-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, V4/u58t0pKsjgyByyXY7I7fysoQN1BMUFKeFIoHK0DxfycmMbgr5qLLqiUxOn17s OiJfEqD+jwye5j16m4lCPA== 0000012400-01-000031.txt : 20010409 0000012400-01-000031.hdr.sgml : 20010409 ACCESSION NUMBER: 0000012400-01-000031 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010402 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BLACK HILLS POWER INC CENTRAL INDEX KEY: 0000012400 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 460111677 STATE OF INCORPORATION: SD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-07978 FILM NUMBER: 1589758 BUSINESS ADDRESS: STREET 1: 625 NINTH ST STREET 2: PO BOX 1400 CITY: RAPID CITY STATE: SD ZIP: 57709 BUSINESS PHONE: 6053481700 MAIL ADDRESS: STREET 1: P O BOX 1400 CITY: RAPID CITY STATE: SD ZIP: 57709 FORMER COMPANY: FORMER CONFORMED NAME: BLACK HILLS CORP DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: BLACK HILLS POWER & LIGHT CO DATE OF NAME CHANGE: 19860409 10-K 1 0001.txt BLACK HILLS POWER, INC. ANNUAL REPORT 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, 2000 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 1-7978 BLACK HILLS POWER, INC. (formerly known as Black Hills Corporation) Incorporated in South Dakota IRS Identification Number 46-0111677 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: None Securities registered pursuant to Section 12(g) of the Act: None 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. This paragraph is not applicable to the Registrant. State the aggregate market value of the voting stock held by non-affiliates of the Registrant. All outstanding shares are held by the Registrant's parent company, Black Hills Corporation. 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 March 30, 2001 Common stock, $1.00 par value 23,416,396 shares Reduced Disclosure The Registrant meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. 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 polices 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 counterparty credit risk; 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. TABLE OF CONTENTS Page ITEMS 1 & 2. BUSINESS AND PROPERTIES............................................4 General......................................................4 Electric Utility.............................................4 Independent Energy...........................................5 Communications...............................................5 ITEM 3. LEGAL PROCEEDINGS..................................................6 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS................................................7 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS..............................................7 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........14 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................18 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE............................43 ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K...43 SIGNATURES........................................................46 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES General We are an electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. We began selling and marketing various forms of energy on an unregulated basis in 1956. Our independent 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 produce coal, natural gas and crude oil primarily in the Rocky Mountain region and market fuel products nationwide. 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. During 2000, we became a wholly-owned subsidiary of Black Hills Corporation (formerly Black Hills Holding Corporation) through a "plan of exchange" between us and Black Hills Corporation. The "plan of exchange" provided that each share of our common stock would be exchanged for one share of common stock of the holding company. As a result: o all common shareholders of Black Hills Power, Inc. (formerly Black Hills Corporation) became shareholders of Black Hills Corporation (formerly Black Hills Holding Corporation), the holding company; o Black Hills Power, Inc. became a wholly-owned subsidiary of Black Hills Corporation; and o The debt securities and other financial obligations of Black Hills Power, Inc. continue to be obligations of Black Hills Power, Inc. Unless the context otherwise requires, references in this Form 10-K to "Black Hills Power," "we," "us" and "our" refer to Black Hills Power, Inc. and all of its subsidiaries collectively. Electric Utility We engage in the generation, transmission and distribution of electricity to approximately 58,600 customers in South Dakota, Wyoming and Montana. We control 458 megawatts of generating capacity, including 65 megawatts of capacity purchased from others under long-term power contracts at rates which currently are significantly lower than prevailing market prices. Approximately 53 percent of our generating capacity consists of coal-fired plants and 33 percent is gas- or oil-fired, with the remaining 14 percent purchased from others. Our revenue mix for 2000 was comprised of 29 percent wholesale off-system, 26 percent commercial, 20 percent residential, 14 percent industrial, 10 percent contract wholesale and 1 percent municipal sales. In 2000, our South Dakota customers accounted for 92 percent of our retail electric revenues. Our retail electric rates in South Dakota are subject to a five-year freeze expiring on January 1, 2005. Because our generation capacity typically exceeds our peak load demands, we rarely purchase power on the spot market during periods of peak usage, permitting us to preserve our low-cost rate structure for our retail customers. Off-system sales offer a means to optimize the utilization of our power supply sources by permitting us to sell capacity and energy in excess of our native load requirements to wholesale customers at market prices which sometimes exceed our regulated retail rates. Wholesale off-system sales have represented an increasing percentage of our total revenues and net income. We added 40 megawatts of additional capacity to our system with the addition of the Neil Simpson combustion turbine, which we placed into operation in June 2000. We operate a transmission system of 447 miles of high voltage and 541 miles of lower voltage lines. Our system has the capability of connecting to either the midwestern or