities, as determined by generally accepted accounting principles. EBITDA as presented may not necessarily be comparable to other similarly titled measures of other companies. The following is a summary of sales volumes of our coal, oil and natural gas production and various measures of power generation: 2001 2000 1999 ---- ---- ---- Tons of coal sold 3,518,000 3,050,000 3,180,000 Barrels of oil sold 445,500 334,000 318,000 Mcf of natural gas sold 4,619,500 3,274,000 2,791,000 Mcf equivalent sales 7,292,500 5,278,000 4,698,000 MWs of independent power capacity in service 617 250 - MWs of independent power capacity under construction 364 470 - The following is a summary of average daily fuel marketing volumes: 2001 2000 1999 ---- ---- ---- Natural gas - MMBtus 1,047,700 860,800 635,500 Crude oil - barrels 36,500 44,300 19,270 Coal - tons 6,100 4,400 4,500 2001 Compared to 2000 Net income of our integrated energy group nearly doubled in 2001 compared to 2000. These strong earnings resulted primarily from the unusually high prices of natural gas and high gas trading margins received in western markets during the first half of 2001, an increase in volumes marketed and fuel production, and expanded power generation. 33
In addition, in 2001, we reached a settlement of ongoing litigation with PacifiCorp concerning rights and obligations under a coal supply agreement under which PacifiCorp purchased coal from our coal mine to meet the coal requirements of the Wyodak Power Plant. As a result of this settlement, we recognized $5.6 million pre-tax non-operating income. In addition, we sold the "North Conveyor System" which resulted in a $2.6 million pre-tax gain. See Note 10 of Notes to Consolidated Financial Statements. The integrated energy business group's revenues decreased 8 percent in 2001 compared to 2000. A full year of independent power operations revenues related to the July 2000 acquisition of Indeck Capital and an increase in fuel production revenue was offset by decreased gas marketing revenue. Although daily volumes of natural gas marketed increased 22 percent, gas marketing revenues declined due to a decrease in prices of financial and physical natural gas marketed from an average of $2.77 per million British thermal units in 2000 to $2.14 per million British thermal units in 2001. The integrated energy business group's total operating expenses decreased 11 percent due to a decrease in the cost of sales related to lower commodity prices. EBITDA and operating income increased over 117 percent and 68 percent, respectively from 2000 levels due to the decline in operating expenses and higher production volumes. 2000 Compared to 1999 Net income of our integrated energy group increased 144 percent in 2000 compared to 1999. Operating expenses, operating income and EDITDA increased over 117 percent, 345 percent and 166 percent, respectively. These increases resulted primarily from our gas marketing operations--which experienced a dramatic increase in both trading volumes and margins, a significant increase in fuel production volumes, record fuel and power prices and expanded power generation, including the acquisition of Indeck Capital. The integrated energy business group's revenues increased 121 percent in 2000 compared to 1999. The revenue increase was a direct result of gas and electricity shortages in the West Coast markets and the closing of the Indeck Capital acquisition. Daily volumes of natural gas marketed increased 35 percent. Fuel Marketing Our fuel marketing companies produced the following results: 2001 2000 1999 ---- ---- ---- (in thousands) Revenue $1,185,049 $1,366,970 $614,228 Operating income (loss) 54,071 23,774 (2,248) Net income (loss) 35,058 14,009 (185) EBITDA 55,414 23,977 2,995 Our fuel marketing companies generate large amounts of revenue and corresponding expense related to buying and selling energy commodities. Fuel marketing is extremely competitive, and margins are typically very small. 2001 Compared to 2000 Earnings from the fuel marketing segment increased $21.1 million due substantially to high gas margins received in the first half of 2001, as well as a 22 percent increase in natural gas average daily volumes marketed in 2001 compared to 2000. Revenues decreased 13 percent from 2000 as a decline in margins in the last half of 2001 more than offset higher daily volumes. The unusual energy market conditions stemming primarily from natural gas and electricity shortages in California and our ability to capture the higher margins contributed significantly to the strong financial performance. 34
2000 Compared to 1999 The strong increase in earnings in 2000 compared to 1999 was due to the unusual energy market conditions that existed in the last half of 2000 stemming from the natural gas and electricity shortages in California. Average daily volumes of natural gas marketed increased 35 percent in 2000 compared to 1999. Power Generation Our power generation segment produced the following results: 2001 2000 1999 ---- ---- ---- (in thousands) Revenue $94,294 $39,660 $ - Operating income (loss) 27,455 20,374 (157) Net income (loss) 1,576 3,241 (109) EBITDA 44,363 17,630 (157) 2001 Compared to 2000 2001 reflects the first full year of operations of our power generation segment and our continued expansion of generation facilities. We now own 617 net megawatts in currently operating plants. Of these 617 net megawatts, approximately 90 percent are under contracts or tolling arrangements with at least one year remaining. An additional 364 megawatts of generating capacity is currently under construction. Substantially all of this output will be sold pursuant to existing long-term contracts. The increased production capacity was offset by a $4.4 million after-tax charge for Enron exposure, reserves for exposure to western power markets and reduced water flow at hydro power plants in New York. 2000 Compared to 1999 Results from the power generation segment were not significant in 1999. In July 2000, we completed the acquisition of Indeck Capital, representing a significant advancement of our position in the power generation segment. At December 31, 2000 we owned 250 net megawatts of generation in operating plants and had 470 megawatts of generating capacity under construction. Oil and Gas Oil and gas operating results were as follows: 2001 2000 1999 ---- ---- ---- (in thousands) Revenue $33,408 $20,328 $13,052 Operating income 15,193 7,906 3,978 Net income 10,197 4,992 2,462 EBITDA 23,033 12,005 6,392 The following is a summary of our oil and gas reserves at December 31: 2001 2000 1999 ---- ---- ---- Barrels of oil (in thousands) 4,055 4,413 4,109 Mcf of natural gas 24,071 18,404 19,460 Total in Mcf equivalents 48,401 44,882 44,114 35
These reserves are based on reports prepared by Ralph E. Davis Associates, Inc., an independent consulting and engineering firm. Reserves were determined using constant product prices at the end of the respective years. Estimates of economically recoverable reserves and future net revenues are based on a number of variables, which may differ from actual results. We intend to increase our net proved reserves by selectively increasing our oil and gas exploration and development activities and by acquiring producing properties. 2001 Compared to 2000 Record net income in 2001 was primarily a result of a 27 percent increase in the average price received and a 38 percent increase in production volumes. The increase in gas reserves at December 31, 2001 was due to strong drilling results and reserve acquisitions. In 2001, we acquired the operating and non-operating interests in 74 gas and oil wells located in Colorado and Wyoming from Stewart Petroleum Corporation of Denver, Colorado, for approximately $10 million. The acquired interest in these fuel assets represents approximately 10 billion cubic feet equivalent of natural gas. The acquisition increased our proved reserves by approximately 22 percent (based on year-end 2000 reserve estimates) and our current production rates by 10 percent. 2000 Compared to 1999 The increase in net income in 2000 was primarily the result of record natural gas prices, higher crude oil prices, and a significant increase in production volumes. The increase in economically recoverable oil reserves at December 31, 2000 was due to improved product prices. Coal Mining Coal mining results were as follows: 2001 2000 1999 ---- ---- ---- (in thousands) Revenue $31,800 $30,530 $31,095 Operating income 6,586 8,794 12,606 Net income 11,591 7,173 9,715 EBITDA 18,468 11,361 14,965 2001 Compared to 2000 Coal mining earnings increased $4.4 million as a result of a coal contract settlement, a gain on the sale of mining equipment and a 15 percent increase in tons sold, partially offset by lower average coal prices due to a coal contract settlement and an increase in mining related expenses. Tons of coal sold increased primarily due to the commencement of sales through our train load-out facility. In 2001, we reached a settlement of ongoing litigation with PacifiCorp concerning rights and obligations under a coal supply agreement under which PacifiCorp purchased coal from our coal mine to meet the coal requirements of the Wyodak Power Plant. As a result of this settlement, we recognized $5.6 million pre-tax non-operating income. In addition, we sold the "North Conveyor System" which resulted in a $2.6 million pre-tax gain. See Note 10 of Notes to Consolidated Financial Statements. 2000 Compared to 1999 A planned five-week outage at the Wyodak Plant resulted in lower coal sales and earnings in 2000 compared to 1999. 36
Electric Utility Group 2001 2000 1999 ---- ---- ---- (in thousands) Revenue $212,355 $173,308 $133,222 Operating expenses 128,247 105,100 80,936 -------- -------- -------- Operating income $ 84,108 $ 68,208 $ 52,286 ======== ======== ======== Net income $ 45,238 $ 37,100 $ 27,362 ======== ======== ======== EBITDA $ 96,189 $ 83,367 $ 67,804 ======== ======== ======== We currently have a winter peak of 344 megawatts established in December 1998 and a summer peak of 392 megawatts established in August 2001. We own 395 megawatts of electric utility generating capacity and purchase an additional 65 megawatts under a long-term agreement (decreasing to 60 megawatts in 2002). An additional 40 megawatts of generating capacity is currently under construction. 2001 Compared to 2000 Electric revenue increased 23 percent in 2001 compared to 2000. The increase in electric revenue in 2001 was primarily due to a 78 percent increase in wholesale off-system sales at an average price that was 27 percent higher than the average price in 2000. The increase in off-system sales was driven by high spot market prices for energy in early 2001, which enabled us to generate more energy from our combustion turbine facilities, including the Neil Simpson combustion turbine, which we placed into commercial operation in June 2000. Megawatt-hours generated from our oil-fired diesel and natural gas-fired combustion turbines were 440,368 in 2001, compared to 305,767 in 2000. Historically, market prices were not sufficient to support the economics of generating from these facilities, except to meet peak demand and as standby use for native load requirements. Firm kilowatt-hour sales increased 2 percent in 2001. Residential and commercial sales increases of 3 percent in 2001 were partially offset by a slight decrease in industrial sales, primarily due to load reductions at Homestake Gold Mine. Degree days, a measure of weather trends, were 3 percent below normal in 2001 and 4 percent below 2000. Revenue per kilowatt-hour sold was 7.0 cents in 2001 compared to 6.4 cents in 2000. The number of customers in the service area increased to 59,237 from 58,601 in 2000. The increase in the revenue per kilowatt-hour sold in 2001 is due to a 41 percent increase in wholesale off-system sales to 965,030 megawatt-hours and strong average wholesale power prices. Electric utility operating expenses increased 22 percent in 2001 primarily due to a 29 percent increase in purchased power costs and a 14 percent increase in the average cost of generation. The increase in the average cost of generation was primarily associated with the operation of certain gas-fired combustion turbines. In addition, 2001 results include a $2.0 million after-tax non-cash charge related to the contribution of Black Hills Corporation Common Stock to the newly formed Black Hills Corporation Foundation. This Foundation was created to enhance our longstanding practice of giving back to our communities. Through the Foundation, we may strengthen our service to our valued customers and fellow citizens for generations to come. 2000 Compared to 1999 Electric revenue increased 30 percent in 2000 compared to 1999. The increase in electric revenue in 2000 was primarily due to a 381 percent increase in wholesale off-system sales at an average price that was 3 times higher than the average price in 1999. The increase in off-system sales was driven by high spot market prices for energy in late 2000, which enabled us to generate more energy from our combustion turbine facilities, including the Neil Simpson combustion turbine, which we placed into commercial operation in June 2000. Megawatt-hours generated from our oil-fired diesel and natural gas-fired combustion turbines were 305,767 in 2000 compared to 25,882 in 1999. 37
Firm kilowatt-hour sales increased 3 percent. Residential and commercial sales increases of 4 percent were partially offset by a 2 percent decrease in industrial sales, primarily due to load reductions at Homestake Gold Mine. Degree days, a measure of weather trends, were 16 percent above 1999 and 1 percent above normal. Revenue per kilowatt-hour sold was 6.4 cents in 2000 compared to 5.4 cents in 1999. The number of customers in the service area increased to 58,601 in 2000 from 57,709 in 1999. The increase in the revenue per kilowatt-hour sold in 2000 is due to a 54 percent increase in wholesale off-system sales to 684,378 megawatt-hours and robust wholesale power prices. Electric utility operating expenses increased by 30 percent in 2000 primarily due to increased fuel, purchased power, and operating and maintenance expenses, partially offset by lower depreciation. Fuel expense in 2000 included the cost associated with the additional combustion turbine generation. Communications Group 2001 2000 1999 ---- ---- ---- (in thousands) Revenue - external* $ 20,258 $ 7,689 $ 278 Revenue - intersegment* 4,250 3,682 3,145 Operating expenses 37,758 23,857 7,070 --------- -------- ------- Operating loss $(13,250) $(12,486) $(3,647) ======== ======== ======= Net loss $(12,300) $(11,382) $ (968) ======== ======== ======= EBITDA $ (3,142) $ (6,484) $(1,659) ========= ======== ======= - --------------------------- *External revenue is revenue from our broadband communications business. Intersegment revenue is primarily revenue from our information services company derived from providing services to our other business segments. This intersegment revenue and associated expenses are eliminated in the consolidation process. 2001 2000 1999 ---- ---- ---- Residential customers 15,660 8,368 143 Business customers 2,250 646 110 Fiber optic backbone miles 242 210 200 Hybrid fiber coaxial cable miles 737 588 100 In September 1998, we formed our broadband communications business to provide facilities-based communications services for Rapid City and the northern Black Hills of South Dakota. We have invested approximately $125 million in state-of-the-art technology that offers local and long distance telephone service, expanded cable television service, Internet access, and high-speed data and video services. We began serving communications customers in late 1999 and market our services to schools, hospitals, cities, economic development groups, and business and residential customers. The build-out is approximately 85 percent complete at December 31, 2001. Losses are expected to continue as we proceed with building the network and increasing the customer base. We expect our communications group will sustain approximately $6.5 million in net losses in 2002, with annual losses decreasing thereafter and profitability expected by 2004. The recovery of capital investment and future profitability are dependent primarily on our ability to attract new customers. If we are unable to attract additional customers or technological advances make our network obsolete, we could have a material write-down of assets. 2001 Compared to 2000 Our customer base nearly doubled in 2001 to 15,660 residential customers and 2,250 business customers. The increase in revenues from a larger customer base in 2001 was partially offset by increases in reserves for inventory and carrier billings and increased interest expense. Operating expense increased due to the expansion of the business. Operating performance in 2001 was in line with our expectations. 38
2000 Compared to 1999 Operating losses in 2000 were attributable to increased interest, depreciation and operating expenses. Operating losses in 1999 were primarily due to start-up organizational costs, increased depreciation expense and increased interest expense associated with the capital deployment. Critical Accounting Policies We prepare the consolidated financial statements in conformity with accounting principles generally accepted in the United States. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. The significant accounting policies which we believe are the most critical in understanding and evaluating our reported financial results include the following: Valuation of Long-Lived Assets We periodically review the carrying value of our long-lived assets, including goodwill and other intangibles, for continued appropriateness. This review is based upon our projections of anticipated future cash flows. If the anticipated future cash flows are less than our carrying value, then a permanent non-cash write-down is required to be charged to earnings. Although we believe our estimates of future cash flows are reasonable, different assumptions regarding such cash flows could materially affect our evaluations. Full Cost Method of Accounting for Oil and Gas Activities We account for our oil and gas activities under the full cost method whereby all productive and nonproductive costs related to acquisition, exploration and development drilling activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. Net capitalized costs are subject to a "ceilings test" that limits such costs to the aggregate of the present value of future net revenues of proved reserves and the lower of cost or fair value of unproved properties. This method values the reserves based upon actual oil and gas prices at the end of each reporting period adjusted for contracted price changes. If the net capitalized costs exceed the full-cost ceiling, then a permanent non-cash write-down is required to be charged to earnings in that reporting period. Although our net capitalized costs were less than the full cost ceiling at December 31, 2001, we can make no assurances that a write-down in the future will not occur depending on oil and gas prices at that point in time. In addition, we rely on an independent consulting and engineering firm to determine the amount of our proved reserves based on a number of assumptions about variables. We can make no assurances that these assumptions will not differ from actual results. Fair Value of Derivative Instruments Derivative instruments used in our trading activities are recorded at fair value, and realized and unrealized gains and losses are recorded as a component of income. Fair values are based on listed market prices, where possible. If listed market prices are not available, fair value is determined based on other relevant factors. Fair values for certain derivative contracts are derived from pricing models that consider current market and contractual prices for the underlying financial instruments or commodities, as well as time value and yield curve or volatility factors underlying the positions. Pricing models and their underlying assumptions impact the amount and timing of unrealized gains and losses recognized, and the use of different pricing models or assumptions could produce different financial results. Changes in the commodity markets will impact our estimates of fair value in the future. To the extent financial contracts have extended maturity dates, our estimates of fair value may involve greater subjectivity due to the lack of transparent market data available upon which to base modeling assumptions. 39
Counterparty Credit Risk We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer's current creditworthiness, as determined by our review of their current credit information. We continuously monitor collections and payments from our customers and maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot guarantee that we will continue to experience the same credit loss rates that we have in the past or that an investment grade counterparty will not default as was the case with Enron in 2001. We accrued for a $4.4 million after-tax loss in 2001 in regards to the Enron bankruptcy, which was outside our original provision. In addition, in 2001 we accrued approximately $1.0 million after-tax loss for payments owed by Southern California Edison, however this payment was collected in the first quarter of 2002. Pension and Other Postretirement Plans The determination of our obligation and expense for pension and other postretirement benefits is dependent on the use of certain assumptions by actuaries in calculating the amounts. Those assumptions are described in Note 11 of our Notes to Consolidated Financial Statements and include, among others, the discount rate, the expected long-term rate of return on assets and the rate of increase in compensation levels and healthcare benefits. In accordance with generally accepted accounting principles, actual results that differ from our assumptions are accumulated and amortized over future periods and therefore, generally affect our recognized expense and recorded obligation in future periods. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense. Liquidity and Capital Resources Cash Flow Activities 2001 In 2001, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay long-term debt maturities and to fund a material amount of our property additions. We continue to fund property and investment additions primarily related to construction of additional electric generation facilities for our integrated energy business group through a combination of operating cash flow, increased short-term debt and long-term non-recourse project financing. Cash flows from operations increased $107 million, primarily due to increased net income, depreciation, deferred taxes and decreased working capital. In the second quarter of 2001, we issued 3.4 million shares of common stock through an underwritten public offering at $52 per share. Total net proceeds of approximately $163 million were used to repay a portion of current indebtedness under revolving credit facilities, to fund various power plant construction projects and for general corporate purposes. Also, in the second quarter of 2001 we acquired the Fountain Valley facility, a 240 megawatt generation facility located near Colorado Springs, Colorado, featuring six LM-6000 simple-cycle, gas-fired turbines from Enron Corporation. The facility became operational in the third quarter of 2001. Total project cost was approximately $183 million that we financed primarily with non-recourse debt. We have an 11-year contract with Public Service Company of Colorado to utilize the facility for peaking purposes under a tolling arrangement in which we assume no fuel risk. In the third quarter of 2001, we purchased a 277 megawatt gas-fired co-generation power plant project located in North Las Vegas, Nevada from Enron North America, a wholly owned subsidiary of Enron Corporation. The facility currently has a 53 megawatt co-generation power plant in operation of which we own 50 percent. Although we only 40
own 50 percent of this power plant, under generally accepted accounting principles we are required to consolidate 100 percent of this plant. Most of the power from the 53 megawatt facility is sold under a long-term contract expiring in 2024. In addition, the project also has a 224 megawatt combined-cycle expansion under construction, of which we own 100 percent. The facility is scheduled to be fully operational in third quarter 2002 and will utilize LM-6000 technology. The power to be generated by the expansion project is also under a long-term sales contract that expires in 2017. Total cost of the project is estimated to be approximately $330 million of which $240 million was expended and financed with short-term borrowings at December 31, 2001. We plan on financing the transaction primarily with non-recourse project level debt in 2002. In addition, during the third quarter of 2001, we completed a $400 million revolving credit facility, which replaced our previous short-term credit lines, which totaled $290 million. 2000 In 2000, we generated sufficient cash flow from operations to meet our operating needs, to pay common and preferred dividends and to pay long-term debt maturities. We funded property additions primarily related to construction of additional electric generation facilities for our integrated energy business group through a combination of operating cash flow, increased short-term debt and long-term non-recourse project financing. Investing and financing activities increased primarily as a result of the acquisition of Indeck Capital in July 2000 and construction of several generating facilities. Cash flows from operations decreased $2.9 million, primarily due to increased working capital partially offset by increased net income and depreciation. We expect increased operating cash flows resulting from our investing activities to support the additional indebtedness. As part of our acquisition of Indeck Capital, we incurred $40.3 million of additional debt through an increase in borrowings on our short-term credit facilities, which were used to repay certain obligations of Indeck Capital. In addition, we issued 1.537 million shares of common stock and 4,000 shares of convertible preferred stock to the former Indeck Capital shareholders. Dividends Dividends paid on our common stock totaled $1.12 per share in 2001. This reflected increases approved by our board of directors from $1.08 per share in 2000 and $1.04 per share in 1999. All dividends were paid out of current earnings. Our three-year annual dividend growth was 3.8 percent. In January 2002, our board of directors increased the quarterly dividend 3.6 percent to 29 cents per share. If this dividend is maintained during 2002, it will be equivalent to $1.16 per share, an annual increase of 4 cents 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 and our future business prospects. Short-Term Liquidity and Financing Transactions Our principal sources of short-term liquidity are our revolving bank facilities and cash provided by operations. As of December 31, 2001 we had available a $200 million 364-day facility and a $200 million three-year facility both dated August 28, 2001. In addition, on January 4, 2002, we entered into a $50.0 million bridge credit agreement that expires June 30, 2002. These bank facilities can be used to fund our working capital needs, for general corporate purposes and to provide liquidity for a commercial paper program if implemented. At December 31, 2001, we had $360 million of bank borrowings outstanding under these facilities. The corresponding amount outstanding at February 28, 2002 was $384 million. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $7.0 million and $32.0 million at December 31, 2001 and February 28, 2002, respectively. The above bank facilities include covenants that are common in such arrangements. Such covenants include a consolidated net worth in an amount of not less than the sum of $375 million and 50 percent of the aggregate consolidated net income beginning June 30, 2001; a recourse leverage ratio not to exceed 0.65 to 1.00; an interest 41
coverage ratio of not less than 3.00 to 1.00; and a credit rating of at least "BBB-" from Standard & Poor's or "Baa3" from Moody's Investor Service. If these covenants are violated, it would be considered an event of default and the lender has the right to terminate the remaining commitment and accelerate the principal and interest outstanding to become immediately due. In addition, certain of our interest rate swap agreements with a $150 million notional amount at December 31, 2001 include cross-default provisions. These provisions would allow the counterparty the right to terminate the swap agreement and liquidate at a prevailing market rate, in the event of default. In addition, Enserco Energy, Inc., our gas marketing unit, has a $75.0 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. The line of credit is secured by all of Enserco's assets. We provide no other guarantees to the lender under this facility. At December 31, 2001 and 2000, there were outstanding letters of credit issued under the facility of $36.2 million and $69.8 million, respectively, with no borrowing balances on the facility. Similarly, Black Hills Energy Resources, Inc., our oil marketing unit, has a $25.0 million uncommitted, discretionary credit facility secured by all of its assets. We provide no other guarantees to the lender under this facility. This line of credit provides credit support for the purchases of crude oil by Black Hills Energy Resources. At December 31, 2001 and 2000, Black Hills Energy Resources had letters of credit outstanding of $4.4 million and $8.5 million, respectively, and no balance outstanding on its overdraft line. Based upon our expected cash flows from operations, expected project financings for the year, credit facility capacity, and projected cash needs in the near term, we do not expect any liquidity issues in the foreseeable future. On March 15, 2002, we closed on $135 million of senior secured financing for our Arapahoe and Valmont Facilities, 210 megawatts of gas-fired generation located in the Denver, Colorado area. Proceeds from this financing were used to refinance $53.8 million of an existing seven-year senior secured term facility, pay down approximately $50.0 million of short-term credit facility borrowings and approximately $31.0 million will be used for future project construction costs. In addition, we plan on seeking long-term project-level non-recourse financing for the Las Vegas Project, a 277 megawatt gas-fired generation complex located in North Las Vegas, Nevada during 2002. Total project costs are estimated to be $330 million of which approximately $240 million was expended as of December 31, 2001 and was funded with short-term credit facility borrowings. Our consolidated net worth was $515 million at December 31, 2001. The long-term debt component of our capital structure at December 31, 2001 and 2000 was 45 percent and 52 percent, respectively. Our total debt leverage (long-term debt and short-term debt) was 61 percent and 65 percent at December 31, 2001 and 2000, respectively. 42
The following information is provided to summarize cash obligations and commercial commitments. As shown in the table, we have $35.9 million of long-term debt maturing in 2002. <TABLE> <CAPTION> Payments Due by Period ------------------------------------------------------------------------------------------ (in thousands) Contractual Less 1-3 4-5 After 5 Obligations Total Than 1 Year Years Years Years ----------- ----- ----------- ----- ----- ----- <S> <C> <C> <C> <C> <C> Notes payable $ 361,240 $361,240 $ - $ - $ - First mortgage bonds 130,316 18,018 6,978 3,910 101,410 Project financing debt (a) 293,016 17,839 63,101 153,611 58,465 Other long-term debt 28,370 47 187 175 27,961 Unconditional purchase obligations (b) 232,081 25,815 36,656 32,159 137,451 Other long-term obligations (c) 149,255 - 11,324 12,942 124,989 ---------- -------- -------- -------- -------- Total contractual cash obligations $1,194,278 $422,959 $118,246 $202,797 $450,276 ========== ======== ======== ======== ======== </TABLE> (a) Approximately 74 percent of the floating rate term loans has been hedged with an interest rate swap moving the floating rates to fixed rates. See - "Financing Activities under Market Risk Disclosures." (b) Unconditional purchase obligations include the capacity costs associated with a purchase power agreement with PacifiCorp and certain coal purchase, gas purchase, and gas transportation agreements. The energy charge under the purchase power agreement and the commodity price under the gas purchase contract are variable costs which for purposes of estimating our future obligations, were calculated using existing prices at December 31, 2001. (c) Black Hills Generation, a subsidiary in our power generation segment, has entered into agreements with Wygen Funding, Limited Partnership to lease the Wygen Plant, a 90 megawatt coal-fired power plant under construction in Campbell County, Wyoming. Wygen Funding is a special purpose entity that owns the Wygen Plant and has financed the project. Total cost of the project is estimated to be $130 - $140 million. Neither Wygen Funding, its owners, nor its officers are related to us, and other than the lease transaction and obligations incurred as a result of the transaction, we have no obligation to provide additional funding or issue securities to Wygen Funding. Lease payments are based on final construction and financing costs and are currently estimated to be approximately $6.5 million per year based on five-year treasury rates. Lease payments will begin after substantial completion of construction scheduled to occur in the first quarter of 2003. The lease will be accounted for as an operating lease. The initial lease term is five years with two five-year renewal options and includes a purchase option equal to the adjusted acquisition cost. The adjusted acquisition cost is essentially equal to the cost of the project. If Black Hills Generation elects to terminate and not renew the lease and not purchase the project, then it must make a termination payment equal to the lesser of 83.5 percent of the adjusted acquisition cost or the shortfall proceeds received from the sale of the project. Black Hills Corporation has guaranteed the agreements. <TABLE> <CAPTION> Amount of Commitment Expiration Per Period -------------------------------------------------------------------------------------- (in thousands) Other Total Commercial Amounts Less 1-3 4-5 After 5 Commitments Committed Than 1 Year Years Years Years ----------- --------- ----------- ----- ----- ----- <S> <C> <C> <C> <C> <C> Letters of credit $74,300 $73,400 $900 $ - $ - Reclamation liability (a) 18,161 - - - 18,161 ------- ------- ---- ----- ------- Total commercial commitments $92,461 $73,400 $900 $ - $18,161 ======= ======= ==== ===== ======= </TABLE> 43
(a) Under our coal mining permit, we are required to reclaim all land where we have mined coal reserves. The cost of reclaiming the land is accrued as the coal is mined. While the reclamation process takes place on a continual basis, much of the reclamation occurs over an extended period after we mine the area. Approximately $0.7 million is charged to operations as reclamation expense annually. As of December 31, 2001, accrued reclamation costs were approximately $18.2 million. Credit Ratings As of February 28, 2002, our corporate credit rating is "A3" by Moody's Investors Service and "BBB" by Standard & Poor's. In addition, our utility's first mortgage bonds are rated "A1" and "BBB+" by Moody's and Standard & Poor's, respectively. These security ratings are subject to revision and/or withdrawal at any time by the respective rating organizations. Capital Requirements Our primary capital requirements for the three years ended December 31, 2001 were as follows: <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- (in thousands) <S> <C> <C> <C> Property and investment additions: Integrated energy $532,788 $130,332 $73,656 Electric utility 41,313 25,257 31,911 Communications and other 20,055 59,377 49,042 Common stock dividends 28,517 23,527 22,602 Maturities/redemptions of long-term debt 13,960 1,330 1,330 -------- -------- -------- $636,633 $239,823 $178,541 ======== ======== ======== </TABLE> Our capital additions for 2001 were $594 million. The major capital items for the year included the following: o Acquisition of the 240 megawatt Fountain Valley gas-fired turbine generation facility located near Colorado Springs, Colorado which was placed in service in third quarter 2001. o Acquisition of the 277 megawatt gas-fired co-generation power plant project located near Las Vegas, Nevada of which 53 megawatts were operational and 224 megawatts is expected to be placed in service in the third quarter of 2002. o Construction of the 50 megawatt combined-cycle expansion at our Arapahoe site in Denver, Colorado, which is expected to be placed in service in mid-2002. o Completion of construction of the 40 megawatt gas-turbine expansion at our Valmont, Colorado site, which we placed in service in July 2001. o Completion of construction of the 40 megawatt gas-fired combustion turbine unit at our Wyodak site, which we placed in service in May 2001. o Completion of the 18 megawatt combined-cycle upgrade of the Harbor facility near Long Beach, California. o Acquisitions of various interests in partnerships in which we previously held a minority interest. o Acquisition of operating and non-operating interests in 74 gas and oil wells from Stewart Petroleum Corporation. o Construction of a 40 megawatt gas-fired turbine known as the Lange project, which is expected to be placed in service in early 2002. o Construction of our communications fiber optic network. 44
Forecasted capital requirements for projected plant construction, other integrated energy investments, regulated utility capital improvements and completion of the communications network are as follows: 2002 2003 2004 ---- ---- ---- (in thousands) Integrated energy $ 148,996 $210,161 $336,489 Electric utility 47,745 24,180 15,271 Communications 16,312 4,269 3,230 --------- -------- -------- $ 213,053 $238,610 $354,990 ========= ======== ======== Our integrated energy business group's forecasted capital requirements include the following: o Completion of construction of the 224 megawatt gas-fired co-generation power plant project located near Las Vegas, Nevada which is expected to be placed in service in the third quarter of 2002. o Completion of construction of a 50 megawatt combined-cycle expansion at our Arapahoe, Colorado site (expected in mid-2002). o Deployment of $500 million for generating projects and acquisitions of proven producing natural gas properties and low-risk exploration and development drilling in years 2003-2004. We expect to finance our integrated energy business group's purchase and construction of electric generating facilities, primarily with long-term, non-recourse project level debt. We expect that any project-level debt will contain significant restrictions on distributions of cash from the project to us. In addition to the above forecasted capital items we will lease the Wygen Plant, a 90 megawatt coal-fired plant under construction at our Wyodak, Wyoming site through an off-balance sheet financing arrangement discussed above under Short-term Liquidity and Financing Transactions. Because of the leasing arrangement, the $130 - $140 million total construction cost of the plant is not included in the above three-year capital expenditure forecast. Wygen will be similar in design to our Neil Simpson II facility, which was completed in 1995 at the same site. The plant will run on low-sulfur coal fed by conveyor from our adjacent Wyodak coal mine and will use the latest available environmental control technology. We anticipate that the Wygen Plant will be operational in the first quarter of 2003. Forecasted capital expenditures for our electric utility operations include completion of construction of a 40 megawatt gas-fired turbine known as the Lange project expected to be in service in mid-2002, construction of an AC/DC/AC Tie which is expected to be placed in service in 2003, transmission and substation projects, re-build projects on existing transmission lines, distribution projects in response to customer requests for electric service, capital projects associated with our utility's existing generation plants, and other miscellaneous items. Our communications group's capital requirements forecast primarily consists of 2002 costs related to the completion of our fiber optic network in Rapid City and the northern Black Hills of South Dakota, nominal extensions of the base network to reach additional customers, and capital improvements to the existing network infrastructure. 45
Market Risk Disclosures Our operations and financial results are impacted by numerous factors including, but not limited to, commodity price risk, interest rate risk and counterparty risk. We are exposed to commodity price variability in nearly all of our core energy marketing and trading businesses. In addition, fuel requirements for our gas-fired generation and our natural long position in crude oil and natural gas production introduce additional commodity price risk. Fuel Marketing Activities We market natural gas, coal, and crude oil in specific areas of the United States and Canada. We offer wholesale fuel marketing and price risk management products and services to a variety of customers. These activities are subject to numerous risks, including commodity price risk. We have adopted Risk Management Policies and Procedures (RMP&P) covering all marketing activities. These RMP&P's have been approved by our Board of Directors and are routinely reviewed by the Audit Committee of the Board of Directors. The RMP&P include, but are not limited to, trader limits, position limits and credit exposure limits. We employ risk management methods to mitigate our commodity price risk. As a general policy, we only permit speculation with limited "open" positions as defined in the RMP&P. Therefore, substantially all of our marketing activities are fully hedged or back-to-back positions; in other words, each sale is matched with a purchase. To maintain compliance with these RMP&P and mitigate our commodity price risk, we routinely utilize fixed price forward purchase and sales contracts and over-the-counter swaps and options. We attempt to balance our fixed price physical and financial purchase and sale commitments in terms of volume and timing of performance and delivery obligations. However, we may at times have a bias in the market, within established guidelines, resulting from the management of our portfolio. In addition, we may, at times, be unable to fully hedge our portfolio for certain market risks as a result of marketplace illiquidity and other factors. Our fuel marketing operations fall under the purview of Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities" and Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10). As such, these activities are accounted for under mark-to-market accounting. The fair values are recorded as either Derivative assets and/or Derivative liabilities on the accompanying Consolidated Balance Sheet. The net gains or losses are recorded as Revenues in the accompanying Consolidated Statements of Income. 46