western transmission grids. This provides us with an important strategic opportunity to shift off-system power to areas of higher demand and profitability as market conditions warrant. Independent Energy Our independent power unit acquires, develops and operates unregulated power plants, primarily in the Rocky Mountain region of the United States. In July 2000, we expanded our presence in the independent power business by acquiring Indeck Capital, Inc. This acquisition and subsequent additions provide us with varying interests in 13 operating gas-fired and hydroelectric power plants in California, Colorado, Massachusetts and New York, of which we operate 12, as well as minority interests in several power-related funds. We have a total ownership interest of approximately 250 net megawatts. We are in the process of acquiring or constructing an additional net ownership interest of approximately 470 megawatts of generation capacity, approximately 330 megawatts of which we expect to be brought into service in 2001. As of December 31, 2000, we had 275 million tons of low-sulfur sub-bituminous coal reserves at our Wyodak mine located near Gillette, Wyoming. Substantially all of our coal production is sold under long-term contracts with our electric utility and with PacifiCorp. Our Wyodak mine will also provide coal to a 90 megawatt mine-mouth power plant which is being developed for our independent power unit and is scheduled for completion in 2003. Our oil and gas exploration and production unit owns and operates approximately 298 oil and gas wells, all in Wyoming, and owns working interests in another 341 wells operated by others located in California, Montana, North Dakota, Texas, Wyoming, Louisiana, Oklahoma and offshore in the Gulf of Mexico. As of December 31, 2000, we had proved reserves of 4.4 million barrels of oil and 18.4 billion cubic feet of natural gas, with approximately 62 percent of our current production consisting of natural gas. Our fuel marketing and transportation unit supplies wholesale natural gas marketing and risk management products and services primarily to customers in the Rocky Mountain and West Coast regions of the United States. In addition, this unit markets oil in the south and coal in the eastern and midwestern regions of the United States. Our customers include natural gas distribution companies, municipalities, industrial users, oil and gas producers, electric utilities and coal mines. Our average daily marketing volumes for the twelve months ended December 31, 2000 were approximately 860,800 million British thermal units of natural gas, 44,300 barrels of oil and 4,400 tons of coal. Our power marketing activities involve marketing of capacity and energy from our existing power generation facilities. Communications Our communications group, known as Black Hills FiberCom, offers a full suite of local and long distance telephone service, expanded cable television service, cable modem Internet access and high-speed data and video services to residential and business customers. We have completed a 210 mile inter- and intra-city fiber optic network and currently operate nearly 600 miles of two-way interactive hybrid fiber coaxial cable in Rapid City and the northern Black Hills region of South Dakota. The construction of our communications network is approximately 75 percent complete, and we expect to substantially complete construction in 2001. ITEM 3. LEGAL PROCEEDINGS PacifiCorp Litigation In August 2000, we initiated an action in the United States District Court for the District of Wyoming against PacifiCorp relating to a coal supply agreement between PacifiCorp and us. We believe that PacifiCorp has failed to make complete payment to us for coal sold under the coal supply agreement and that PacifiCorp continues to underpay its monthly coal bill by approximately $100,000 per month. We believe that PacifiCorp's actions constitute a breach of the coal supply agreement and have asked for relief in the amount of $5 million, plus all underpayments since the commencement of our lawsuit. PacifiCorp subsequently brought a counterclaim against us, alleging that we had not properly adjusted upward and downward the components which make up the coal price under the coal supply agreement, resulting in alleged overbilling to PacifiCorp of $35 million to $40 million over an undefined period. PacifiCorp further alleged that if past practices continue our adjustment methodology will result in additional overcharges of approximately $150 million through the balance of the term of the coal supply agreement, which expires in June of 2013. In its counterclaim, PacifiCorp seeks to cancel and terminate the contract and to recover monetary damages as proven at trial. Management believes that we have properly billed PacifiCorp under the terms of the coal supply agreement and that PacifiCorp's withholding of payment constitutes a breach of contract on their part. Although it is impossible to predict whether we will ultimately be successful with our claim or in defending PacifiCorp's claim or, if not successful, what the impact might be, management believes that the disposition of this matter will not have a material adverse effect on our consolidated results of operations or financial condition. In addition, management believes that the pending litigation has not affected and will not affect our other agreements with PacifiCorp. Other Litigation On July 14, 2000, the South Coast Air Quality Management District known as SCAQMD sent a letter to our affiliate, now called Black Hills Ontario, L.L.C, the operator of a 12 megawatt natural-gas fired cogeneration 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. If a final determination is reached prior to June 30, 2001, the NOx allowances would be deducted from the facility's allocation for the compliance year ended June 30, 2002. Black Hills Ontario has provided documentation to the SCAQMD disputing this proposed reduction. In addition to this proposed reduction, which could affect the facility's compliance with RECLAIM requirements for the 2001-2002 compliance period, Black Hills Ontario also projects that its NOx emissions for the compliance year ended June 30, 2001 may be approximately 30,000 pounds over its current NOx allocation. 