The contract or notional amounts and terms of our derivative commodity instruments held for trading purposes at December 31, 2001 and 2000, are set forth below: <TABLE> <CAPTION> 2001 2000 ---- ---- Maximum Maximum Notional Term Notional Term Amounts in Years Amounts in Years -------- -------- -------- -------- <S> <C> <C> <C> <C> (thousands of MMBtu's) Natural gas basis swaps purchased 9,882 1 25,578 2 Natural gas basis swaps sold 10,696 1 26,060 2 Natural gas fixed-for-float swaps purchased 10,646 2 6,476 1 Natural gas fixed-for-float swaps sold 11,815 2 7,361 1 Natural gas swing swaps purchased 465 1 - - Natural gas swing swaps sold 930 1 - - Natural gas physical purchases 13,159 1 - - Natural gas physical sales 19,339 1 - - (thousands of barrels) Crude oil purchased 3,139 1 2,186 1 Crude oil sold 3,142 1 2,530 1 (thousands of tons) Coal purchased 1,554 4 896 1 Coal sold 1,448 4 988 1 </TABLE> As required under SFAS 133 and EITF 98-10, derivatives and energy trading activities were marked to fair value on December 31, 2001, and the gains and/or losses recognized in earnings. The amounts related to the accompanying Consolidated Balance Sheets and Statements of Income as of December 31, 2001 and 2000 are as follows (in thousands): <TABLE> <CAPTION> Current Non-current Current Non-current Unrealized December 31, 2001 Assets Assets Liabilities Liabilities Gain ------ ------ ----------- ----------- ---- <S> <C> <C> <C> <C> <C> Natural gas $29,755 $ 661 $25,437 $953 $4,026 Crude Oil 6,267 - 5,497 - 770 Coal 1,192 467 1,018 - 641 ------- ------ ------- ---- ------ $37,214 $1,128 $31,952 $953 $5,437 ======= ====== ======= ==== ====== December 31, 2000 Natural gas $61,008 $ 391 $56,968 $3,532 $ 899 Crude oil 1,523 - 1,000 - 523 Coal 5,370 - 4,460 - 910 ------- ------ ------- ------ ------ $67,901 $ 391 $62,428 $3,532 $2,332 ======= ====== ======= ====== ====== </TABLE> At December 31, 2001, we had a mark to fair value unrealized gain of $5.4 million for our fuel marketing activities. Of this amount, $5.2 million was current and $0.2 million was non-current. The current portion of unrealized gains included $5.5 million gain associated with hedged transactions and $(0.3) million loss associated with open positions. We anticipate that substantially all of the current portion of unrealized gains for hedged transactions will be realized during the next twelve months. Conversely, estimated and actual realized gains or losses related to open positions will likely change during 2002 as market prices change from the December 31, 2001 estimates. 47
Non-trading Energy Activities We produce natural gas and crude oil through our exploration and production activities. These natural "long" positions, or unhedged open positions, introduce commodity price risk and variability in our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve our cash flows. We have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Board of Directors and are routinely reviewed by our Audit Committee. To mitigate commodity price risk and preserve cash flows, we use over-the-counter swaps and options. These derivative instruments fall under the purview of SFAS 133 and we elect to utilize hedge accounting as allowed under this Statement. At December 31, 2001, we had a portfolio of swaps to hedge portions of our crude oil and natural gas production. These transactions were previously identified as cash flow hedges, properly documented and met prospective effectiveness testing. At year-end, these transactions met retrospective effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2001, the derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the Consolidated Balance Sheet. The effective portion of the gain or loss on these derivatives was reported in other comprehensive income and the ineffective portion was reported in earnings. On January 1, 2001 (the transition adjustment date for SFAS 133 adoption), and on December 31, 2001, we had the following swaps and related balances (in thousands): <TABLE> <CAPTION> Accumulated Maximum Non- Non- Other Terms in Current current Current current Comprehensive January 1, 2001 Notional Years Assets Assets Liabilities Liabilities Income (Loss) Earnings -------- ----- ------ ------ ----------- ----------- ------------- -------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Crude oil swap 294,000 2 $ 33 $151 $ - $ - $ 184 $ - Crude oil options 120,000 1 472 - - - 472 - Natural gas swaps 1,581,000 1 - 3,411 - (3,411) - ------- ---- ------ ----- -------- ------ - $ 505 $151 $3,411 $ - $ (2,755) $ - ======= ==== ====== ===== ======== ====== December 31, 2001 Crude oil swaps 90,000 1 $ 529 $ - $ - $ - $ 529 $ - Natural gas swaps 1,216,000 1 1,593 - - - 1,463 130 ------ ----- ------ ----- -------- ------ $2,122 $ - $ - $ - $ 1,992 $ 130 ====== ===== ====== ===== ======== ====== </TABLE> *Crude in bbls, gas in MMBtu's Most of our crude oil and natural gas hedges are highly effective, resulting in very little earnings impact prior to realization. During 2001, we recorded $0.1 million in earnings due to ineffectiveness for certain natural gas swaps due to basis risk. All existing hedges at December 31, 2001 expire during the year ended December 31, 2002. The unrealized earnings gains or losses currently recorded in accumulated other comprehensive income are expected to be realized in earnings during 2002. Based on December 31, 2001 market prices, $2.0 million will be realized and reported in earnings during 2002. These estimated realized gains for 2002 were calculated using December 31, 2001 market prices. Estimated and actual realized gains will likely change during 2002 as market prices change. In addition, we acquired several natural gas swaps when we completed the Las Vegas Cogeneration acquisition on August 31, 2001 (See Note 15). The project has a long-term fixed price power sales agreement and an index-priced natural gas purchase contract for 5,000 MMBtus per day through April 30, 2010. These swaps fix the long-term purchase price of the index-priced natural gas purchase contract. At acquisition close, the fair value of these swaps 48
was $6.0 million. These swaps were executed with Enron North America Corp. (Enron), which is currently in bankruptcy proceedings. These swaps are derivatives under SFAS 133. We elected to treat these derivatives as cash flow hedges so that any gains or losses on the fair values of the swaps could be deferred and subsequently recognized when the underlying hedged natural gas was consumed in the plant. The swaps were properly documented and met the criteria for cash flow hedges. During the fourth quarter of 2001, we determined that it was probable that Enron would default on its obligations to us in conjunction with these swaps. Upon that determination, we ceased to account for these swaps as cash flow hedges. In addition, we recognized a $6.0 million pre-tax valuation reserve in recognition of Enron's probable performance default and resulting consequence that we would not receive payment for these amounts. We have taken action to mitigate this exposure. By negotiations or by appropriate legal action filed in U.S. Bankruptcy Court, Southern District of New York, we will seek authority to "net" or offset, certain obligations with Enron and its subsidiaries, both payable and receivable, among our subsidiaries. If we are successful in these efforts, substantially all of the financial value of the fuel swap could be recovered, and we would not have any remaining exposure to Enron or its bankrupt subsidiaries. Financing Activities We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. At December 31, 2001, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2001, we had $291.4 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of five years and a fair value of $(14.4) million. These hedges are substantially effective and any ineffectiveness was immaterial. In addition to the above interest rate swaps, we have entered into a $100 million forward starting floating-to-fixed interest rate swap to hedge the anticipated floating rate debt financing related to the Las Vegas Cogeneration expansion. The forward starting period for the swap is the second quarter of 2002, with a term of ten years. The swap will terminate and cash settle on its forward starting date, based on the fair market value of the swap at the starting date. At December 31, 2001, the swap had a fair market value of $2.3 million. The hedge has met effectiveness criteria. Upon completion of the long-term financing of the project, any gain or loss on the fair market value of the swap is anticipated to be amortized over the life of the long-term financing. On January 1, 2001 (the transition adjustment date for SFAS 133 adoption) and on December 31, 2001, our interest rate swaps and related balances were as follows (in thousands): <TABLE> <CAPTION> Weighted Average Accumulated Fixed Maximum Non- Non- Other Interest Terms in Current current Current current Comprehensive January 1, 2001 Notional Rate Years Assets Assets Liabilities Liabilities Income (Loss) -------- ---- ----- ------ ------ ----------- ----------- - ------------- <S> <C> <C> <C> <C> <C> <C> <C> <C> Swaps on project financing $127,416 7.38% 5 $ - $ 265 $ 2,440 $5,332 $ (7,507) ======== ======= ======= ======== ====== ========= December 31, 2001 Swaps on project financing $316,397 5.85% 4 $ - $5,746 $10,212 $5,949 $(10,415) Swaps on corporate debt 75,000 4.45% 3 - - 1,535 217 (1,752) -------- ------- ------ ------- ------ -------- $391,397 $ - $5,746 $11,747 $6,166 $(12,167) ======== ======= ====== ======= ====== ======== </TABLE> 49
We anticipate a portion of unrealized losses recorded in accumulated other comprehensive income will be realized as increased interest expense in 2002. Based on December 31, 2001 market interest rates, $11.7 million will be realized as additional interest expense during 2002. Estimated and realized amounts will likely change during 2002 as market interest rates change. At December 31, 2001, we had $655.8 million of outstanding, floating-rate debt of which $264.4 million was not offset with interest rate swap transactions that effectively convert the debt to a fixed rate. A 100 basis point increase in interest rates would cause interest expense to increase $2.6 million. The table below presents principal (or notional) amounts and related weighted average interest rates by year of maturity for our short-term investments and long-term debt obligations, including current maturities (in thousands). <TABLE> <CAPTION> 2002 2003 2004 2005 2006 Thereafter Total <S> <C> <C> <C> <C> <C> <C> <C> Cash equivalents Fixed rate $ 29,666 $ - $ - $ - $ - $ - $ 29,666 Long-term debt Fixed rate $ 18,065 $ 3,122 $ 2,017 $ 2,026 $ 2,036 $128,565 $ 155,831 Average interest rate 6.98% 9.31% 9.50% 9.52% 9.54% 8.28% 8.20% Variable rate (a) $ 17,839 $ 19,301 $ 21,126 $ 22,674 $ 135,285 $ 79,646 $ 295,871 Average interest rate 3.45% 3.45% 3.45% 3.45% 3.32% 3.48% 3.40% Total long-term debt $ 35,904 $ 22,423 $ 23,143 $ 24,700 $ 137,321 $ 208,211 $ 451,702 Average interest rate 5.22% 4.27% 3.98% 3.95% 3.41% 6.44% 5.05% </TABLE> (a) Approximately 74 percent of the variable rate debt has been hedged with interest rate swaps moving the floating rates to fixed rates with an average interest rate of 5.85 percent. Credit Risk Credit risk relates to the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We maintain credit policies with regards to our counterparties that we believe limit our overall credit risk. For our fuel marketing, energy production and risk management activities, we attempt to mitigate our credit risk by conducting a majority of our business with investment grade companies, obtaining netting agreements where possible and securing our exposure with less creditworthy counterparties through parental guarantees, prepayments and letters of credit. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer's current creditworthiness, as determined by our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot guarantee that we will continue to experience the same credit loss rates that we have in the past or that an investment grade counterparty will not default as was the case with Enron in 2001. At the end of the year, our credit exposure (exclusive of regulated utility retail customers and communications) was concentrated with investment grade companies. Approximately 85 percent of our credit exposure was with investment grade companies. For the 15 percent credit exposure with non-investment grade rated counterparties, approximately 60 percent of this exposure was supported through letters of credit, prepayments, parental guarantees and asset liens. 50
Rate Regulation Existing Rate Regulation In June 1999, the South Dakota Public Utilities Commission approved a settlement, which extended a rate freeze in effect since 1995 until January 1, 2005. The South Dakota settlement provides that, absent an extraordinary event, we may not file for any increase in our rates or invoke any fuel and purchased power adjustment tariff which would take effect during the freeze period. The specified extraordinary events are: o new governmental impositions increasing annual costs for South Dakota customers by more than $2.0 million; o simultaneous forced outages of both our Wyodak plant and Neil Simpson II plant projected to continue at least 60 days; o forced outages occurring to either plant which continue for a period of three months and are projected to last at least nine months; o an increase in the Consumer Price Index at a monthly rate for six months which would result in a 10 percent or higher annual inflation rate; o the loss of a South Dakota customer or revenue from an existing South Dakota customer that would result in a loss of revenue of $2.0 million or more during any 12-month period; o the cost of coal to our South Dakota customers increases and is projected to increase by more than $2.0 million over the cost for the most recent calendar year; and o electric deregulation occurs as a result of either federal or state mandate, which allows any of our customers to choose its provider of electricity at any time during the freeze period. During the freeze period, except as identified above, we are undertaking the risks of: o machinery failure; o load loss caused by either an economic downturn or changes in regulation; o increased costs under power purchase contracts over which we have no control; o government interferences; and o acts of nature and other unexpected events that could cause material losses of income or increases in costs of doing business. However, the settlement anticipates that we will retain, during that period of time, earnings realized from more efficient operations, sales from load growth, and off-system sales of power and energy. Over the last four years we have initiated an effort to enter into new contracts with our largest industrial customers. The new contracts contain "meet or release" provisions that grant us a five-year right to continue to serve a customer at market rates in the event of deregulation. Additionally, through our General Service Large Optional Combined Account Billing Tariff, we have allowed general service customers to aggregate their loads. This tariff also provides us with a five-year right to continue to serve those customers in the event of deregulation. Our "meet or release" contracts currently total more than 124 megawatts of large commercial and industrial load. These contracts provide us the assurance of a firm local market for our power resources, in the event deregulation occurs. These industrial and large commercial customers, together with our wholesale power sale agreements with the City of Gillette, Wyoming and Montana-Dakota Utilities Company, equal approximately 50 percent of our utility's firm load. 51
Regulatory Accounting As it pertains to the accounting for our utility operations, we follow SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. As a result of our regulatory activity, a 50-year depreciable life for the Neil Simpson II plant is used for financial reporting purposes. If we were not following SFAS 71, a 35- to 40-year life would probably be more appropriate which would increase depreciation expense by approximately $0.6 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our generation operations. In the event we determine that we no longer meet the criteria for following SFAS 71, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that may give rise to the discontinuance of SFAS 71 include increasing competition that could restrict our ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate. New Accounting Pronouncements In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS 141) and No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. Under SFAS 142, goodwill and intangible assets with indefinite lives are no longer amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Intangible assets with a defined life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, we were required to adopt SFAS 142 effective January 1, 2002. We are currently evaluating the effects adoption has on our consolidated financial statements. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement costs being capitalized as part of the carrying amount of the long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. We expect to adopt SFAS 143 effective January 1, 2003 and are currently evaluating the effects adoption will have on our consolidated financial statements. In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 supersedes FASB Statement 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB 30). SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale as well as resolves implementation issues related to SFAS 121. We were required to adopt SFAS 144 effective January 1, 2002. Adoption did not have a material impact on our consolidated financial position, results of operations or cash flows. 52
Safe Harbor for Forward Looking Information In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), we are hereby filing cautionary statements identifying important factors that could cause our actual results to differ materially from those projected in forward-looking statements (as such term is defined in the Reform Act) made by or on behalf of the Company in our Annual Report on Form 10-K, Annual Report, Quarterly Report on Form 10-Q, and presentations, or in response to questions or otherwise. These statements concern our plans, expectations and objectives for future operations. All statements, other than statements of historical fact that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words "anticipate," "believe," "estimate," "expect," "intend," "plan," "predicts," "project," "will likely result," "will continue," or similar expressions are not statements of historical fact and may be forward-looking. These forward-looking statements include, among others, such things as: o expansion and growth of our business and operations; o future financial performance; o future acquisition and development of power plants; o future production of coal, oil and natural gas; o reserve estimates; and o business strategy. Forward-looking statements are based on assumptions that 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 which could cause actual results to differ materially from those contained in the forward-looking statements, including the following factors: o prevailing governmental policies and regulatory actions, with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and resale competition; o changes in and compliance with environmental and safety laws and policies; o weather conditions; o population growth and demographic patterns; o competition for retail and wholesale customers; o pricing and transportation of commodities; o market demand, including structural market changes; o changes in tax rates or policies or in rates of inflation; o changes in project costs; o unanticipated changes in operating expenses or capital expenditures; o capital market conditions; o creditworthiness of counterparties; o technological advances; o competition for new energy development opportunities; and o legal and administrative proceedings that influence our business and profitability. Any forward-looking statement speaks only as to the date on which that statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which that statement is made or to reflect the occurrence of an anticipated event. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. 53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Public Accountants 54 Consolidated Statements of Income for the three years ended December 31, 2001 55 Consolidated Balance Sheets as of December 31, 2001 and 2000 56 Consolidated Statements of Cash Flows for the three years ended December 31, 2001 57 Consolidated Statements of Common Stockholders' Equity for the three years ended December 31, 2001 58 Notes to Consolidated Financial Statements 59-86 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of Black Hills Corporation: We have audited the accompanying consolidated balance sheets of Black Hills Corporation (a South Dakota corporation) and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Black Hills Corporation and Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As explained in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company adopted the provisions of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." ARTHUR ANDERSEN LLP Minneapolis, Minnesota, March 22, 2002 54
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME <TABLE> <CAPTION> Years ended December 31, 2001 2000 1999 ---- ---- ---- (in thousands, except per share amounts) <S> <C> <C> <C> Operating revenues $1,558,558 $1,623,836 $ 791,875 ---------- ---------- --------- Operating expenses: Fuel and purchased power 1,165,144 1,370,841 637,302 Operations and maintenance 65,556 46,054 36,463 Administrative and general 80,635 44,423 18,272 Depreciation, depletion and amortization 54,051 32,864 25,067 Taxes, other than income taxes 22,993 14,904 12,880 ---------- ---------- --------- 1,388,379 1,509,086 729,984 ---------- ---------- --------- Operating income 170,179 114,750 61,891 ---------- ---------- --------- Other income (expense): Interest expense (39,626) (30,342) (15,460) Interest income 2,378 7,075 3,614 Other, net 9,876 2,996 876 ---------- ---------- --------- (27,372) (20,271) (10,970) ---------- ---------- --------- Income before minority interest and income taxes 142,807 94,479 50,921 Minority interest (4,186) (11,273) 1,935 Income taxes (50,544) (30,358) (15,789) ---------- ---------- --------- Net income 88,077 52,848 37,067 Preferred stock dividends (527) (78) - ---------- ---------- --------- Net income available for common stock $ 87,550 $ 52,770 $ 37,067 ========== ========== ========= Earnings per share of common stock: Basic $ 3.45 $ 2.39 $ 1.73 ========== ========== ========= Diluted $ 3.42 $ 2.37 $ 1.73 ========== ========== ========= Weighted average common shares outstanding: Basic 25,374 22,118 21,445 ========== ========== ========= Diluted 25,771 22,281 21,482 ========== ========== ========= </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 55
BLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS <TABLE> <CAPTION> At December 31, 2001 2000 ---- ---- (in thousands, except share amounts) ASSETS <S> <C> <C> Current assets: Cash and cash equivalents $ 29,666 $ 24,913 Securities available-for-sale 3,550 2,113 Receivables (net of allowance for doubtful accounts of $5,913 and $3,631, respectively) 117,259 299,719 Derivative assets 39,336 67,901 Other current assets 30,540 23,973 ---------- ---------- 220,351 418,619 ---------- ---------- Investments 59,895 50,137 ---------- ---------- Property, plant and equipment 1,566,624 1,072,129 Less accumulated depreciation and depletion (328,400) (277,848) ---------- ---------- 1,238,224 794,281 ---------- ---------- Other assets: Derivative assets 6,874 391 Goodwill and other intangible assets 115,081 45,905 Other 18,342 10,987 ---------- ---------- 140,297 57,283 ---------- ---------- $1,658,767 $1,320,320 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 102,041 $ 247,596 Accrued liabilities 40,178 49,661 Current maturities of long-term debt 35,904 13,960 Notes payable 361,240 211,679 Derivative liabilities 43,699 62,428 ---------- ---------- 583,062 585,324 ---------- ---------- Long-term debt, net of current maturities 415,798 307,092 ---------- ---------- Deferred credits and other liabilities: Federal income taxes 75,398 62,679 Derivative liabilities 7,119 3,532 Other 42,693 41,386 ---------- ---------- 125,210 107,597 ---------- ---------- Minority interest in subsidiaries 19,533 37,961 ---------- ---------- Commitments and contingencies (Notes 10, 11 and 15) Stockholders' equity: Preferred stock - no par Series 2000-A; 21,500 shares authorized; issued and outstanding: 5,177 shares in 2001, 4,000 shares in 2000 5,549 4,000 ---------- ---------- Common stock equity- Common stock $1 par value; 100,000,000 shares authorized; issued: 26,890,943 shares in 2001 and 23,302,111 shares in 2000 26,891 23,302 Additional paid-in capital 240,454 73,442 Retained earnings 250,515 191,482 Treasury stock, at cost (4,503) (9,067) Accumulated other comprehensive loss (3,742) (813) ---------- ---------- 509,615 278,346 ---------- ---------- Total stockholders' equity 515,164 282,346 ---------- ---------- $1,658,767 $1,320,320 ========== ========== </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 56
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS <TABLE> <CAPTION> Years ended December 31, 2001 2000 1999 ---- ---- ---- (in thousands) <S> <C> <C> <C> Operating activities: Net income available for common $87,550 $52,770 $37,067 Principal non-cash items- Depreciation, depletion and amortization 54,051 32,864 25,067 Issuance of treasury stock (Note 4) 4,243 - - Provision for valuation allowances 9,632 3,353 (203) Net change in derivative assets and liabilities (4,186) (2,332) - Gain on sales of assets (2,587) (3,736) (2,541) Deferred income taxes and investment tax credits 9,792 1,937 2,291 Undistributed earnings in associated companies (9,287) (3,672) - Minority interest 4,186 11,273 (1,935) Change in operating assets and liabilities- Accounts receivable 181,738 (204,662) 2,435 Other current assets (7,446) (3,513) (4,003) Accounts payable (146,603) 165,394 6,268 Accrued liabilities (9,483) 18,678 4,013 Other, net 5,796 2,444 5,284 --------- -------- -------- 177,396 70,798 73,743 --------- -------- -------- Investing activities: Property, plant and equipment additions (378,479) (134,855) (102,290) Payment for acquisition of net assets, net of cash acquired (199,001) (28,688) - Payment for acquisition of minority interest (16,676) - - Increase in investments (471) (9,974) (52,319) Proceeds from sales of assets 2,900 5,500 3,463 Available-for-sale securities purchased - - (7,870) Available-for-sale securities sold - 4,660 22,959 --------- -------- -------- (591,727) (163,357) (136,057) --------- -------- -------- Financing activities: Dividends paid on common stock (28,517) (23,527) (22,602) Treasury stock issued (purchased) 321 (1,037) (4,949) Common stock issued 168,522 3,854 424 Increase in short-term borrowings 149,561 73,848 92,489 Long-term debt - issuance 144,610 60,082 - Long-term debt - repayments (13,960) (1,330) (1,330) Subsidiary distributions to minority interests (1,453) (10,900) - --------- -------- --------- 419,084 100,990 64,032 --------- -------- --------- Increase in cash and cash equivalents 4,753 8,431 1,718 Cash and cash equivalents: Beginning of year 24,913 16,482 14,764 --------- -------- --------- End of year $ 29,666 $ 24,913 $ 16,482 ========= ======== ========= Supplemental disclosure of cash flow information: Cash paid during the period for- Interest $39,595 $31,292 $15,297 Income taxes $40,917 $18,518 $13,173 Noncash net assets acquired through issuance of common and preferred stock (Note 15) $ 3,628 $34,493 $ - </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 57
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY <TABLE> <CAPTION> Accumulated Common Stock Additional Treasury Stock Other ---------------------- Paid-In Retained --------------------- Comprehensive Shares Amount Capital Earnings Shares Amount Income (loss) Total ------ ------ ------- -------- ------ ------ ------------- ----- (in thousands, except share amounts) <S> <C> <C> <C> <C> <C> <C> <C> <C> Balance at December 31, 1998 21,719 $ 21,719 $ 40,254 $147,774 141 $(3,081) - $206,666 ------ -------- -------- -------- ---- ------- ----------- -------- Comprehensive Income: Net income - - - 37,067 - - - 37,067 ------ -------- -------- -------- ---- ------- ----------- -------- Total comprehensive income - - - 37,067 - - - 37,067 Dividends on common stock - - - (22,602) - - - (22,602) Issuance of common stock 20 20 404 - - - - 424 Treasury stock acquired, net - - - - 227 (4,949) - (4,949) ------ -------- -------- -------- ---- ------- ----------- -------- Balance at December 31, 1999 21,739 21,739 40,658 162,239 368 (8,030) - 216,606 ------ -------- -------- -------- ---- ------- ----------- -------- Comprehensive Income: Net income - - - 52,848 - - - 52,848 Other comprehensive income, net of tax: Unrealized loss on available for sale securities - - - - - - (813) (813) ------ -------- -------- -------- ---- ------- ----------- -------- Total comprehensive income - - - 52,848 - - (813) 52,035 Dividends on preferred stock - - - (78) - - - (78) Dividends on common stock - - - (23,527) - - - (23,527) Issuance of common stock 1,563 1,563 32,784 - - - - 34,347 Treasury stock acquired, net - - - - 13 (1,037) - (1,037) ------ -------- -------- -------- ---- ------- ----------- -------- Balance at December 31, 2000 23,302 23,302 73,442 191,482 381 (9,067) (813) 278,346 ------ -------- -------- -------- ---- ------- ----------- -------- Comprehensive Income: Net income - - - 88,077 - - - 88,077 Other comprehensive income, net of tax: Unrealized gain on available for sale securities - - - - - - 1,438 1,438 Initial impact of adoption of SFAS 133, net of minority interest - - - - - - (4,510) (4,510) Fair value adjustment on derivatives designated as cash flow hedges, net of minority interest - - - - - - 143 143 ------ -------- -------- -------- ---- -------- ----------- -------- Total comprehensive income - - - 88,077 - - (2,929) 85,148 Dividends on preferred stock - - - (527) - - - (527) Dividends on common stock - - - (28,517) - - - (28,517) Issuance of common stock 3,589 3,589 167,012 - - - - 170,601 Treasury stock issued, net - - - - (142) 4,564 - 4,564 ------ -------- -------- -------- ---- -------- ----------- -------- Balance at December 31, 2001 26,891 $ 26,891 $240,454 $250,515 239 $(4,503) $ (3,742) $509,615 ====== ======== ======== ======== ==== ======= =========== ======== </TABLE> The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. 58
BLACK HILLS CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2001, 2000 and 1999 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation and its subsidiaries operate in three primary operating groups: non-regulated integrated energy, regulated electric utility and communications. The Company operates its integrated energy businesses through its direct and indirect subsidiaries: Wyodak Resources related to coal, Black Hills Exploration and Production related to oil and natural gas, Enserco Energy, Black Hills Energy Resources and Black Hills Coal Network related to fuel marketing of natural gas, oil and coal, respectively, and Black Hills Energy Capital and its subsidiaries and Black Hills Generation related to independent power activities, all aggregated for reporting purposes as Black Hills Energy (formerly Black Hills Energy Ventures); operates its public utility electric operations through its subsidiary, Black Hills Power, Inc.; and operates its communications operations through its indirect subsidiaries Black Hills Fiber Systems, Black Hills FiberCom L.L.C. and Daksoft. For further descriptions of the Company's business segments, see Note 14. In December 2000, the Company effected a holding company structure under the renamed holding company, Black Hills Corporation. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to allowance for uncollectable accounts receivable, inventory obsolescence, realization of market value of derivatives due to commodity risk, intangible asset valuations and useful lives, proved oil and gas reserve volumes, employee benefit plans, environmental accruals and contingencies. Actual results could differ from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly owned and majority-owned subsidiaries and certain subsidiaries in which the Company's ownership interest may be less than 50 percent but represents voting control. Generally, the Company uses equity accounting for investments of which it owns between 20 and 50 percent and investments in partnerships under 20 percent if the Company exercises significant influence. All significant intercompany balances and transactions have been eliminated in consolidation except for revenues and expenses associated with intercompany coal sales in accordance with the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). Total intercompany coal sales not eliminated were $11.2 million, $9.7 million and $7.7 million in 2001, 2000 and 1999, respectively. The Company owns 51 percent of the voting securities of Black Hills FiberCom, LLC (FiberCom). During 2000, FiberCom's operating losses reduced its members' equity below zero. At that point, the Company began to recognize 100 percent of FiberCom's operating losses and will continue to do so until such time as additional equity investments are made by third parties or future net income restores members' equity to a positive amount. As discussed in Note 15, the Company and its subsidiaries made several acquisitions during 2001 and 2000. The Company's consolidated statements of income include operating activity of these companies beginning with their acquisition date. The Company uses the proportionate consolidation method to account for its working interests in oil and gas properties. 59
Minority Interest in Subsidiaries Minority interest in the accompanying Consolidated Statements of Income represents the share of income or loss of certain consolidated subsidiaries attributable to the minority shareholders of those subsidiaries. The minority interest in the accompanying Consolidated Balance Sheets reflect the amount of the underlying net assets of those certain consolidated subsidiaries attributable to the minority shareholders in those subsidiaries. Regulatory Accounting The Company's subsidiary, Black Hills Power, is subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company's non-regulated businesses. Black Hills Power follows the provisions of SFAS 71, and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating Black Hills Power. As a result of Black Hills Power's 1995 rate case settlement, a 50-year depreciable life for the Neil Simpson II plant is used for financial reporting purposes. If Black Hills Power were not following SFAS 71, a 35 to 40 year life would be more appropriate, which would increase depreciation expense by approximately $0.6 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to Black Hills Power's generation operations. In the event Black Hills Power determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company could be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict Black Hills Power's ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure that the continuing application of SFAS 71 is appropriate. Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Securities Available-for-Sale The Company has investments in marketable securities that are classified as available-for-sale securities and are carried at fair value in accordance with the provisions of Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities." The unrealized gain or loss resulting from the difference between the securities' fair value and cost basis is included as a component of accumulated other comprehensive income in common stockholders' equity. Inventory Materials, supplies and fuel are generally stated at the lower of cost or market on a first-in, first-out basis. During 2001, 2000 and 1999, provisions of $1.4 million, $1.5 million and $0, respectively, were charged to operations to write-down inventories at the Company's communications group to estimated net realizable value. Natural gas, oil and coal inventories held in fuel marketing companies are stated at market. Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is an allowance for funds used during construction (AFUDC) which represents the approximate composite cost of borrowed funds and a return on capital used to finance the project. The AFUDC was computed at an annual composite rate of 10.2, 9.7 and 8.3 percent during 2001, 2000 and 1999, respectively. In addition, the Company capitalizes interest, when applicable, on certain non-regulated construction projects. The amount of AFUDC and interest capitalized was $7.5 million, $2.0 million and $1.2 million in 2001, 2000 and 1999, respectively. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, together with removal cost less salvage, is charged to accumulated depreciation. Retirement or disposal of all other assets, except for oil and gas properties as described 60
below, result in gains or losses recognized as a component of income. Repairs and maintenance of property are charged to operations as incurred. Depreciation provisions for regulated electric property, plant and equipment is computed on a straight-line basis using an annual composite rate of 3.0 percent in 2001, 2.8 percent in 2000 and 3.1 percent in 1999. Non-regulated property, plant and equipment are depreciated on a straight-line basis using estimated useful lives ranging from 3 to 39 years. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method on volumes produced and estimated reserves. Goodwill and Intangible Assets Goodwill represents the excess of acquisition costs over the fair value of the net assets of acquired businesses and through 2001 was amortized on a straight-line basis over the estimated useful lives of such assets, which ranged from 8 to 25 years. The cost of other acquired intangibles is amortized on a straight-line basis over their estimated useful lives. Amortization expense was $4.4 million, $3.1 million and $2.7 million in 2001, 2000 and 1999, respectively. Accumulated amortization was $11.1 million, $6.7 million and $3.6 million at December 31, 2001, 2000 and 1999, respectively. Impairment of Long-Lived Assets and Intangible Assets The Company periodically evaluates whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of its long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, the Company would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, the Company would recognize an impairment loss. No impairment loss was recorded during 2001, 2000 or 1999. Oil and Gas Operations The Company accounts for its oil and gas activities under the full cost method. Under the full cost method, all productive and nonproductive costs related to acquisition, exploration and development drilling activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonments of properties, are treated as adjustments to the cost of the properties with no gain or loss recognized. Under the full cost method, net capitalized costs are subject to a "ceiling test" which limits these costs to the present value of future net cash flows discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the net capitalized costs. Future net cash flows are estimated based on end-of-period spot market prices adjusted for contracted price changes. If the net capitalized costs exceed the full cost "ceiling" at period end, a permanent noncash write-down would be charged to earnings in that period unless subsequent market price changes eliminate or reduce the indicated write-down. Given the volatility of oil and gas prices, it is possible that the Company's estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that a write-down of oil and gas properties could occur in the future. No "ceiling test" write-downs were recorded during 2001, 2000 or 1999. Income Taxes The Company uses the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. The Company classifies deferred tax assets and liabilities into current and noncurrent amounts based on the classification of the related assets and liabilities. 61
Revenue Recognition Generally, revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. Fuel marketing businesses also use the mark-to-market method of accounting. Under that method, all energy trading activities are recorded at fair value as of the balance sheet date and net gains or losses resulting from the revaluation of these contracts to fair value are recognized currently in the results of operations. For long-term non-utility power sales agreements revenue is recognized either in accordance with Emerging Issues Task Force Issue No. 91-6, "Revenue Recognition of Long-Term Power Sales Contracts," or in accordance with SFAS No. 13, "Accounting for Leases," as appropriate. Under EITF 91-6, revenue is generally recognized as the lower of the amount billed or at the average rate expected over the life of the agreement. Under SFAS 13, revenue is generally levelized over the life of the agreement. For its Investments in Associated Companies (see Note 3), which are involved in power generation, the Company uses the equity method to recognize as earnings its pro rata share of the net income or loss of the associated company. Earnings Per Share of Common Stock Basic earnings per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed under the treasury stock method and is calculated to compute the dilutive effect primarily resulting from outstanding stock options and conversion of preferred shares. Reclassifications Certain 2000 and 1999 amounts in the consolidated financial statements have been reclassified to conform to the 2001 presentation. These reclassifications had no effect on the Company's common stockholders' equity or results of operations, as previously reported. Recently Issued Accounting Pronouncements In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS 141) and No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. Under SFAS 142, goodwill and intangible assets with indefinite lives are no longer amortized but are reviewed annually (or more frequently if impairment indicators arise) for impairment. Intangible assets with a defined life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, the Company was required to adopt SFAS 142 effective January 1, 2002. Management is currently evaluating the effects adoption has on the Company's consolidated financial statements. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement costs being capitalized as part of the carrying amount of the long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Management expects to adopt SFAS 143 effective January 1, 2003 and is currently evaluating the effects adoption will have on the Company's consolidated financial statements. In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 supersedes FASB Statement 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB 30). SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale as well as resolves implementation issues related to SFAS 121. The Company was required to adopt SFAS 144 effective January 1, 2002. Adoption did not have a material impact on the Company's consolidated financial position, results of operations or cash flows. 62