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 such 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, 2001, or, if allowances are available, as to the cost of those allowances. Black Hills Ontario may also be subject to administrative or civil penalties with respect to alleged violations of the SCAQMD's regulation for the compliance year ended June 30, 1999, although no notice of such penalties has been issued. There are no other material legal proceedings pending, other than ordinary routine litigation incidental to our business, to which we are a party. There are no 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 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. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS Consolidated Results Consolidated net income for 2000 was $52.8 million, compared to $37.1 million in 1999 and $25.8 million in 1998. This equates to a 19.0 percent, 17.1 percent and 12.5 percent return on year-end common equity in 2000, 1999 and 1998, respectively. We reported record earnings in 2000, 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 independent energy business group in 2000 were partially offset by start-up losses in our communications business. Unusual energy market conditions stemming primarily from gas and electricity shortages in California contributed to our strong financial performance in 2000. There was approximately a $9.0 million contribution to 2000 earnings due to prevailing prices of gas and electricity and unusually wide gas trading margins that may not recur in the future. Earnings in 1999 increased over 1998 due primarily to sales growth in our electric utility and improved results in our independent energy business group, partially offset by expected start-up losses in our communications business. In 1998, we recorded an $8.8 million (after tax) charge to earnings related to a write-down of certain oil and natural gas properties. Absent this charge, our earnings for 1998 would have been $34.6 million, and our return on year-end common equity would have been 16.1 percent. The write-down was primarily due to historically low crude oil prices, lower natural gas prices and a decline in value of certain unevaluated properties. Consolidated revenues were $1,623.8 million, $791.9 million and $679.3 million in 2000, 1999 and 1998, respectively, representing a 105 percent increase in 2000 and a 17 percent increase in 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 independent energy business group and increases in off-system sales by our electric utility. Prices of natural gas marketed increased from an average of $1.97-$2.15 per million British thermal units in 1998 and 1999 to $4.19 per million British thermal units in 2000. Daily volumes of natural gas marketed increased 35 percent from 635,500 million British thermal units per day in 1999 to 860,800 million British thermal units in 2000. Revenue increases in 1999 resulted primarily from the acquisitions and growth in the fuel marketing segment of our independent energy business group and off-system sales by our electric utility. Revenue and net income (loss) provided by each business group as a percentage of our total revenue and net income were as follows:
2000 1999 1998 ---- ---- ---- Revenue: Independent energy 89% 83% 81% Electric utility 11 17 19 Communications - - - ---- ---- ---- 100% 100% 100% === === === Net Income (Loss): Independent energy 55% 31% 5% Electric utility 70 74 96 Communications (25) (5) (1) ---- --- --- 100% 100% 100% === === ===
Net income from the independent energy group is expected to exceed net income derived from utility operations in 2001. We expect that earnings growth from the independent energy group over the next few years will be driven primarily by our continued expansion in the independent power production segment. We also believe that continued strength in commodity prices and energy markets will provide the opportunity for strong results in our fuel marketing and oil and gas production operations. We have continued to produce modest growth in revenue and earnings from the retail electric business over the past two years. We believe that this trend is stable and that, absent unplanned system outages, it will continue for the next several years due to the extension of our electric rate freeze until January 1, 2005. The share of our future earnings generated from wholesale off-system electric sales will depend on many factors including native load growth, plant availability and commodity prices in the western markets. Although our communications business significantly increased residential and business customers in 2000, we expect it will sustain approximately $10 million in net losses in 2001, with annual losses decreasing thereafter and profitability expected in the next three to four years. The following business group and segment information includes intercompany eliminations. Electric Utility
2000 1999 1998 ---- ---- ---- (in thousands) Revenue $173,308 $133,222 $129,236 Operating expenses 105,100 80,936 79,340 -------- -------- -------- Operating income $ 68,208 $ 52,286 $ 49,896 ======== ======== ======== Net income $ 37,105 $ 27,286 $ 24,825 ======== ======== ======== EBITDA $ 88,853 $ 68,299 $ 64,936 ======== ======== ========
Our electric revenue increased 30.1 percent in 2000 compared to 3.1 percent in 1999. The increase in electric revenue in 2000 was primarily due to a 54 percent increase in wholesale off-system sales at an average price that was 3.1 times higher than the average price in 1999. The increase in off-system sales was driven by high spot market prices for energy in 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. Megawatthours generated from our oil-fired diesel and natural gas-fired combustion turbines were 305,767 in 2000, 25,882 in 1999 and 33,082 in 1998. 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 kilowatthour sales increased 2.8 percent in 2000 compared to a decrease of 0.1 percent in 1999. Residential and commercial sales increases of 6 percent and 3 percent, respectively, in 2000 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 in 2000. Degree days in 1999 were 9 percent below 1998 and 13 percent below normal. The increase in electric revenue in 1999 was primarily due to stable firm sales combined with a 20 percent increase in off-system sales. Revenue per kilowatthour sold was 6.4 cents in 2000, compared to 5.4 cents in 1999 and 1998. The number of customers in the service area increased to 58,601 from 57,709 in 1999 and from 56,856 in 1998. The revenue per kilowatthour sold in 2000 reflects a 54 percent increase in wholesale non-firm sales to 684,378 megawatthours and robust wholesale power prices. The revenue per kilowatthour sold in 1999 reflects the 20 percent increase in wholesale non-firm sales to 445,712 megawatthours. The revenue per kilowatthour sold in 1998 reflects the 33 percent increase in wholesale non-firm sales to 371,104 megawatthours. Our 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. Operating expenses increased 2.0 percent in 1999, primarily due to increased purchase power expense, operations and maintenance expenses and depreciation, partially offset by lower fuel expense. 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 1 percent, with the system demand forecasted to increase at a rate of 2 percent. We currently have a winter peak of 344 megawatts established in December 1998 and a summer peak of 372 megawatts established in August 2000. 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. Independent Energy
2000 1999 1998 ---- ---- ---- (in thousands) Revenue: Fuel marketing $1,353,795 $614,228 $506,043 Coal production 30,530 31,095 31,413 Oil and gas production 19,183 13,052 12,562 Independent power 39,331 - - ---------- -------- -------- Total revenue 1,442,839 658,375 550,018 Expenses 1,381,991 644,196 536,048* ---------- -------- -------- Operating income $ 60,848 $ 14,179 $ 13,970* ========== ======== ======== Net income $ 28,946 $ 11,882 $ 10,068* ========== ======== ======== EBITDA** $ 65,184 $ 25,016 $ 22,530 ========== ======== ========
- --------------- * Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down relating to oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. ** EBITDA represents earnings before interest, income taxes, depreciation and amortization and any non-recurring or non-cash items. 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, as determined by generally accepted accounting principles, or as an indicator of operating performance or cash flows from operating, investing and financing activities, as determined by generally accepted accounting principles, and is thus susceptible to varying calculations. EBITDA as presented may not be comparable to other similarly titled measures of other companies. The following is a summary of coal, oil and natural gas production:
2000 1999 1998 ---- ---- ---- Tons of coal sold 3,050,000 3,180,000 3,280,000 Barrels of oil sold 334,000 318,000 344,000 Mcf of natural gas sold 3,274,000 2,791,000 2,056,000 Mcf equivalent sales 5,278,000 4,698,000 4,120,000
The following is a summary of average daily fuel marketing volumes:
2000 1999 1998 ---- ---- ---- Natural gas - MMBtus 860,800 635,500 524,800 Crude oil - barrels 44,300 19,270 19,000 Coal - tons 4,400 4,500 4,400*
- ------------ * Since the acquisition date The independent energy business group's revenues increased 119 percent in 2000 and 20 percent in 1999. The revenue increase in 2000 was a direct result of gas and electricity shortages in the West Coast markets and the closing of the Indeck Capital acquisition. The revenue increase in 1999 was primarily the result of consolidating our three fuel marketing companies' operations from the time of their acquisitions. Additionally, revenues increased in both years as a result of increased volumes and increased fuel and power prices. Daily volumes of natural gas marketed increased 35 percent in 2000 and 21 percent in 1999. The July 2000 acquisition of Indeck Capital contributed to our strong earnings growth in 2000. In addition, in December 2000, we sold our ownership interest in a power fund management company which resulted in a $3.7 million pre-tax gain. The independent energy business group's total operating expenses, EBITDA and operating income increased over 115 percent, 160 percent and 329 percent, respectively, in 2000 compared to 1999. Net income of this group increased 144 percent in 2000. 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. The independent energy business group's 1999 net income improved over 1998 (excluding the non-cash charge in 1998) primarily due to record gas production, improved oil prices, lower depletion expense and the sale of certain retail gas marketing operations in 1999, partially offset by a non-cash write-down of certain intangible assets relating to our wholesale gas marketing office in Houston. Coal Mining Coal mining results were as follows:
2000 1999 1998 ---- ---- ---- (in thousands) Revenue $30,530 $31,095 $31,413 Operating income 8,800 12,600 12,700 Net income 7,200 9,700 9,750 EBITDA 19,000 15,700 15,600
A planned five-week overhaul at the Wyodak plant resulted in lower coal sales and earnings in 2000 compared to 1999 and 1998. Oil and Gas Oil and gas operating results were as follows:
2000 1999 1998 ---- ---- ---- (in thousands) Revenue $19,183 $13,052 $ 12,562 Operating income 7,900 4,000 1,200* Net income 5,000 2,500 800* EBITDA 11,900 6,900 6,400
- ------------ *Excludes $13.5 million pre-tax, $8.8 million after tax, non-cash write-down relating to oil and gas properties due to historically low crude oil prices, lower natural gas prices and a decline in the value of unevaluated properties. Record net income in 2000 was primarily a result of record natural gas prices, higher crude oil prices and a significant increase in production volumes. Operating results for 1998 decreased primarily as a result of historically low crude oil prices, which not only reduced revenue but also increased depletion expense (lower oil and gas prices reduce the economically recoverable reserve amounts, causing an increase in depletion expense). We recognized approximately $3.7 million, $2.6 million and $4.9 million of depletion expense (excluding the write-down in 1998) related to gas and oil production in 2000, 1999 and 1998, respectively. The following is a summary of our oil and gas reserves at December 31:
2000 1999 1998 ---- ---- ---- Barrels of oil (in millions) 4.41 4.11 2.37 Bcf of natural gas 18.4 19.5 16.0 Total in Bcf equivalents 44.88 44.11 30.16
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. The increase in oil reserves at December 31, 2000 was due to improved product prices. The increase in reserves at December 31, 1999 was due to strong drilling results, reserve acquisitions and improved product prices. We intend to increase our net proved reserves by selectively increasing our oil and gas exploration and development activities and by acquiring producing properties. Fuel Marketing Our fuel marketing companies produced the following results:
2000 1999 1998 ---- ---- ---- (in thousands) Revenue $1,353,795 $614,228 $506,043 Operating income (loss) 23,800 (2,200) - Net income 14,000 (200) (300) EBITDA 23,700 2,500 600
Record volumes marketed and strong margins contributed to the increase in net income from fuel marketing in 2000 compared to 1999 and 1998. During 1999, the fuel marketing companies sold certain of their retail gas marketing operations, resulting in after-tax gains of approximately $1.8 million. In 1999, revenue and the related cost of sales increased primarily due to a full year of coal marketing operations (acquired in September 1998), increased product prices and increased oil volumes marketed. Operating income in 1999 was reduced by a non-cash write-down of certain intangible assets relating to the wholesale gas marketing office in Houston in the amount of approximately $1.2 million (after tax). 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. The unusual energy market conditions stemming primarily from natural gas and electricity shortages in California contributed to the strong financial performance in 2000 and may not recur in the future. However, we believe that the continued growth of our fuel and power production businesses will create opportunities for us to continue to generate strong fuel marketing operating results in future years. Independent Power Production Our independent power segment produced the following results:
2000 1999 1998 ---- ---- ---- (in thousands) Revenue $39,331 $ - $ - Operating income (loss) 20,400 (160) (160) Net income 3,200 (110) (120) EBITDA 10,751 (160) (160)
Results from the independent power production segment were not significant either in 1999 or 1998. In July 2000, we completed the acquisition of Indeck Capital, representing a significant advancement of our position in the independent power production business. We now own 250 net megawatts in currently operating plants. Of this 250 net megawatts, approximately 179 megawatts is under contracts or tolling arrangements with at least one year remaining; approximately 40 megawatts is owned through minority interests in independent power investment funds which we do not manage, and the remainder is sold under short-term market arrangements. An additional 470 megawatts of generating capacity is currently under construction. We expect to sell substantially all of this output under long-term contracts. We expect to increase revenues and earnings in this segment beyond 2001 through future project development. Communications
2000 1999 1998 ---- ---- ---- (in thousands) Revenue $ 7,689 $ 278 $ - Operating expenses 20,175 4,852 1,087 --------- -------- --------- Operating loss $(12,486) $(4,574) $ (1,087) ========= ======== ========= Net loss $(12,027) $(1,262) $ (280) ========= ======== ========= EBITDA $(13,144) $(2,626) $ (570) ========= ======== =========
In September 1998, we formed our communications business to provide facilities-based communications services for Rapid City and the northern Black Hills of South Dakota. We began serving communications customers in late 1999 and market our services to schools, hospitals, cities, economic development groups, and business and residential customers. 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 capital deployment. As of December 31, 2000, we had 8,368 residential customers and 646 business customers. Our goal is to double the number of our customers, and to attain 50 percent residential market penetration within our service territory while serving 35 percent of all broadband business customers in that territory. If we are unable to attract additional customers or technological advances make our network obsolete, we could have a write-down of our assets which could be material. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Price Risk Management Our operations are exposed to market risk arising from changes in commodity prices. These changes could cause fluctuations in our earnings and cash flows. In the normal course of business, we actively manage our exposure to these market risks by entering into various hedging transactions. Hedging transactions involve the use of a variety of derivative financial instruments. Our risk management policies place clear controls on these activities. We have adopted risk management policies and procedures, approved by our board of directors, and reviewed routinely by the audit committee of the board of directors. Our risk management policies and procedures include, but are not limited to, risk tolerance levels relating to authorized derivative financial instruments, position limits, authorization of transactions and credit exposure. Operating margins earned by wholesale gas and crude oil marketing are relatively insensitive to commodity price fluctuations since most of the purchase and sales contracts do not contain fixed-price provisions. Generally, prices contained in these contracts are tied to a current spot or index price and, therefore, adjust directionally with changes in overall market conditions. We generally attempt to balance our fixed-price physical and financial purchase and sales commitments. However, we may, at times, have a bias in the market, within established guidelines, resulting from the management of our portfolio. To the extent a net open position exists, fluctuating commodity market prices can impact our financial position or results of operations, either favorably or unfavorably. The net open positions are actively managed, and the impact of changing prices on our financial condition at a point in time is not necessarily indicative of the impact of price movements throughout the year. Effective January 1, 1999, we adopted the provisions of Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10). The resulting effect of adoption of the provisions of EITF 98-10 was to alter our comprehensive method of accounting for energy-related contracts, as defined in that statement. We account for all energy trading activities at fair value as of the balance sheet date and recognize currently the net gains or losses resulting from the revaluation of these contracts