Change in Accounting Principle - Derivatives and Hedging Activities In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging Activities." SFAS 133, as amended, establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133 allows hedge accounting for fair value and cash flow hedges. SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS 133 requires that on date of initial adoption, an entity shall recognize all freestanding derivative instruments in the balance sheet as either assets or liabilities and measure them at fair value. The difference between a derivative's previous carrying amount and its fair value shall be reported as a transition adjustment. The transition adjustment resulting from adopting this Statement shall be reported in net income or other comprehensive income, as appropriate, as the effect of a change in accounting principle in accordance with paragraph 20 of Accounting Principles Board Opinion No. 20 (APB 20), "Accounting Changes." On January 1, 2001, the Company adopted SFAS 133. Upon adoption, most of the Company's fuel marketing activities previously accounted for under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) fell under the purview of SFAS 133. The effect of adoption on the fuel marketing companies and risk management activities was not material because, unless otherwise noted, the fuel marketing companies did not designate their risk management activities as hedge instruments. This "no hedge" designation resulted in these derivatives being measured at fair value and gains and losses recognized currently in earnings. This treatment under SFAS 133 was comparable to the accounting under EITF 98-10. At January 1, 2001, the Company had certain non-trading energy contracts and interest rate swaps documented as cash flow hedges. These contracts were defined as derivatives under SFAS 133 and met the requirements for cash flow hedges. Because these contracts were documented as hedges prior to adoption, the transition adjustment was reported in accumulated other comprehensive income. The aggregated entry for these derivatives identified as cash flow hedges increased derivative assets by $0.9 million, increased the derivative liabilities by $11.2 million and decreased accumulated other comprehensive income by $10.3 million pre-tax. (2) RISK MANAGEMENT ACTIVITIES The Company's operations and financial results are impacted by numerous factors including, but not limited to, commodity price risk, interest rate risk and counterparty risk. The Company is exposed to commodity price variability in nearly all core energy marketing and trading businesses. In addition, fuel requirements at its gas-fired generation and its natural long position in crude oil and natural gas production introduce additional commodity price risk. Fuel Marketing Activities The Company markets natural gas, coal, and crude oil in specific areas of the United States and Canada. The Company offers wholesale fuel marketing and price risk management products and services to a variety of customers. These activities subject the Company to numerous risks including commodity price risk. The Company has adopted Risk Management Policies and Procedures (RMP&P) covering all marketing activities. The RMP&P have been approved by the Company's Board of Directors and are routinely reviewed by the Audit Committee of the Board of Directors. The RMP&P include, but are not limited to, trader limits, position limits and credit exposure limits. 63
The Company employs risk management methods to mitigate its commodity price risk. As a general policy, the Company only permits speculation with limited "open" positions as defined in the RMP&P. Therefore, substantially all of its marketing activities are fully hedged or back-to-back positions; in other words, each sale is matched with a purchase. To maintain compliance with the RMP&P and mitigate its commodity price risk, the Company routinely utilizes fixed price forward purchase and sales contracts and over-the-counter swaps and options. The Company attempts to balance its fixed price physical and financial purchase and sale commitments in terms of volume and timing of performance and delivery obligations. However, the Company may at times have a bias in the market, within established guidelines, resulting from the management of its portfolio. In addition, the Company may, at times, be unable to fully hedge its portfolio for certain market risks as a result of marketplace illiquidity and other factors. The Company's fuel marketing operations fall under the purview of SFAS 133 and EITF 98-10. As such, these activities are accounted for under mark-to-market accounting. The Company records its fair values as either Derivative assets and/or Derivative liabilities on the accompanying Consolidated Balance Sheet. The net gains or losses are recorded as Revenues in the accompanying Consolidated Statements of Income. The contract or notional amounts and terms of the Company's derivative commodity instruments held for trading purposes at December 31, 2001 and 2000, are set forth below: <TABLE> <CAPTION> 2001 2000 Notional Maximum Notional Maximum (thousands of MMBtu's) Amounts Term in Years Amounts Term in Years -------- ------------- -------- ------------- <S> <C> <C> <C> <C> Natural gas basis swaps purchased 9,882 1 25,578 2 Natural gas basis swaps sold 10,696 1 26,060 2 Natural gas fixed-for float swaps purchased 10,646 2 6,476 1 Natural gas fixed-for-float swaps sold 11,815 2 7,361 1 Natural gas swing swaps purchased 465 1 - - Natural gas swing swaps sold 930 1 - - Natural gas physical purchases 13,159 1 - - Natural gas physical sales 19,339 1 - - (thousands of barrels) Crude oil purchased 3,139 1 2,186 1 Crude oil sold 3,142 1 2,530 1 (thousands of tons) Coal purchased 1,554 4 896 1 Coal sold 1,448 4 988 1 </TABLE> 64
As required under SFAS 133 and EITF 98-10, derivatives and energy trading activities were marked to fair value on December 31, 2001, and the gains and/or losses recognized in earnings. The amounts related to the accompanying Consolidated Balance Sheets and Statements of Income as of December 31, 2001 and 2000, are as follows (in thousands): <TABLE> <CAPTION> Current Non-current Current Non-current Unrealized December 31, 2001 Assets Assets Liabilities Liabilities Gain ------ ------ ----------- ----------- ---- <S> <C> <C> <C> <C> <C> Natural gas $29,755 $ 661 $25,437 $ 953 $4,026 Crude Oil 6,267 - 5,497 - 770 Coal 1,192 467 1,018 - 641 ------- ------ ------- ------- ------ $37,214 $1,128 $31,952 $ 953 $5,437 ======= ====== ======= ======= ====== December 31, 2000 Natural gas $61,008 $ 391 $56,968 $3,532 $ 899 Crude oil 1,523 - 1,000 - 523 Coal 5,370 - 4,460 - 910 ------- ------ ------- ------ ------ $67,901 $ 391 $62,428 $3,532 $2,332 ======= ====== ======= ====== ====== </TABLE> At December 31, 2001, the Company had a mark to fair value unrealized gain of $5.4 million for its fuel marketing activities. Of this amount, $5.2 million was current and $0.2 million was non-current. The current portion of unrealized gains included $5.5 million gain associated with hedged transactions and $(0.3) million loss associated with open positions. The Company anticipates that substantially all of the current portion of unrealized gains for hedged transactions will be realized during the next twelve months. Conversely, estimated and actual realized gains or losses related to open positions will likely change during 2002 as market prices change from the December 31, 2001 estimates. Non-trading Energy Activities The Company produces natural gas and crude oil through its exploration and production activities. These natural long positions, or unhedged open positions, introduce commodity price risk and variability in cash flows for the Company. The Company employs risk management methods to mitigate this commodity price risk and preserve its cash flows. The Company has adopted guidelines covering hedging for its natural gas and crude oil production. These guidelines have been approved by the Company's Board of Directors and are routinely reviewed by its Audit Committee. To mitigate commodity price risk and preserve cash flows, the Company uses over-the-counter swaps and options. These derivative instruments fall under the purview of SFAS 133 and the Company elects to utilize hedge accounting as allowed under this Statement. At December 31, 2001, the Company had a portfolio of swaps to hedge portions of its crude oil and natural gas production. These transactions were previously identified as cash flow hedges, properly documented, and met prospective effectiveness testing. At year-end, these transactions met retrospective effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2001, the derivatives were marked to fair value and were recorded in Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives was reported in other comprehensive income and the ineffective portion was reported in earnings. 65
On January 1, 2001 (the transition adjustment date for SFAS 133 adoption) and December 31, 2001, the Company had the following swaps and related balances (in thousands): <TABLE> <CAPTION> Accumulated Maximum Other Terms in Current Non-current Current Non-current Comprehensive Notional* Years Assets Assets Liabilities Liabilities Income (Loss) Earnings --------- ----- ------ ------ ----------- ----------- ------------- -------- January 1, 2001 <S> <C> <C> <C> <C> <C> <C> <C> <C> Crude oil swaps 294,000 2 $ 33 $151 $ - $ - $ 184 $ - Crude oil options 120,000 1 472 - - - 472 - Natural gas swaps 1,581,000 1 - - 3,411 - (3,411) - ------ ---- ------- ----- -------- ------ $ 505 $151 $ 3,411 $ - $ (2,755) $ - ====== ==== ======= ===== ======== ====== December 31, 2001 Crude oil swaps 90,000 1 $ 529 $ - $ - $ - $ 529 $ - Natural gas swaps 1,216,000 1 1,593 - - - 1,463 130 ------ ------ -------- ----- -------- ------ $2,122 $ - $ - $ - $ 1,992 $ 130 ====== ====== ======== ===== ======== ====== </TABLE> - ----------------------- *crude in bbls, gas in MMBtu's Most of the Company's crude oil and natural gas hedges are highly effective, resulting in very little earnings impact prior to realization. During 2001, the Company recorded $0.1 million earnings due to ineffectiveness for certain natural gas swaps due to basis risk. All existing hedges at December 31, 2001 expire during the year ended December 31, 2002. The unrealized earnings gains or losses currently recorded in accumulated other comprehensive income are expected to be realized in earnings during 2002. Based on December 31, 2001 market prices, $2.0 million will be realized and reported in earnings during 2002. These estimated realized gains for 2002 were calculated using December 31, 2001 market prices. Estimated and actual realized gains will likely change during 2002 as market prices change. In addition, the Company acquired several natural gas swaps when it completed the Las Vegas Cogeneration acquisition on August 31, 2001 (Note 15). The project has a long-term fixed price power sales agreement and an index-priced natural gas purchase contract for 5,000 MMBtus per day through April 30, 2010. These swaps fix the long-term purchase price of the index-priced natural gas purchase contract. At acquisition close, the fair value of these swaps was $6.0 million. These swaps were executed with Enron North America Corp. (Enron), which is currently in bankruptcy proceedings. These swaps are derivatives under SFAS 133. The Company elected to treat these derivatives as cash flow hedges so that any gains or losses on the fair values of the swaps could be deferred and subsequently recognized when the underlying hedged natural gas was consumed in the plant. The swaps were properly documented and met the criteria for cash flow hedges. During the fourth quarter of 2001, the Company determined that it was probable that Enron would default on its obligations to the Company in conjunction with these swaps. Upon that determination, the Company ceased to account for these swaps as cash flow hedges. In addition, the Company recognized a $6.0 million pre-tax valuation reserve in recognition of Enron's probable performance default and resulting consequence that the Company would not receive payment for these amounts. Financing Activities The Company engages in activities to manage risks associated with changes in interest rates. The Company has entered into floating-to-fixed interest rate swap agreements to reduce its exposure to interest rate fluctuations associated with its floating rate debt obligations. At December 31, 2001, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2001, the Company had $291.4 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of five years and a fair value of $(14.4) million. These hedges are substantially effective and any ineffectiveness was immaterial. In addition to the above interest rate swaps, the Company has entered into a $100 million forward starting floating-to-fixed interest rate swap to hedge the anticipated floating rate debt financing related to the Company's Las Vegas Cogeneration 66
expansion. The forward starting period for the swap is the second quarter of 2002, with a term of ten years. The swap will terminate and cash settle on its forward starting date, based on the fair market value of the swap at the starting date. At December 31, 2001, the swap had a fair market value of $2.3 million. The hedge has met effectiveness criteria. Upon completion of the long-term financing of the project, any gain or loss on the fair market value of the swap is anticipated to be amortized over the life of the long-term financing. At December 31, 2001, the Company had $655.8 million of outstanding, floating rate debt, of which $264.4 million was not offset with interest rate swaps transactions that effectively convert the debt to fixed rate. On January 1, 2001 (the transition adjustment date for SFAS 133 adoption) and on December 31, 2001, the Company's interest rate swaps and related balances were as follows (in thousands): <TABLE> <CAPTION> Weighted Average Accumulated Fixed Maximum Other Interest Terms in Current Non-current Current Non-current Comprehensive Notional* Rate Years Assets Assets Liabilities Liabilities Income (Loss) --------- ---- ----- ------ ------ ----------- ---------- ------------- January 1, 2001 <S> <C> <C> <C> <C> <C> <C> <C> <C> Swaps on project financing $127,416 7.38% 5 $ - $ 265 $ 2,440 $5,332 $ (7,507) ======== ===== ======= ======= ====== ======== December 31, 2001 Swaps on project financing $316,397 5.85% 4 $ - $ 5,746 $10,212 $5,949 $(10,415) Swaps on corporate debt 75,000 4.45% 3 - - 1,535 217 (1,752) -------- ----- ------- ------- ------ -------- Total $391,397 $ - $ 5,746 $11,747 $6,166 $(12,167) ======== ===== ======= ======= ====== ======== </TABLE> The Company anticipates a portion of unrealized losses recorded in accumulated other comprehensive income will be realized as increased interest expense in 2002. Based on December 31, 2001 market interest rates, $11.7 million will be realized as additional interest expense during 2002. Estimated and realized amounts will likely change during 2002 as market interest rates change. Credit Risk Credit risk relates to the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. The Company maintains credit policies with regards to its counterparties that the Company believes limit its overall credit risk. For its fuel marketing, energy production and risk management activities, the Company attempts to mitigate its credit risk by conducting a majority of its business with investment grade companies, obtaining netting agreements where possible and securing its exposure with less creditworthy counterparties through parental guarantees, prepayments and letters of credit. At the end of the year, the Company's credit exposure (exclusive of regulated retail customers and communications) was concentrated with investment grade companies. Approximately 85 percent of the Company's credit exposure was with investment grade companies. For the 15 percent credit exposure with non-investment grade rated counterparties, approximately 60 percent of this exposure was supported through letters of credit, prepayments, parental guarantees and asset liens. 67
(3) INVESTMENTS IN ASSOCIATED COMPANIES Included in Investments on the Consolidated Balance Sheets are the following investments that have been recorded on the equity method of accounting: o A 33.33 percent interest (see Note 18) in Millennium Pipeline Company, L.P., a Texas limited partnership, which owns and operates an oil pipeline in the Gulf Coast region of Texas. The Company has a carrying amount in the investment of $7.0 million and $6.9 million as of December 31, 2001 and 2000, respectively. The partnership had assets of $23.8 million and $22.0 million, liabilities of $2.8 million and $1.0 million as of December 31, 2001 and 2000, and net income of $3.4 million and $2.8 million during 2001 and 2000, respectively. o At 12.6 percent, 6.9 percent and 5.3 percent interest in Energy Investors Fund, L.P., Energy Investors Fund II, L.P., and Project Finance Fund III, L.P., respectively, which in turn have investments in numerous electric generating facilities in the United States and elsewhere. The Company has a carrying amount in the investment of $10.0 million and $8.4 million at December 31, 2001 and 2000, respectively, which includes $1.9 million and $2.1 million, respectively, that represents the cost of the investment over the underlying net assets of the funds. This excess is being amortized over 10 years. As of and for the year ended December 31, 2001, the funds had assets of $215.1 million, liabilities of $0.7 million and net income of $37.2 million. As of, and for the year ended December 31, 2000, the funds had assets of $186.8 million, liabilities of $16.0 million and net income of $27.1 million. o A 50 percent interest in two natural gas-fired co-generation facilities located in Rupert and Glenns Ferry, Idaho. The Company's carrying amount in the investment is $3.9 million and $4.1 million as of December 31, 2001 and 2000, respectively, which includes $0.5 million that represents the cost of the investment over the value of the underlying net assets of the projects. This excess is being amortized over 19 years. As of and for the year ended December 31, 2001, these projects had assets of $25.6 million, liabilities of $19.0 million and a net loss of $(0.4) million. As of, and for the year ended December 31, 2000, these projects had assets of $26.0 million, liabilities of $18.7 million and net income of $0.9 million. o A direct and indirect ownership of approximately 53 percent (32 percent in 2000) representing 50 percent voting control, of Harbor Cogeneration Company (see Note 18). Harbor Cogeneration owns a 98 megawatt gas-fired plant (expanded from 80 megawatts in 2000) located in Wilmington, California. At December 31, 2001 and 2000, the Company's carrying amount in the investment was $47.9 million and $42.2 million, respectively, which includes $12.2 million and $13.7 million, respectively, which represents the cost of the investment over the value of the underlying net assets of Harbor. This excess is being amortized over 15 years. As of and for the year ended December 31, 2001, Harbor had assets of $51.4 million, liabilities of $0.4 million and net income of $10.1 million. As of, and for the year ended December 31, 2000, Harbor had assets of $41.7 million, liabilities of $0.8 million and net income of $28.8 million. (4) COMMON STOCK Common Stock Offering During 2001, the Company completed a public offering of its common stock through which approximately 3.4 million shares were sold at $52 per share. Net proceeds were approximately $163 million after commissions and expenses. The proceeds were used to repay a portion of current indebtedness under revolving credit facilities, to fund various power plant construction costs and for general corporate purposes. Employee Stock Incentive and Employee Stock Purchase Plans The Company has several employee stock incentive plans (Stock Incentive Plans), which allow for the granting of stock options with exercise prices equal to the stock's fair market value on the date of grant, and an employee stock purchase plan (ESPP Plan). The Company accounts for such plans under APB No. 25, and has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock Based Compensation" (SFAS 123). Accordingly, no compensation cost has been recognized. 68
The Company may grant options for up to 2,200,000 shares of common stock under the Stock Incentive Plans. The Company has 1,037,882 shares available to grant at December 31, 2001. The option exercise price equals the fair market value of the stock on the day of the grant. The options granted vest one-third a year for three years and all expire after ten years from the grant date. A summary of the status of the stock option plans at December 31, 2001, 2000 and 1999, and changes during the years then ended are as follows: <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price ------ ----- ------ ----- ------ ----- <S> <C> <C> <C> <C> <C> <C> Balance at beginning of year 914,917 $23.43 431,450 $21.35 292,700 $20.29 Granted 203,000 $37.09 492,500 $25.22 140,250 $23.58 Forfeited (30,834) $22.13 (4,000) $23.25 (1,500) $23.06 Exercised (94,211) $20.41 (5,033) $21.33 - $ - ------- ------- ------- Balance at end of year 992,872 $26.55 914,917 $23.43 431,450 $21.35 ======= ======= ======= Exercisable at end of year 445,252 $22.76 292,891 $20.43 182,400 $19.19 ======= ======= ======= </TABLE> Details of outstanding options at December 31, 2001 are as follows: <TABLE> <CAPTION> Weighted Average Option Exercise Shares Weighted Average Remaining Weighted Average Prices Outstanding Exercise Price Contractual Life Shares Exercisable Exercise Price ----- ----------- -------------- ---------------- ------------------ -------------- <S> <C> <C> <C> <C> <C> $16.67 to $25.00 680,872 $21.75 7.4 years 407,600 $21.45 $25.01 to $37.50 151,000 $31.04 9.8 years 3,166 $28.63 $37.51 to $55.36 161,000 $42.65 9.1 years 34,486 $37.69 </TABLE> The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model. The weighted average fair value of the options granted and the assumptions used to estimate the fair value of options are as follows: <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- <S> <C> <C> <C> Weighted average fair value of options at grant date $10.77 $3.88 $4.16 Weighted average risk-free interest rate 5.92% 6.30% 6.68% Weighted average expected price volatility 34.92% 20.60% 19.85% Weighted average expected dividend yield 2.90% 4.20% 4.50% Expected life in years 10 10 10 </TABLE> Had compensation cost been determined consistent with SFAS 123, the Company's net income and earnings per share would have been reduced to the following pro forma amounts for the years ended December 31 (unaudited): <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- (in thousands, except per share amounts) Net income available for common: <S> <C> <C> <C> As reported $87,550 $52,770 $37,067 Pro forma $86,845 $52,432 $36,877 Earnings per share (basic and diluted): As reported - basic $ 3.45 $ 2.39 $1.73 - diluted $ 3.42 $ 2.37 $1.73 Pro forma - basic $ 3.42 $ 2.38 $1.72 - diluted $ 3.39 $ 2.35 $1.72 </TABLE> 69
The Company maintains the ESPP Plan under which it sells shares to employees at 90 percent of the stock's market price on the offering date. The Company issued 48,368, 21,394 and 19,565 shares of common stock under the ESPP Plan in 2001, 2000 and 1999, respectively. At December 31, 2001, 177,808 shares are reserved and available for issuance under the ESPP Plan. The fair value per share of shares sold in 2001 was $22.50 on the offering date. Employee Stock Awards During 2001, the Company issued a total of 36,550 common shares as a stock bonus award to its non-officer employees. The bonus was grossed up to cover related employee taxes. The total pre-tax compensation charge recognized by the Company was $1.9 million, which is based on the market value of the stock on the grant date. Additionally, approximately 18,000 common shares will be issued at the two-year anniversary date of the original award, contingent on certain vesting restrictions. Pre-tax compensation cost related to this portion of the award is estimated to be $0.9 million and is being expensed over the two-year vesting period. During 2001, the Company issued 12,177 restricted common shares (net of 4,512 common shares forfeited) to certain officers. The shares carry a restriction on the officer's ability to sell the shares, until the shares vest. The shares vest one-third per year over three years, contingent on employment. Pre-tax compensation cost related to the award was $0.7 million, which is being expensed over the three-year vesting period. Nonemployee stock award During 2001, the Company issued 100,000 common shares as a charitable contribution to the newly formed not-for-profit entity, Black Hills Corporation Foundation. The charitable contribution cost included in "Other, net" on the 2001 Consolidated Statement of Income was $3.1 million, which is based on the stock market value on the grant date. Dividend Reinvestment and Stock Purchase Plan The Company has a Dividend Reinvestment and Stock Purchase Plan under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. The Company purchased shares on the open market in 2001, 2000 and 1999. At December 31, 2001, 1,290,797 shares of unissued common stock were available for future offerings under the Plan. (5) PREFERRED STOCK The Company has 25,000,000 authorized shares of no-par preferred stock. During 2001 and 2000, the Company issued 5,177 preferred shares in the Indeck Capital acquisition and the related "earn-out" provisions. The preferred shares issued are non-voting, cumulative, no par shares with a dividend rate equal to 1 percent per annum per share, computed on the basis of $1,000 per share plus an amount equal to any dividend declared payable with respect to the common stock, multiplied by the number of shares of common stock into which each share of preferred stock is convertible. The record and payment dates are the same as the record and payment dates with respect to the payment of dividends on common stock. No dividend may be declared or paid with respect to common stock unless such a dividend is declared and paid with respect to the preferred stock. The preferred stock is senior to the common stock in liquidation events. The Company may redeem the preferred stock in whole or in part, at any time solely at its option. The redemption price per share for the preferred stock shall be $1,000 per share plus all accrued and unpaid dividends. Each share of the preferred stock is convertible at the option of the holder into common stock at any time prior to July 7, 2005 and automatically converted into common stock on July 7, 2005. Each share of preferred stock is convertible into 28.57 common shares. If the Company delivers a notice of redemption, the conversion price shall be adjusted to equal the lesser of (i) the conversion price then in effect, and (ii) the current market price on the redemption notice date. 70
(6) LONG-TERM DEBT Long-term debt outstanding at December 31 is as follows (in thousands): <TABLE> <CAPTION> 2001 2000 ---- ---- <S> <C> <C> First mortgage bonds: 6.50% due 2002 $ 15,000 $ 15,000 9.00% due 2003 2,176 3,215 8.06% due 2010 30,000 30,000 9.49% due 2018 4,840 5,130 9.35% due 2021 33,300 35,000 8.30% due 2024 45,000 45,000 --------- --------- 130,316 133,345 --------- --------- Other long-term debt: Pollution control revenue bonds at 6.7% due 2010 12,300 12,300 Pollution control revenue bonds at 7.5% due 2024 12,200 12,200 Other 3,870 3,911 --------- --------- 28,370 28,411 --------- --------- Project financing floating rate debt (a): Fountain Valley project at 3.29% (b) due 2006 144,581 - Hudson Falls at 3.7% (b) due 2010 69,479 74,147 South Glens Falls at 3.7% (b) due 2009 24,008 26,124 Valmont and Arapahoe at 3.31% (b) due 2010 54,948 59,025 --------- --------- 293,016 159,296 --------- --------- Total long-term debt 451,702 321,052 Less current maturities (35,904) (13,960) --------- --------- Net long-term debt $415,798 $307,092 ========= ========= </TABLE> - --------------- (a) Approximately 74 percent of the December 31, 2001 balance has been hedged with interest rate swaps moving the floating rates to fixed rates with a weighted average interest rate of 5.85 percent (see Note 2-Risk Management Activities). (b) Interest rates are presented as of December 31, 2001. Substantially all of the Company's utility property is subject to the lien of the indenture securing its first mortgage bonds. First mortgage bonds of the Company may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. Project financing debt is non-recourse debt collateralized by a mortgage on each respective project's land and facilities, leases and rights, including rights to receive payments under long-term purchase power contracts. Certain debt instruments of the Company and its subsidiaries contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with or have obtained amendments and waivers effective at December 31, 2001. Scheduled maturities of long-term debt for the next five years are: $35.9 million in 2002, $22.4 million in 2003, $23.1 million in 2004, $24.7 million in 2005 and $137.3 million in 2006. (7) NOTES PAYABLE The Company has committed lines of credit with various banks totaling $400 million at December 31, 2001 and $290 million at December 31, 2000. At December 31, 2001, these lines consist of a $200 million revolving credit facility with a term of 364 days, which terminates August 27, 2002, and a $200 million revolving credit facility with a term of three years, which terminates on August 27, 2004. The Company had $360 million of borrowings and $33.0 million of letters of credit and $211 million of borrowings and $20.6 million of letters of credit issued on the lines at December 31, 2001 and 2000, respectively. The Company had no compensating balance requirements associated with these lines of credit. 71
The above facilities contain ratings trigger provisions that, if violated, would be considered an event of default and would allow the lender to terminate the remaining commitment and accelerate the principal and interest outstanding to become immediately due. The Company would be considered in violation of these ratings trigger provisions if its Standard & Poor's (S&P) Rating ceases to be at least BBB- or its Moody's Rating ceases to be at least Baa3. In addition, certain of the Company's interest rate swap agreements with a $150.0 million notional amount and a $0.7 million fair value at December 31, 2001 include cross-default provisions. These provisions would allow the counterparty the right to terminate the swap agreement and liquidate at a prevailing market rate, in the event of default. The Company's S&P and Moody's Ratings were BBB and A3, respectively at December 31, 2001. In addition to the above lines of credit, at December 31, 2001, Enserco Energy (Enserco) has a $75.0 million ($90.0 million at December 31, 2000) uncommitted, discretionary line of credit to provide support for the purchases of natural gas. The line of credit is secured by all of Enserco's assets. The Company and its other subsidiaries provide no guarantees to the lender. At December 31, 2001 and 2000, there were outstanding letters of credit issued under the facility of $36.2 million and $69.8 million, respectively, with no borrowing balances on the facility. Black Hills Energy Resources (BHER) has a $25.0 million uncommitted, discretionary credit facility secured by all of its assets. The transactional line of credit provides credit support for the purchases of crude oil of BHER. The Company and its other subsidiaries provide no guarantees to the lender. At December 31, 2001 and 2000, BHER had letters of credit outstanding of $4.4 million and $8.5 million, respectively, with no borrowing balances on the facility. Our credit facilities contain certain restrictive covenants. The Company and its subsidiaries had complied with all the covenants at December 31, 2001. Interest rates under the facility borrowings vary and are based, at the option of the Company at the time of the loan origination, on either (i) a prime based borrowing rate varying from prime rate (4.75 percent at December 31, 2001) to prime rate plus 1.0 percent, or (ii) on a London Interbank Offered Rate (LIBOR) based borrowing rate varying from LIBOR plus 0.6 percent to LIBOR plus 0.625 percent. The one-month LIBOR rate at December 31, 2001 was 1.87 percent. In addition to interest on outstanding borrowings, the credit facilities contain a 0 percent to 0.15 percent annual facility fee on the total facility amount, and an annual utilization fee ranging from 0 percent to 0.125 percent of the total used facility amount. The Company has entered into floating-to-fixed interest rate swaps to hedge a portion of its exposure to interest rate fluctuations with the above floating rate obligations. See Note 2 for further details. (8) FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of the Company's financial instruments are as follows: <TABLE> <CAPTION> 2001 2000 ---- ---- (in thousands) Carrying Amount Fair Value Carrying Amount Fair Value --------------- ---------- --------------- ---------- <S> <C> <C> <C> <C> Cash and cash equivalents $ 29,666 $ 29,666 $ 24,913 $ 24,913 Securities available-for-sale $ 3,550 $ 3,550 $ 2,113 $ 2,113 Derivative financial instruments - assets $ 46,210 $ 46,210 $ 68,292 $ 68,292 Derivative financial instruments - liabilities $ 50,818 $ 50,818 $ 65,960 $ 65,960 Notes payable $361,240 $361,240 $211,679 $211,679 Long-term debt $451,702 $469,787 $321,052 $337,446 </TABLE> The following methods and assumptions were used to estimate the fair value of each class of the Company's financial instruments. Cash and Cash Equivalents The carrying amount approximates fair value due to the short maturity of these instruments. 72
Securities Available-for-Sale The fair value of the Company's investments equals the quoted market price when available and a quoted market price for similar securities if a quoted market price is not available. The Company has classified all of its marketable securities as available-for-sale as of December 31, 2001 and 2000. An unrealized gain on the Company's investments of $1.4 million and an unrealized loss of $0.8 million was recorded as of December 31, 2001 and 2000, respectively. Derivative Financial Instruments These instruments are carried at fair value. Descriptions of the various instruments the Company uses and the valuation method employed are available in Note 2 of these Consolidated Financial Statements. Notes Payable The carrying amount approximates fair value due to their variable interest rates with short reset periods. Long-Term Debt The fair value of the Company's long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. The Company's outstanding bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for the Company to call and refinance the bonds. (9) JOINTLY OWNED FACILITY The Company owns a 20 percent interest and Pacific Power owns an 80 percent interest in the Wyodak Plant (Plant), a 330 megawatt coal-fired electric generating station located in Campbell County, Wyoming. Pacific Power is the operator of the Plant. The Company receives 20 percent of the Plant's capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2001, the Company's investment in the Plant included $71.7 million in electric plant and $22.8 million in accumulated depreciation, and is included in the corresponding captions in the accompanying Consolidated Balance Sheets. The Company's share of direct expenses of the Plant was $5.9 million, $5.6 million and $4.9 million for the years ended December 31, 2001, 2000 and 1999, respectively, and is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income. As discussed in Note 10, the Company's coal mining subsidiary, Wyodak Resources, supplies coal to the Plant under an agreement expiring in 2022. This coal supply agreement is collateralized by a mortgage on and a security interest in some of Wyodak Resources' coal reserves. Under the coal supply agreement, PacifiCorp is obligated to purchase a minimum of 1,500,000 tons of coal each year of the contract term, subject to adjustment for planned outages. Wyodak Resources' sales to the Plant were $21.0 million, $23.2 million and $24.9 million for the years ended December 31, 2001, 2000 and 1999, respectively. (10) COMMITMENTS AND CONTINGENCIES Off Balance Sheet Lease The Company's subsidiary, Black Hills Generation, has entered into an Agreement for Lease and Lease with Wygen Funding, Limited Partnership for the Wygen Plant, a 90 megawatt coal-fired power plant under construction in Campbell County, Wyoming. Wygen Funding is a special purpose entity that owns the Wygen Plant and has financed the project. Total cost of the project is estimated to be approximately $130 - $140 million. Neither Wygen Funding, its owners, nor its officers are related to the Company, and other than the lease transaction and obligations incurred as a result of this transaction, there is no obligation to provide additional funding or issue securities to Wygen Funding. Lease payments are based on final construction and financing costs and are currently estimated to be approximately $6.5 million per year based on five-year treasury rates. Lease payments will begin after substantial completion of construction scheduled for first quarter 2003. The lease will be accounted for as an operating lease. The initial lease term is five years with two five-year renewal options and includes a purchase option equal to the adjusted acquisition cost. The adjusted acquisition cost is essentially equal to the final construction cost of the project. If the Company elects to terminate or not renew the lease and not purchase the project, then it must make a termination payment equal to the lesser of 83.5 percent of the adjusted acquisition cost or the shortfall of proceeds received from the sale of the project. Black Hills Corporation has guaranteed the Agreement for Lease and Lease. 73
Power Purchase Agreement - Pacific Power In 1983, the Company entered into a 40 year power purchase agreement with Pacific Power providing for the purchase by the Company of 75 megawatts of electric capacity and energy from Pacific Power's system. An amended agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5 megawatts per year starting in 2000). The price paid for the capacity and energy is based on the operating costs of one of Pacific Power's coal-fired electric generating plants. Costs incurred under this agreement were $13.9 million in 2001, $14.6 million in 2000 and $17.8 million in 1999. Long-Term Power Sales Agreements The Company, through its subsidiaries, has the following significant long-term power sales contracts: o The Company has long-term power sales contracts with the Public Service Company of Colorado (PSCC) for the output of several of its plants. All of the output of the Company's Fountain Valley, Arapahoe and Valmont gas-fired facilities, totaling 400 megawatts in operation plus an additional 50 megawatts combined-cycle expansion currently under construction, is included under the contracts which expire in 2012. The contracts are tolling arrangements in which the Company assumes no fuel price risk. o Beginning September 1, 2001, the Company has a ten year power sales contract with Cheyenne Light, Fuel and Power (CLF&P) for the output of the 40 megawatt gas-fired Gillette CT. The contract is a tolling arrangement in which the Company assumes no fuel risk. In addition, the Company entered into a ten year contract with CLF&P for 60 megawatts of contingent capacity from the 90 megawatt Wygen Plant, currently under construction. Twenty megawatts of the remaining capacity of this plant has been sold under a ten year contract with the Municipal Electric Agency of Nebraska. o The Company has secured long-term contracts for the output of the 277 megawatt Las Vegas facility that was acquired during the third quarter of 2001. See Note 15 for a description of the facility and the related long-term contracts. o Various long-term contracts with Niagara Mohawk Power Corporation have been entered into to sell the output of several of the Company's hydroelectric projects located in upstate New York. The Company's net ownership of capacity under contract is approximately 21 megawatts with contracts expiring between 2028 and 2032. There are additional contracts on plants with a net ownership capacity of approximately 21 megawatts that expire during 2002 and 2003. Reclamation Liability Under its mining permit, Wyodak Resources is required to reclaim all land where it has mined coal reserves. The cost of reclaiming the land is accrued as the coal is mined. While the reclamation process takes place on a continual basis, much of the reclamation occurs over an extended period after the area is mined. Approximately $0.7 million is charged to operations as reclamation expense annually. As of December 31, 2001, accrued reclamation costs included in Other liabilities on the accompanying Consolidated Balance Sheets were approximately $18.2 million. Legal Proceedings Settlement On April 3, 2001, the Company reached a settlement of ongoing litigation with PacifiCorp filed in the United States District Court, District of Wyoming, (File No. 00CV-155B). The litigation concerned the parties' rights and obligations under the Further Restated and Amended Coal Supply Agreement dated May 5, 1987, under which PacifiCorp purchased coal from the Company's coal mine to meet the coal requirements of the Wyodak Power Plant. The Settlement Agreement provided for the dismissal of the litigation, with prejudice, coupled with the execution of several new coal-related agreements between the parties discussed below. The Company believes the value of the Settlement Agreements is equal to the net present value of the litigated Further Restated and Amended Coal Supply Agreement. New Restated and Amended Coal Supply Agreement: Effective January 1, 2001, the parties agreed to terminate the Further Restated and Amended Coal Supply Agreement, and replace it with the New Restated and Amended Coal Supply Agreement (New Agreement). The New Agreement began on January 1, 2001, and extends to December 31, 2022. Under the New Agreement, the Company received an extension of sales beyond the June 8, 2013 term of the former Coal Supply Agreement. PacifiCorp will receive a price reduction for each ton of coal purchased. The minimum purchase obligation under the New Agreement increased to 1,500,000 tons of coal for each calendar year of the contract term, subject to adjustment for planned 74
outages. The New Agreement further provided for a special one-time payment by PacifiCorp in the amount of $7.3 million, which was received in August 2001. This payment primarily related to disputed billings under the previous agreement and a value transfer premium. Of this payment, $5.6 million was recognized currently and is included in "Other, net" non-operating income on the accompanying Consolidated Statements of Income, $1.0 million was previously recognized in revenues and the remaining $0.7 million is being recognized as sales are made under the New Agreement. Coal Option Agreement: The term of this agreement began October 1, 2001, and extends until December 31, 2010. The agreement provides that PacifiCorp shall purchase 1,400,000 tons of coal during the period of October 1, 2001 through December 31, 2002 and 1,000,000 tons of coal in 2003 at a fixed price. The agreement further provides the Company with a "put" option for 2002 and 2003 under which the Company may sell to PacifiCorp up to 500,000 tons of coal from the Wyodak Mine at a market based price. For each calendar year from January 1, 2004 through 2010, the put option is increased to a maximum of 1,000,000 tons at a market based price. The "put" tonnages will be reduced or offset for quantities of an enhanced coal known as "K-Fuel" purchased by PacifiCorp under the KFx Facility Output Agreement. Additionally, for each calendar year during which the Company is selling to PacifiCorp K-Fuel under the KFx Facility Output Agreement described below, and in which the Company has not exercised its "put" option, PacifiCorp may elect to purchase an equal amount of tonnage from the Company's coal reserves to use in a 50/50 blend with the K-Fuel, up to 500,000 tons per year in 2002 through 2007 at a market based price with a fixed floor. Asset Option Agreement: This agreement provides PacifiCorp an option to purchase a 10 percent interest in the KFx facility or the legal entity that owns the KFx facility at a market based price. Sale of North Conveyor System: The Company sold the "North Conveyor System" to PacifiCorp, which served as the backup coal delivery system for the Wyodak Power Plant which resulted in a $2.6 million gain that is included in "Other, net" non-operating income on the accompanying Consolidated Statements of Income. KFx Facility Output Agreement: The KFx plant is a coal enhancement facility the Company owns located near its Wyodak Coal Mine. The KFx plant was built to produce an enhanced coal known as "K-Fuel." Assuming the plant becomes operational, PacifiCorp agrees to purchase K-Fuel for a term beginning January 1, 2002, and extending to December 31, 2007. If the plant is not operational on or before December 31, 2003, the agreement will become void. Under this agreement, PacifiCorp agrees to purchase the output of K-Fuel from the KFx plant, up to a maximum of 500,000 tons for each calendar year from 2002 through 2007 at fixed price with market based escalation. Wyodak reserves the right to sell up to a total of 100,000 tons from the output of the KFx plant to other customers during the same time period. Ongoing Litigation The Company is subject to various legal proceedings and claims, which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the consolidated financial position or results of operations of the Company. (11) EMPLOYEE BENEFIT PLANS Defined Benefit Pension and Other Postretirement Plans The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of the Company and those of the following subsidiaries, Black Hills Power, Wyodak Resources Development Corp., Black Hills Exploration and Production and Daksoft who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company's funding policy is in accordance with the federal government's funding requirements. The Plan's assets are held in trust and consist primarily of equity securities and cash equivalents. 75