to fair value in our results of operations. As a result, substantially all of the energy trading activities of our gas marketing, crude oil marketing and coal marketing operations are accounted for under fair value accounting methodology as prescribed in EITF 98-10. Through our independent energy business group, we utilize financial instruments for our fuel marketing services. These financial instruments include fixed-for-float swap financial instruments, basis swap financial instruments, and costless collars traded in the over-the-counter financial markets. The derivatives are not held for speculative purposes but rather serve to hedge our exposure related to commodity purchases or sales commitments. Under EITF 98-10, these transactions qualify as energy trading activities that must be accounted for at fair value. As such, realized and unrealized gains and losses are recorded as a component of income. Because we do not speculate with "open" positions, substantially all of our trading activities are back-to-back positions where a commitment to buy/(sell) a commodity is matched with a committed sale/(buy) or financial instrument. The quantities and maximum terms of derivative financial instruments held for trading purposes at December 31, 2000 and 1999 are as follows:
Max. Term December 31, 2000 Volume Covered (Years) - ----------------- -------------- --------- (MMBtus) Natural gas basis swaps purchased 25,577,894 2 Natural gas basis swaps sold 26,059,621 2 Natural gas fixed-for-float swaps purchased 6,476,222 1 Natural gas fixed-for-float swaps sold 7,360,560 1 (Tons) Coal tons sold 988,000 1 Coal tons purchased 896,000 1
Max. Term December 31, 1999 Volume Covered (Years) - ----------------- -------------- ------- (MMBtus) Natural gas futures contracts purchased 860,000 1 Natural gas basis swaps purchased 17,741,500 4 Natural gas basis swaps sold 18,390,517 4 Natural gas fixed-for-float swaps purchased 9,490,486 1 Natural gas fixed-for-float swaps sold 10,994,521 1 Natural gas collar transactions; puts purchased, calls sold 408,500 1 Natural gas collar transactions; calls purchased, puts sold 318,500 1
As required under EITF 98-10, energy trading activities were marked to fair value on December 31, 2000, and the gains and losses recognized in earnings. The entries for the accompanying consolidated balance sheets and income statement are as follows (in thousands):
Instrument Asset Liability Gain (loss) - ---------- ----- --------- ----------- Natural gas basis swaps $13,391 $23,963 $(10,572) Natural gas fixed-for-float swaps 24,617 27,110 (2,493) Natural gas physical 23,391 9,427 13,964 Coal transactions 5,370 4,460 910 Crude oil transactions 1,523 1,000 523 ------- ------- --------- Totals $68,292 $65,960 $ 2,332 ======= ======= =========
There were no significant differences between the fair values of derivative assets and liabilities at December 31, 1999. Non-trading Energy Activities To reduce risk from fluctuations in the price of oil and natural gas, we enter into swaps and costless collar transactions. We use these transactions to hedge price risk from sales of our forecasted crude oil and natural gas production. For such transactions, we utilize hedge accounting. At December 31, 2000, we had fixed-for-float swaps for 17,000 barrels of oil per month for the year 2001 to hedge our crude oil price risk with a fair value of $34,000. We had fixed-for-float swaps for 10,000 barrels of oil per month for the year 2002 to hedge our crude oil price risk with a fair value of $416,000. We also had costless collars (purchased puts-sold calls) for 10,000 barrels of oil per month for 2001 with a fair value of $323,000. We hedged our forecasted 2001 natural gas production with fixed-for-float swaps. We had fixed-for-float swaps for 1,581,000 million British thermal units with a fair value of $(3.4) million. These amounts are not reflected in our December 31, 2000 consolidated balance sheet, but will be recorded as part of the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," on January 1, 2001. Financing Activities To reduce risk from fluctuations in interest rates, we enter into interest rate swap transactions. We use these transactions to hedge interest rate risk for variable rate debt financing. For such transactions, we utilize hedge accounting. At December 31, 2000, we had interest rate swaps with a notional amount of $127.4 million, which have a maximum term of six years and a fair value of $(7.5) million. These amounts are not reflected in our December 31, 2000 consolidated balance sheet, but will be recorded as part of the adoption of SFAS No. 133 on January 1, 2001. Credit Risk In addition to the risk associated with price movements, credit risk is also inherent in our risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. While we have not experienced significant losses due to the credit risk associated with these arrangements, we have off-balance sheet risk to the extent that the counterparties to these transactions fail to perform as required by the terms of their contracts. Interest Rate Risk Our exposure to market risk for changes in interest rates relates primarily to our short-term investments and long-term debt obligations. As stated in our policy, we are averse to principal loss and ensure the safety and preservation of our investments by limiting default risk, market risk and reinvestment risk. We mitigate default risk on short-term investments by investing in high credit quality securities consisting primarily of tax-exempt federal, state and local agency obligations, by periodically monitoring the credit rating of any investment issuer or guarantor and by limiting the amount of exposure to any one issuer. Our portfolio includes only securities with active secondary or resale markets to ensure portfolio liquidity. All short-term investments mature, by policy, in two years or less. The effect of a 100 basis point (1 percent) increase in interest rates would not have a material effect to our results of operations or financial condition, due to the short-term duration of the investment portfolio. At December 31, 2000, we had $162.2 million of outstanding floating rate debt of which $34.8 million was not offset with interest rate swap transactions that effectively convert the interest on that debt to a fixed rate. 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).