Net pension income for the Plan was as follows: <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- (in thousands) <S> <C> <C> <C> Service cost $ 945 $ 967 $ 1,174 Interest cost 3,080 2,885 2,598 Estimated return on assets (5,814) (5,257) (4,162) Amortization of transition amount - (90) (90) Amortization of prior service cost 231 231 89 Recognized net actuarial gain (556) (537) - ------- ------- ------- Net pension income $(2,114) $(1,801) $ (391) ======= ======= ======= Actuarial assumptions: Discount rate 7.5% 7.5% 6.75% Expected long-term rate of return on assets 10.5% 10.5% 10.5% Rate of increase in compensation levels 5.0%* 5.0% 5.0% </TABLE> - -------------------------- *The rate of increase in compensation levels for 2001 was changed from a single rate assumption for all ages to an age-based salary scale assumption resulting in a weighted average increase of 5.0 percent. A reconciliation of the beginning and ending balances of the projected benefit obligation is as follows: 2001 2000 ---- ---- (in thousands) Beginning projected benefit obligation $41,314 $39,615 ------- ------- Service cost 945 967 Interest cost 3,080 2,885 Actuarial gains (167) (48) Benefits paid (2,156) (2,105) ------- ------- Net increase 1,702 1,699 ------- ------- Ending projected benefit obligation $43,016 $41,314 ======= ======= A reconciliation of the fair value of Plan assets as of October 1 of each year is as follows: 2001 2000 ---- ---- (in thousands) Beginning market value of plan assets $56,560 $51,212 Benefits paid (2,156) (2,105) Investment income (loss) (13,136) 7,453 ------- ------- Ending market value of plan assets $41,268 $56,560 ======= ======= Funding information for the Plan as of October 1 each year was as follows: 2001 2000 ---- ---- (in thousands) Fair value of plan assets $41,268 $56,560 Projected benefit obligation (43,016) (41,314) ------- ------- Funded status (1,748) 15,246 Unrecognized: Net (gain) loss 5,527 (13,812) Prior service cost 1,823 2,054 ------- ------- Prepaid pension cost $ 5,602 $ 3,488 ======= ======= Accumulated benefit obligation $35,695 $33,374 ======= ======= 76
The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. Expenses recognized under the plans were $0.5 million during 2001 and 2000 and $0.4 million during 1999. Employees who are participants in the Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits coverage. These benefits are subject to premiums, deductibles, copayment provisions and other limitations. The Company may amend or change the Plan periodically. The Company is not pre-funding its retiree medical plan. The net periodic postretirement cost was as follows: <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- (in thousands) <S> <C> <C> <C> Service cost $ 289 $ 282 $225 Interest cost 507 523 362 Amortization of transition obligation 150 150 150 Loss 21 68 1 ------- ------- ---- $ 967 $ 1,023 $738 ======= ======= ==== </TABLE> Funding information as of October 1 was as follows: <TABLE> <CAPTION> 2001 2000 ---- ---- (in thousands) <S> <C> <C> Accumulated postretirement benefit obligation: Retirees $3,186 $2,478 Fully eligible active participants 1,803 1,203 Other active participants 3,963 3,172 ------ ------ Unfunded accumulated postretirement benefit obligation 8,952 6,853 Unrecognized net loss (2,792) (1,001) Unrecognized transition obligation (1,648) (1,797) ------ ------ Accrued postretirement cost $4,512 $4,055 ====== ====== </TABLE> For measurement purposes, an 8.0 percent annual rate of increase in healthcare benefits was assumed for 2001; the rate was assumed to decrease gradually to 6.0 percent in 2005 and remain at that level thereafter. The healthcare cost trend rate assumption has a significant effect on the amounts reported. A one percent increase in the healthcare cost trend assumption would increase the service and interest cost $1.0 million or 23.8 percent and the net periodic postretirement cost $1.2 million or 28.1 percent. A one percent decrease would reduce the service and interest cost by $0.7 million or 18.3 percent and decrease the net periodic postretirement cost $0.8 million or 17.2 percent. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7.5 percent. Defined Contribution Plan The Company also sponsors a 401(k) savings plan for eligible employees. Participants elect to invest up to 20 percent of their eligible compensation on a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for employees covered by the collective bargaining agreement), the Company provides a matching contribution of 100 percent of the employee's tax-deferred contribution up to a maximum 3 percent of the employee's eligible compensation. Matching contributions vest at 20 percent per year and are fully vested when the participant has 5 years of service with the Company. The Company's matching contributions totaled $0.9 million for 2001 and $0.6 million for 2000. 77
(12) OTHER COMPREHENSIVE INCOME The following table displays the related tax effects allocated to each component of Other Comprehensive Income (Loss) for the year ended December 31, 2001: <TABLE> <CAPTION> Pre-tax Tax Expense Net-of-tax Amount (Benefit) Amount ------ --------- ------ (in thousands) <S> <C> <C> <C> Unrealized gain on securities during the year $1,775 $ 337 $ 1,438 Net change in fair value of derivatives designated as cash flow hedges (net of minority interest share of $2,875) (7,299) (2,932) (4,367) ------- ------- ------- Other comprehensive loss $(5,524) $(2,595) $(2,929) ======= ======= ======= </TABLE> Items of other comprehensive income (loss) were not significant in 2000 or 1999. (13) INCOME TAXES Income tax expense for the years indicated was: 2001 2000 1999 ---- ---- ---- (in thousands) Current: Federal $38,730 $27,140 $13,267 State 2,022 1,281 231 ------- ------- ------- 40,752 28,421 13,498 Deferred 10,224 2,576 2,931 Tax credits (432) (639) (640) ------- ------- ------- $50,544 $30,358 $15,789 ======= ======= ======= The temporary differences, which gave rise to the net deferred tax liability, were as follows: <TABLE> <CAPTION> Years ended December 31, 2001 2000 ---- ---- (in thousands) <S> <C> <C> Deferred tax assets: Accelerated depreciation, amortization and other plant-related differences $ 735 $ 5,393 Regulatory asset 2,169 2,507 Valuation reserves 3,099 508 Mining development and oil exploration 1,501 3,605 Employee benefits 4,178 3,308 Items of other comprehensive income 4,540 - Other 6,176 3,203 ------- ------- 22,398 18,524 ------- ------- Deferred tax liabilities: Accelerated depreciation and other plant-related differences 74,449 63,559 Regulatory liability 1,425 1,447 Mining development and oil exploration 8,650 8,450 Employee benefits 2,152 1,347 Derivative fair value adjustments 2,000 - Items of other comprehensive income 1,945 - Other 7,175 6,400 ------- ------- 97,796 81,203 ------- ------- Net deferred tax liability $75,398 $62,679 ======= ======= </TABLE> 78
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- <S> <C> <C> <C> Federal statutory rate 35.0% 35.0% 35.0% State income tax 1.4 1.4 - Amortization of investment tax credits - (1.0) (0.9) Percentage depletion in excess of cost (2.2) (1.1) (1.6) Other 2.3 2.2 (2.6) ---- ---- ---- 36.5% 36.5% 29.9% ==== ==== ==== </TABLE> 79
(14) BUSINESS SEGMENTS The Company's reportable segments are those that are based on the Company's method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of December 31, 2001, substantially all of the Company's operations and assets are located within the United States. The Company's operations are conducted through six business segments that include: Electric, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; Integrated Energy consisting of: Mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and Gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region, Texas, California and other states; Fuel Marketing, which markets natural gas, oil, coal and related services to customers in the East Coast, Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions markets; Power Generation, which produces and sells power to wholesale customers; and Communications, which primarily markets communications and software development services. December 31: 2001 2000 ---- ---- (in thousands) Total assets Integrated energy: Coal mining $ 42,198 $ 47,038 Oil and gas 57,766 36,376 Fuel marketing 144,586 340,969 Power generation 867,203 375,801 Electric utility 421,280 412,213 Communications 123,634 106,884 Corporate 2,100 1,039 ---------- ---------- Total assets $1,658,767 $1,320,320 ========== ========== Capital expenditures Integrated energy: Coal mining $ 7,855 $ 2,419 Oil and gas 27,114 9,259 Fuel marketing 166 273 Power generation 497,653 76,932* Electric utility 41,313 25,257 Communications 20,030 59,377 Corporate 25 - --------- ---------- Total capital expenditures $ 594,156 $ 173,517 ========= ========== -------------------------------------------------------------------- *Excludes the non-cash acquisition of Indeck Capital, Inc. as described in Note 15. Property, plant and equipment Integrated energy: Coal mining $ 63,592 $ 57,720 Oil and gas 104,926 77,812 Fuel marketing 790 1,559 Power generation 698,175 294,805 Electric utility 569,368 530,380 Communications 129,748 109,718 Corporate 25 135 ---------- ---------- Total property, plant and equipment $1,566,624 $1,072,129 ========== ========== 80
<TABLE> <CAPTION> December 31: 2001 2000 1999 ---- ---- ---- (in thousands) <S> <C> <C> <C> External operating revenues Integrated energy: Coal mining $ 20,551 $ 20,880 $ 23,431 Oil and gas 30,619 19,183 13,052 Fuel marketing 1,169,232 1,353,795 614,228 Power generation 94,294 39,331 - Electric utility 212,355 173,308 133,222 Communications 20,258 7,689 278 ---------- ---------- -------- Total external operating revenues $1,547,309 $1,614,186 $784,211 ========== ========== ======== Intersegment operating revenues Integrated energy: Coal mining (a) $ 11,249 $ 9,650 $ 7,664 Oil and gas 2,789 1,145 - Fuel marketing 15,817 13,175 - Power generation - 329 - Communications 4,250 3,682 3,145 Intersegment eliminations (22,856) (18,331) (3,145) ---------- ---------- -------- Total intersegment operating revenues(a) $ 11,249 $ 9,650 $ 7,664 ========== ========== ======== -------------------------------------------------------------- (a) In accordance with the provisions of SFAS 71, intercompany coal sales are not eliminated. Depreciation, depletion and amortization Integrated energy: Coal mining $ 2,984 $ 3,525 $ 3,259 Oil and gas 7,806 4,071 2,953 Fuel marketing 724 644 2,757 Power generation 16,520 3,646 - Electric utility 15,773 14,966 15,552 Communications 9,944 6,012 546 Corporate 300 - - ---------- ---------- -------- Total depreciation, depletion and amortization $ 54,051 $ 32,864 $ 25,067 ========== ========== ======== Operating income (loss) Integrated energy: Coal mining $ 6,586 $ 8,794 $ 12,606 Oil and gas 15,193 7,906 3,978 Fuel marketing 54,071 23,774 (2,248) Power generation 27,455 20,374 (157) Electric utility 84,108 68,208 52,286 Communications (13,250) (12,486) (3,647) Corporate (3,984) (1,820) (927) ---------- ---------- -------- Total operating income (loss) $ 170,179 $ 114,750 $ 61,891 ========== ========== ======== </TABLE> 81
<TABLE> <CAPTION> December 31: 2001 2000 1999 ---- ---- ---- (in thousands) <S> <C> <C> <C> Interest income Integrated energy: Coal mining $ 8,125 $ 9,974 $ 2,709 Oil and gas 45 39 18 Fuel marketing 1,859 535 347 Power generation 8,992 4,085 101 Electric utility 4,858 5,658 1,190 Communications 15 657 1,050 Corporate 7,379 370 399 Intersegment eliminations (28,895) (14,243) (2,200) ----------- ---------- ----------- Total interest income $ 2,378 $ 7,075 $ 3,614 =========== ========== =========== Interest expense Integrated energy: Coal mining $ 5,752 $ 8,006 $ 1,260 Oil and gas 145 372 568 Fuel marketing 164 535 719 Power generation 33,593 11,911 111 Electric utility 15,780 17,411 13,830 Communications 5,789 6,245 1,155 Corporate 7,298 105 17 Intersegment eliminations (28,895) (14,243) (2,200) ----------- ---------- ----------- Total interest expense $ 39,626 $ 30,342 $ 15,460 =========== ========== =========== Income taxes Integrated energy: Coal mining $ 6,266 $ 2,660 $ 3,439 Oil and gas 4,930 2,609 968 Fuel marketing 21,326 9,323 50 Power generation 1,668 3,154 (58) Electric utility 24,255 19,469 12,446 Communications (6,561) (6,476) (807) Corporate (1,340) (381) (249) ----------- ---------- ----------- Total income taxes $ 50,544 $ 30,358 $ 15,789 =========== ========== =========== Net income (loss) available for common stock Integrated energy: Coal mining $ 11,591 $ 7,173 $ 9,715 Oil and gas 10,197 4,992 2,462 Fuel marketing 35,058 14,009 (185) Power generation 1,576 3,241 (109) Electric utility 45,238 37,100 27,362 Communications (12,300) (11,382) (968) Corporate (3,086) (1,175) (295) Intersegment eliminations (724) (1,188) (915) ----------- ---------- ----------- Total net income available for common stock $ 87,550 $ 52,770 $ 37,067 =========== ========== =========== </TABLE> 82
(15) ACQUISITIONS On April 11, 2001, the Company's power generation subsidiary, Black Hills Energy Capital, purchased the Fountain Valley facility, a 240 megawatt generation facility located near Colorado Springs, Colorado, featuring six LM-6000 simple-cycle, gas-fired turbines. The facility came on-line mid third quarter of 2001. The facility was purchased from Enron Corporation. Total cost of the project was approximately $183 million and has been financed primarily with non-recourse project debt. The Company has obtained an 11-year contract with Public Service of Colorado to utilize the facility for peaking purposes. The contract is a tolling arrangement in which the Company assumes no fuel risk. The transaction has been accounted for as an asset purchase recorded at cost. On August 31, 2001, Black Hills Energy Capital purchased a 277 megawatt gas-fired co-generation power plant project located in North Las Vegas, Nevada from Enron North America, a wholly owned subsidiary of Enron Corporation. The facility currently has a 53 megawatt co-generation power plant in operation. Most of the power from that facility is under a long-term contract expiring in 2024. The Company has sold 50 percent of this power plant to other parties; however, under generally accepted accounting principles the Company is required to consolidate 100 percent of this plant. The project also has a 224 megawatt combined-cycle expansion under way, which is 100 percent owned by the Company. The facility is scheduled to be fully operational in the third quarter of 2002 and will utilize LM-6000 technology. The power of the expansion is also under a long-term contract, which expires in 2017. This contract for the expansion requires the purchaser to provide fuel to the power plant when it is dispatched. The cost for the entire facility is expected to be approximately $330 million and the Company is in the process of obtaining long-term financing, which is expected to be primarily non-recourse project debt. The acquisition has been accounted for under the purchase method of accounting and, accordingly, the purchase price of approximately $205 million has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and the liabilities assumed as of the date of acquisition. Fair values in the allocation include assets acquired of approximately $157 million (excluding goodwill and other intangibles) and liabilities assumed of approximately $2.0 million. The estimated purchase price allocations are subject to adjustment, generally within one year of the date of the acquisition, should new or additional facts about the acquisitions become available, any changes to the preliminary estimates will be reflected as an adjustment to goodwill. The purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by approximately $57.0 million, which was recorded as long-lived intangible assets and goodwill. In addition, during 2001, the Company acquired an additional 31 percent interest and a 13 percent interest in its consolidated majority-owned subsidiaries, Black Hills North American Power Fund, L.P. and Indeck North American Power Partners, L.P., respectively, from minority shareholders. Total consideration paid was $15.9 million. Pro forma financial amounts reflecting the effects of the above acquisitions are not presented as such acquisitions were not significant to the Company's financial position or results of operations. On July 7, 2000, the Company acquired Indeck Capital, Inc. and merged it into its subsidiary, Black Hills Energy Capital, Inc. The acquisition was a stock transaction with the Company issuing 1,536,747 shares of common stock to the shareholders of Indeck priced at $21.98 per share, along with $4.0 million in preferred stock, resulting in a purchase price of $37.8 million. Additional consideration, consisting of common and preferred stock, may be paid in the form of an earn-out over a four-year period beginning in 2000. As of December 31, 2001, $3.6 million has been paid under the earn-out. The earn-out consideration is based on the acquired company's earnings during such period and cannot exceed $35.0 million in total. Additional consideration paid out under the earn-out is recorded as an increase to goodwill. The acquisition was accounted for under the purchase method of accounting and, accordingly, the purchase price was allocated to the acquired assets and liabilities based on estimates of the fair values of the assets purchased and the liabilities assumed as of the date of acquisition. Fair values in the allocation include assets acquired of $151.1 million (excluding goodwill) and liabilities assumed of $138.7 million. The purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by $25.4 million, which was recorded as goodwill and was being amortized over 25 years on a straight-line basis during 2001 and 2000. 83
In addition during 2000, the Company made several step-acquisitions resulting in consolidation of $169.5 million of assets and $138.8 million of liabilities. The related transactions are as follows: o Through various transactions, acquired an additional 27.11 percent interest in Indeck North American Power Fund, L.P. and an additional 46.66 percent interest in Indeck North American Power Partners, L.P., for $13.0 million in cash. o Acquired a 39.6 percent interest in each of Northern Electric Power Company, L.P. and South Glens Falls Limited Partnership for $4.2 million in cash. o Acquired substantially all of the partnership interests in Middle Falls Limited Partnership, Sissonville Limited Partnership and New York State Dam Limited Partnership for $12.9 million in cash. (16) OIL AND GAS RESERVES (Unaudited) Black Hills Exploration and Production has interests in 813 producing oil and gas properties in nine states. Black Hills Exploration and Production also holds leases on approximately 228,551 net undeveloped acres. The following table summarizes Black Hills Exploration and Production's quantities of proved developed and undeveloped oil and natural gas reserves, estimated using constant year-end product prices, as of December 31, 2001, 2000 and 1999, and a reconciliation of the changes between these dates. These estimates are based on reserve reports by Ralph E. Davis Associates, Inc., an independent engineering company selected by the Company. Such reserve estimates are based upon a number of variable factors and assumptions, which may cause these estimates to differ from actual results. <TABLE> <CAPTION> 2001 2000 1999 ---- ---- ---- Oil Gas Oil Gas Oil Gas --- --- --- --- --- --- (in thousands of barrels of oil and MMcf of gas) <S> <C> <C> <C> <C> <C> <C> Proved developed and undeveloped reserves: Balance at beginning of year 4,413 18,404 4,109 19,460 2,368 15,952 Production (446) (4,615) (352) (3,285) (309) (2,801) Additions 749 19,111 625 4,228 376 7,718 Property sales - - - - (164) (66) Revisions to previous estimates (661) (8,829) 31 (1,999) 1,838 (1,343) ------- ------- ------- ------- ------- ------- Balance at end of year 4,055 24,071 4,413 18,404 4,109 19,460 ======= ======= ======= ======= ======= ======= Proved developed reserves at end of year included above 2,962 22,420 3,047 16,418 2,819 14,391 ======= ======= ======= ======= ======= ======= Year-end prices (average well-head) $ 18.12 $ 2.05 $ 26.76 $ 8.05 $ 25.60 $ 1.99 ======= ======= ======= ======= ======= ======= </TABLE> 84
(17) QUARTERLY HISTORICAL DATA (Unaudited) The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results and market data for each quarter of 2001 and 2000. <TABLE> <CAPTION> First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- (in thousands, except per share amounts) <S> <C> <C> <C> <C> 2001: Operating revenues $561,693 $419,049 $302,398 $275,418 Operating income 61,580 64,005 29,439 15,155 Net income available for common stock 32,050 34,553 16,235 4,712 Earnings per common share: Basic 1.39 1.35 0.61 0.18 Diluted 1.37 1.34 0.61 0.18 Dividends paid per share 0.28 0.28 0.28 0.28 Common stock prices High 45.74 58.50 45.55 34.20 Low 31.00 39.50 27.76 26.00 2000: Operating revenues $247,959 $336,978 $453,231 $585,668 Operating income 16,872 15,200 42,519 40,159 Net income available for common stock 9,061 8,061 16,285 19,363 Earnings per common share: Basic 0.42 0.38 0.71 0.84 Diluted 0.42 0.38 0.71 0.83 Dividends paid per share 0.27 0.27 0.27 0.27 Common stock prices High 25.19 25.19 30.13 46.06 Low 20.44 20.88 22.00 27.00 </TABLE> (18) SUBSEQUENT EVENTS (Unaudited) On January 4, 2002, the Company closed on a $50.0 million bridge credit agreement. The credit agreement will supplement our revolving credit facilities in place at December 31, 2001 and has the same terms as those facilities with an expiration date of June 30, 2002. Outstanding borrowings under the agreement as of February 28, 2002 were $21.1 million. On March 8, 2002, the Company acquired an additional 67 percent ownership interest in Millennium Pipeline Company, L.P., which owns and operates a 200-mile pipeline. The pipeline has a capacity of approximately 65,000 barrels of oil per day, and transports imported crude oil from Beaumont, Texas to Longview, Texas, which is the transfer point to connecting carriers. The Company also acquired additional ownership interest in Millennium Terminal Company, L.P., which has 1.1 million barrels of crude oil storage connected to the Millennium Pipeline at the Oil Tanking terminal in Beaumont. The Millennium system is presently operating near capacity through shipper agreements. These acquisitions give the Company 100 percent ownership in the Millennium companies. Total cost of the acquisitions was $11.0 million and was funded through borrowings under short-term revolving credit facilities. On March 15, 2002, the Company closed on $135 million of senior secured financing for the Arapahoe and Valmont Facilities. These projects have a total of 210 megawatts in service and under construction and are located in the Denver, Colorado area. Proceeds from this financing were used to refinance $53.8 million of an existing seven-year senior secured term project-level facility, pay down approximately $50.0 million of short-term credit facility borrowings and approximately $31.0 million will be used for future project construction. 85
On March 15, 2002, the Company paid $25.7 million to acquire an additional 30 percent interest in the Harbor Cogeneration Facility (the Facility), a 98 megawatt gas-fired plant located in Wilmington, California. This acquisition was funded through borrowings under short-term revolving credit facilities and gives the Company an 83 percent ownership interest and voting control of the Facility. 86
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE No change of accountants or disagreements on any matter of accounting principles or practices or financial statement disclosure have occurred. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding our directors is incorporated herein by reference to the Proxy Statement for the Annual Shareholders' Meeting to be held May 29, 2002. EXECUTIVE OFFICERS Daniel P. Landguth, age 55, was elected Chairman of the Board and Chief Executive Officer in January 1991. Mr. Landguth also currently chairs the Executive Committee. He has over 30 years of experience with Black Hills. Mr. Landguth holds a B.S. degree in Electrical Engineering from the South Dakota School of Mines and Technology. Everett E. Hoyt, age 62, has been President and Chief Operating Officer since February 2001. Since 1989, he has been President and Chief Operating Officer of our electric utility business - a role he continues to play. Mr. Hoyt was elected to the Board of Directors in 1991. Prior to joining us, Mr. Hoyt was employed by NorthWestern Corporation for 16 years where he served as Senior Vice President-Legal and as a member of the Board of Directors. He holds a B.S. degree in Mechanical Engineering from the South Dakota School of Mines and Technology and a J.D. from the University of South Dakota School of Law. Thomas M. Ohlmacher, age 50, has been the President and COO of our Independent Energy Group since November 2001. He served as Senior Vice President-Power Supply and Power Marketing since January 30, 2001 and Vice President - Power Supply since August 1994. Prior to that, he held several positions with our company since 1974. Mr. Ohlmacher holds a B.S. in Chemistry from the South Dakota School of Mines and Technology. Mark T. Thies, age 38, has been our Senior Vice President and Chief Financial Officer since March 2000. From May 1997 to March 2000, he was our Controller. From 1990 to 1997, Mr. Thies served in a number of accounting positions with InterCoast Energy Company, an unregulated energy company and a wholly owned subsidiary of MidAmerican Energy Holdings Company. Mr. Thies holds B.A.s in Accounting and Business Administration from Saint Ambrose College and is a certified public accountant. Ronald D. Schaible, age 57, has been Senior Vice President of Communications of Black Hills Corporation and Vice President and General Manager of Black Hills FiberCom since October 1998. Mr. Schaible has more than 25 years experience in the telecommunications industry. From 1995 to 1998, he was Vice President and General Manager of the Kansas City and Missouri subsidiaries of Brooks Fiber Properties. Mr. Schaible was responsible for both network construction and operations in Kansas City. He holds a B.S. in Electrical Engineering from South Dakota State University. James M. Mattern, age 47, has been the Senior Vice President-Corporate Administration since September 1999, and was Vice President-Corporate Administration from January 1994 to September 1999. From 1997 to 1999, he was also Assistant to the CEO. Mr. Mattern has 12 years of experience with us. He holds a B.S. in Social Sciences and an M.S. in Administration from Northern State University. Steven J. Helmers, age 45, has been our General Counsel and Corporate Secretary since January 2001. Prior to joining us, Mr. Helmers was a shareholder with the Rapid City, South Dakota law firms of Truhe, Beardsley, Jensen, Helmers & VonWald, from 1997 to January 2001, and Lynn, Jackson, Schultz & Lebrun, P.C., from 1983 to 1997. He holds a J.D. from the University of South Dakota School of Law. 87
Roxann R. Basham, age 40, has been our Vice President-Controller since March 2000. From December 1997 to March 2000, she was Vice President-Finance and Secretary/Treasurer. From 1993 until December 1997, she served as our Secretary/Treasurer, and has a total of 16 years of experience with us. She holds a B.S. in Business Administration from the University of South Dakota and is a certified public accountant. David R. Emery, age 39, has been our Vice President-Fuel Resources since January 1997. From June 1993 to January 1997, he was General Manager of Black Hills Exploration and Production. Mr. Emery has 12 years of experience with us. He holds a B.S. in Petroleum Engineering from the University of Wyoming and an M.S. in Business Administration from the University of South Dakota. Kyle D. White, age 42, has been Vice President - Corporate Affairs since January 30, 2001 and Vice President-Marketing and Regulatory Affairs since July 1998. Mr. White served as Director-Strategic Marketing and Sales from 1993 to January 1998 and Vice President-Energy Services from January 1998 to July 1998. He has a total of 18 years of experience with us. Mr. White holds a B.S. and M.S. in Business Administration from the University of South Dakota. ITEM 11. EXECUTIVE COMPENSATION Information regarding management remuneration and transactions is incorporated herein by reference to our Proxy Statement for the Annual Shareholders' Meeting to be held May 29, 2002. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information regarding the security ownership of certain beneficial owners and management is incorporated herein by reference to our Proxy Statement for the Annual Shareholders' Meeting to be held May 29, 2002. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information regarding certain relationships and related transactions is incorporated herein by reference to our Proxy Statement for the Annual Shareholders' Meeting to be held May 29, 2002. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Consolidated Financial Statements Financial statements required by Item 14 are listed in the index included in Item 8 of Part II. 2. Schedules All schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in the Form 10-K. 88
<TABLE> <CAPTION> 3. Exhibits Exhibit Number Description ------- ------------------------------------------------------------------------------------ <S> <C> 2* Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.1* Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.2* Articles of Amendment of the Registrant (filed as an exhibit to the Registrant's Form 8-K filed on December 26, 2000). 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.4* Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A of the Registrant (filed as an exhibit to the Registrant's Form 8-K filed on December 26, 2000). 4.1* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 4.2* Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant's Form 10-K for 2000). 10.1* Agreement for Transmission Service and the Common Use of Transmission Systems dated January 1, 1986, among Black Hills Power, Inc., Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc. and Butte Electric Cooperative, Inc. (filed as Exhibit 10(d) to the Registrant's Form 10-K for 1987). 10.2* Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant's Form 10-K for 1992). 10.3* Coal Leases between Wyodak Resources Development Corp. and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant's Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant's Form 10-K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant's Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant's Form 10-K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant's Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant's Form 10-K for 1989). 10.4* Restated and Amended Coal Supply Agreement dated as of January 1, 2001 between Wyodak Resources Development Corp. and PacifiCorp (filed as Exhibit 10.4 to the Registrant's Form S-1 No. 333-57440). 10.5* Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant's Form 10-K for 1997). 10.6* Coal Supply Agreement for Wyodak Unit #2 dated February 3, 1983, and Ancillary Agreement dated February 3, 1982, between Wyodak Resources Development Corp., Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1983). Amendment to Agreement for Coal Supply for Wyodak #2 dated May 5, 1987 (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1987). 10.7* Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1987). 10.8* Marketing, Capacity and Storage Service Agreement between Black Hills Power, Inc. and PacifiCorp dated September 1, 1995 (filed as Exhibit 10(ag) to the Registrant's Form 10-K for 1995). 10.9* Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1997). 10.10* Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999). </TABLE> 89
<TABLE> <CAPTION> <S> <C> 10.11*+ Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 6, 2000 (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2000). 10.12*+ First Amendment to the Pension Equalization Plan of Black Hills Corporation dated January 30, 2001 (filed as Exhibit 10.12 to the Registrant's Form 10-K for 2000). 10.13*+ Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit 10.13 to the Registrant's Form 10-K for 2000). 10.14*+ Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1997). 10.15*+ Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to the Registrant's Form 10-K for 2000. 10.16+ Black Hills Corporation Omnibus Incentive Compensation Plan dated May 30, 2001. 10.17*+ Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (filed as Exhibit 10(gg) to the Registrant's Form 10-K for 1992). 10.18*+ Change in Control Agreements for various officers (filed as Exhibit 10(af) to the Registrant's Form 10-K for 1995). 10.19*+ Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1997). 10.20*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999). 10.21* Agreement and Plan of Merger, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 2 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.22* Addendum to the Agreement and Plan of Merger, dated as of April 6, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.23* Supplemental Agreement Regarding Contingent Merger Consideration, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 4 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.24* Supplemental Agreement Regarding Restructuring of Certain Qualifying Facilities (Exhibit 5 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.25* Addendum to the Agreement and Plan of Merger, dated as of June 30, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.26* Registration Rights Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 7 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). </TABLE> 90
<TABLE> <CAPTION> <S> <C> 10.27* Shareholders Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 8 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.28* 3-year Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, US Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2001). 10.29* 364-day Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, US Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2001). 10.30 Purchase and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc. dated June 18, 2001 to purchase Southwest Power, LLC. 10.31 Agreement for Lease between Wygen Funding, Limited Partnership and Black Hills Generation, Inc. dated as of July 20, 2001. 10.32 Amendment No. 1 dated as of December 20, 2001 to Agreement for Lease dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Owner and Black Hills Generation, Inc., as Agent. 10.33 Lease Agreement dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Lessor and Black Hills Generation, Inc. as Lessee. 21 List of Subsidiaries of Black Hills Corporation. 23.1 Consent of Independent Public Accountants. 23.2 Consent of Petroleum Engineer and Geologist. 99.1 Letter to Commission Pursuant to Temporary Note 3T. </TABLE> - ---------- * Previously filed as part of the filing indicated and incorporated by reference herein. + Indicates a board of director or management compensatory plan. (b) Reports on Form 8-K We have not filed any Reports on Form 8-K since September 30, 2001. (c) See (a) 3. Exhibits above. (d) See (a) 2. Schedules above. 91
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BLACK HILLS CORPORATION By DANIEL P. LANDGUTH ----------------------------- Daniel P. Landguth, Chairman and Chief Executive Officer Dated: March 25, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. <TABLE> <CAPTION> <S> <C> <C> DANIEL P. LANDGUTH Director and Principal March 25, 2002 - ------------------------------------------ Executive Director Daniel P. Landguth, Chairman, and Chief Executive Officer MARK T. THIES Principal Financial Officer March 25, 2002 - ------------------------------------------- Mark T. Thies, Senior Vice President and Chief Financial Officer ROXANN R. BASHAM Principal Accounting Officer March 25, 2002 - ------------------------------------------- Roxann R. Basham, Vice President-Controller, and Assistant Secretary ADIL M. AMEER Director March 25, 2002 - ------------------------------------------- Adil M. Ameer BRUCE B. BRUNDAGE Director March 25, 2002 - ------------------------------------------- Bruce B. Brundage DAVID C. EBERTZ Director March 25, 2002 - ------------------------------------------- David C. Ebertz JOHN R. HOWARD Director March 25, 2002 - ------------------------------------------- John R. Howard EVERETT E. HOYT Director and Officer March 25, 2002 - ------------------------------------------- Everett E. Hoyt, President and Chief Operating Officer KAY S. JORGENSEN Director March 25, 2002 - ------------------------------------------- Kay S. Jorgensen DAVID S. MANEY Director March 25, 2002 - ------------------------------------------- David S. Maney THOMAS J. ZELLER Director March 25, 2002 - ------------------------------------------- Thomas J. Zeller </TABLE> 92
<TABLE> <CAPTION> INDEX TO EXHIBITS Exhibit Number Description ------- ------------------------------------------------------------------------------------------- <S> <C> 2* Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.1* Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.2* Articles of Amendment of the Registrant (filed as an exhibit to the Registrant's Form 8-K filed on December 26, 2000). 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 3.4* Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A of the Registrant (filed as an exhibit to the Registrant's Form 8-K filed on December 26, 2000). 4.1* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to the Registrant's Registration Statement on Form S-4 (No. 333-52664)). 4.2* Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed at Exhibit 4.2 to the Registrant's Form 10-K for 2000). 10.1* Agreement for Transmission Service and the Common Use of Transmission Systems dated January 1, 1986, among Black Hills Power, Inc., Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc. and Butte Electric Cooperative, Inc. (filed as Exhibit 10(d) to the Registrant's Form 10-K for 1987). 10.2* Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant's Form 10-K for 1992). 10.3* Coal Leases between Wyodak Resources Development Corp. and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant's Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant's Form 10-K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant's Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant's Form 10-K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant's Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant's Form 10-K for 1989). 10.4* Restated and Amended Coal Supply Agreement dated as of January 1, 2001 between Wyodak Resources Development Corp. and PacifiCorp (filed as Exhibit 10.4 to the Registrant's Form S-1 No. 333-57440). 10.5* Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant's Form 10-K for 1997). </TABLE> 93
<TABLE> <CAPTION> <S> <C> 10.6* Coal Supply Agreement for Wyodak Unit #2 dated February 3, 1983, and Ancillary Agreement dated February 3, 1982, between Wyodak Resources Development Corp., Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1983). Amendment to Agreement for Coal Supply for Wyodak #2 dated May 5, 1987 (filed as Exhibit 10(o) to the Registrant's Form 10-K for 1987). 10.7* Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1987). 10.8* Marketing, Capacity and Storage Service Agreement between Black Hills Power, Inc. and PacifiCorp dated September 1, 1995 (filed as Exhibit 10(ag) to the Registrant's Form 10-K for 1995). 10.9* Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1997). 10.10* Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999). 10.11*+ Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 6, 2000 (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2000). 10.12*+ First Amendment to the Pension Equalization Plan of Black Hills Corporation dated January 30, 2001 (filed as Exhibit 10.12 to the Registrant's Form 10-K for 2000). 10.13*+ Black Hills Corporation Nonqualified Deferred Compensation Plan dated June 1, 1999 (filed as Exhibit 10.13 to the Registrant's Form 10-K for 2000). 10.14*+ Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1997). 10.15*+ Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to the Registrant's Form 10-K for 2000. 10.16+ Black Hills Corporation Omnibus Incentive Compensation Plan dated May 30, 2001. 10.17*+ Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (filed as Exhibit 10(gg) to the Registrant's Form 10-K for 1992). 10.18*+ Change in Control Agreements for various officers (filed as Exhibit 10(af) to the Registrant's Form 10-K for 1995). 10.19*+ Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1997). 10.20*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999). 10.21* Agreement and Plan of Merger, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 2 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.22* Addendum to the Agreement and Plan of Merger, dated as of April 6, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, </TABLE> 94
<TABLE> <CAPTION> <S> <C> Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.23* Supplemental Agreement Regarding Contingent Merger Consideration, dated as of January 1, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 4 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.24* Supplemental Agreement Regarding Restructuring of Certain Qualifying Facilities (Exhibit 5 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.25* Addendum to the Agreement and Plan of Merger, dated as of June 30, 2000, among Black Hills Corporation, Black Hills Energy Capital, Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.26* Registration Rights Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 7 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.27* Shareholders Agreement among Black Hills Corporation, Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit 8 to Schedule 13D filed on behalf of the former shareholders of Indeck Capital, Inc. consisting of Gerald R. Forsythe, Michelle R. Fawcett, Marsha Fournier, Monica Breslow, Melissa S. Forsythe and John W. Salyer, Jr., dated July 7, 2000). 10.28* 3-year Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, US Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2001). 10.29* 364-Day Credit Agreement dated as of August 28, 2001 among Black Hills Corporation, as Borrower, The Financial Institutions party, hereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal, as Co-Syndication Agent, US Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent (filed as Exhibit 10.2 to the Registrant's Form 10-Q for the quarterly period ended September 30, 2001). </TABLE> 95
<TABLE> <CAPTION> <S> <C> 10.30 Purchase and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc. dated June 18, 2001 to purchase Southwest Power, LLC. 10.31 Agreement for Lease between Wygen Funding, Limited Partnership and Black Hills Generation, Inc. dated as of July 20, 2001. 10.32 Amendment No. 1 dated as of December 20, 2001 to Agreement for Lease dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Owner and Black Hills Generation, Inc., as Agent. 10.33 Lease Agreement dated as of July 20, 2001 between Wygen Funding, Limited Partnership as Lessor and Black Hills Generation, Inc. as Lessee. 21 List of Subsidiaries of Black Hills Corporation. 23.1 Consent of Independent Public Accountants. 23.2 Consent of Petroleum Engineer and Geologist. 99.1 Letter to Commission Pursuant to Temporary Note 3T. - ---------- * Previously filed as part of the filing indicated and incorporated by reference herein. + Indicates a board of director or management compensatory plan. </TABLE> 96