2001 2002 2003 2004 2005 Thereafter Total Cash equivalents Fixed rate $ 24,913 $ - $ - $ - $ - $ - $ 24,913 Average interest rate 6.23% - - - - - 6.23% rate Long-term debt Fixed rate $ 3,070 $18,065 $ 3,122 $ 2,017 $ 2,026 $130,602 $158,902 Average interest rate 9.30% 6.98% 9.31% 9.50% 9.52% 8.30% 8.22% Variable rate $10,890 $11,919 $12,968 $14,380 $15,560 $ 96,433 $162,150 Average interest rate 8.20% 8.20% 8.19% 8.19% 8.19% 8.10% 8.14% Total long-term debt $13,960 $29,984 $16,090 $16,397 $17,586 $227,035 $321,052 Average interest rate 8.44% 7.46% 8.41% 8.35% 8.35% 8.22% 8.18%
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Public Accountants 18 Consolidated Statements of Income for the three years ended December 31, 2000 19 Consolidated Balance Sheets as of December 31, 2000 and 1999 20 Consolidated Statements of Cash Flows for the three years ended December 31, 2000 21 Consolidated Statements of Common Stockholder's Equity for the three years ended December 31, 2000 22 Notes to Consolidated Financial Statements 23-42 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholder of Black Hills Power, Inc.: We have audited the accompanying consolidated balance sheets of Black Hills Power, Inc. (formerly Black Hills Corporation, a South Dakota corporation) and Subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2000. 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 Power, Inc. and Subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Minneapolis, Minnesota, January 26, 2001 BLACK HILLS POWER, INC. (formerly Black Hills Corporation) CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) Operating revenues $1,623,836 $ 791,875 $ 679,254 ---------- --------- ---------- Operating expenses: Fuel and purchased power 1,370,841 637,302 531,518 Operations and maintenance 46,054 36,463 32,701 Administrative and general 44,423 18,272 15,747 Depreciation, depletion and amortization 32,864 25,067 24,037 Oil and gas ceilings test write-down - - 13,546 Taxes, other than income taxes 14,904 12,880 12,472 ---------- --------- --------- 1,509,086 729,984 630,021 ---------- --------- --------- Operating income 114,750 61,891 49,233 ---------- --------- --------- Other income (expense): Interest expense (30,342) (15,460) (14,707) Interest income 7,075 3,614 2,861 Other, net 2,996 876 129 ---------- ---------- --------- (20,271) (10,970) (11,717) ---------- ---------- --------- Income before minority interest and income taxes 94,479 50,921 37,516 Minority interest (11,273) 1,935 - Income taxes (30,358) (15,789) (11,708) ---------- ---------- --------- Net income 52,848 37,067 25,808 Preferred stock dividends (78) - - ---------- ---------- --------- Net income available for common stock $ 52,770 $ 37,067 $ 25,808 ========== ========== =========
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. BLACK HILLS POWER, INC. (formerly Black Hills Corporation) CONSOLIDATED BALANCE SHEETS
At December 31, 2000 1999 ---- ---- (in thousands, except share amounts) ASSETS Current assets: Cash and cash equivalents $ 24,913 $ 16,482 Securities available-for-sale 2,113 7,586 Receivables (net of allowance for doubtful accounts of $3,631 and $278, respectively) - Customers 278,434 84,331 Other 21,283 55,694 Materials, supplies and fuel 16,545 14,278 Prepaid expenses 7,428 2,828 Derivatives at market value 68,292 5,158 ------------ ---------- 419,008 186,357 ------------ --------- Investments 73,032 10,444 ------------ --------- Property and equipment 1,072,129 700,044 Less accumulated depreciation and depletion (277,848) (246,299) ------------ --------- 794,281 453,745 ------------ --------- Other assets: Regulatory asset 4,134 3,944 Other, principally goodwill 38,930 14,002 ------------ --------- 43,064 17,946 ------------ --------- $1,329,385 $668,492 ============ ========= LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Current maturities of long-term debt $ 13,960 $ 1,330 Notes payable 211,679 97,579 Accounts payable 247,596 80,355 Accrued liabilities 49,661 26,088 Derivatives at market value 65,960 5,158 ------------ ----------- 588,856 210,510 ------------ ---------- Long-term debt, net of current maturities 307,092 160,700 ------------ ---------- Deferred credits and other liabilities: Investment tax credits 2,530 3,022 Federal income taxes 62,679 47,668 Reclamation and regulatory liability 22,340 22,494 Other 16,516 7,492 ------------ ---------- 104,065 80,676 ------------ ---------- Minority interest in subsidiaries 37,961 - ------------ ---------- Commitments and contingencies (Notes 10, 11 and 14) Common stock equity: Common stock $1 par value; 50,000,000 shares authorized; Issued: 23,416,396 shares in 2000 and 21,739,030 shares in 1999 23,416 21,739 Additional paid-in capital 77,326 40,658 Retained earnings 191,482 162,239 Treasury stock - (8,030) Accumulated other comprehensive income (loss) (813) - ------------ ---------- 291,411 216,606 ------------ ---------- $1,329,385 $668,492 ============ ==========
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. BLACK HILLS POWER, INC. (formerly Black Hills Corporation) CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2000 1999 1998 ---- ---- ---- (in thousands) Operating activities: Net income available for common stock $52,770 $37,067 $25,808 Principal non-cash items- Depreciation, depletion and amortization 32,864 25,067 24,037 Oil and gas ceilings test write-down - - 13,546 Derivative fair value adjustment, net (2,332) - - Gain on sales of assets (3,736) (2,541) - Deferred income taxes and investment tax credits 1,937 2,291 (2,535) Minority interest 11,273 (1,935) - Change in operating assets and liabilities- Accounts receivable (201,307) 2,232 (46,821) Materials, supplies, fuel and other current assets (3,513) (4,003) (2,954) Accounts payable 165,394 6,268 41,465 Accrued liabilities 18,678 4,013 2,244 Other, net 2,444 5,284 (60) ---------- --------- -------- 74,472 73,743 54,730 ---------- --------- -------- Investing activities: Property additions (134,855) (102,290) (25,265) Increase in investments (13,646) (52,319) (1,960) Payment for acquisition of net assets, net of cash acquired (28,688) - - Proceeds from sales of assets 5,500 3,463 - Available-for-sale securities purchased - (7,870) (22,361) Available-for-sale securities sold 4,660 22,959 13,655 ---------- ---------- --------- (167,029) (136,057) (35,931) ---------- ---------- --------- Financing activities: Dividends paid (23,527) (22,602) (21,737) Treasury stock purchased (1,037) (4,949) (3,081) Common stock issued 3,852 424 273 Increase in short-term borrowings 73,848 92,489 5,067 Long-term debt - issuance 60,082 - - Long-term debt - repayments (1,330) (1,330) (1,331) Subsidiary distributions to minority interests (10,900) - - ---------- ---------- --------- 100,988 64,032 (20,809) ---------- ---------- --------- Increase (decrease) in cash and cash equivalents 8,431 1,718 (2,010) Cash and cash equivalents: Beginning of year 16,482 14,764 16,774 ---------- --------- --------- End of year $ 24,913 $ 16,482 $ 14,764 ========== ========= ========= Supplemental disclosure of cash flow information: Cash paid during the period for- Interest $31,309 $18,819 $14,742 Income taxes $18,518 $13,173 $13,135 Non-cash net assets acquired through issuance of common and preferred stock (Note 14) $34,493 $ - $ - Non-cash exchange of treasury stock and preferred stock for common stock (Note 1) $13,067 $ - $ -
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. BLACK HILLS POWER, INC. (formerly Black Hills Corporation) CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated Common Stock Additional Treasury Stock Other ---------------------- Paid-In Retained ------------------ Comprehensive Shares Amount Capital Earnings Shares Amount Income (loss) Total ------ ------ ------- -------- ------ ------ ------------- ----- (in thousands) Balance at December 31, 1997 21,705 $ 21,705 $ 39,995 $ 143,703 - $ - $ - $205,403 -------- -------- ---------- ---------- --------- ---------- ---------- -------- Comprehensive Income: Net income - - - 25,808 - - - 25,808 -------- -------- ---------- ---------- --------- ---------- ---------- -------- - - - 25,808 - - - 25,808 Dividends on common stock - - - (21,737) - - - (21,737) Issuance of common stock 14 14 259 - - - - 273 Treasury stock acquired, net - - - - (141) (3,081) - (3,081) -------- -------- ---------- ---------- -------- --------- ---------- -------- 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 -------- -------- ---------- ---------- -------- --------- ---------- -------- - - - 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 Unrealized loss on available for sale securities - - - - - - (813) (813) -------- -------- ---------- ----------- -------- --------- ---------- -------- - - - 52,848 - - (813) 52,035 Dividends on preferred stock - - - (78) - - - (78) Dividends on common stock - - - (23,527) - - - (23,527) Issuance of common stock 140 140 4,428 - - - - 4,568 Issuance of common stock for acquisition 1,537 1,537 32,240 - - - - 33,777 Treasury stock acquired, net - - - - 368 8,030 - 8,030 -------- -------- ---------- ----------- -------- --------- ---------- -------- Balance at December 31, 2000 23,416 $ 23,416 $ 77,326 $ 191,482 - $ - $ (813) $291,411 ====== ======== ========== =========== ======== ========= ========== ========
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2000, 1999 and 1998 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Power, Inc. and its subsidiaries (the Company) operate in three primary operating groups: regulated electric utility, non-regulated independent energy and communications. Black Hills Power operates the public utility operations. The Company operates its independent 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 consolidated for reporting purposes as Black Hills Energy Ventures; and operates its communications operations through its indirect subsidiaries Black Hills Fiber Systems, Black Hills FiberCom and Daksoft. For further descriptions of the Company's business segments see Note 13. During 2000, the Company became a wholly-owned subsidiary of Black Hills Corporation (formerly Black Hills Holding Corporation) through a "plan of exchange" between the Company and Black Hills Corporation. The "plan of exchange" provided that each share of the Company's common stock would be exchanged for one share of common stock of the holding company. As a result: o all common shareholders of Black Hills Power, Inc. (formerly Black Hills Corporation) became shareholders of Black Hills Corporation (formerly Black Hills Holding Corporation), the holding company; o Black Hills Power, Inc. became a wholly-owned subsidiary of Black Hills Corporation; o The debt securities and other financial obligations of Black Hills Power, Inc. continue to be obligations of Black Hills Power, Inc. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries. 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 (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Total intercompany coal sales not eliminated were $9.7 million, $7.7 million and $10.3 million in 2000, 1999 and 1998, 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 noted in Note 14, Black Hills Energy Capital made several acquisitions during 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. Minority Interest in Subsidiaries Minority interest in results of operations of consolidated subsidiaries represents the minority shareholders' share of the income or loss of various consolidated subsidiaries. The minority interest in the consolidated balance sheets reflect the amount of the underlying net assets of various consolidated subsidiaries attributable to the minority shareholders. Regulatory Accounting The Company's regulated electric operations are 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. The Company's electric operations follow the provisions of SFAS No. 71, and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating its electric operations. As a result of the Company's 1995 rate case settlement, a 50-year depreciable life for Neil Simpson II is used for financial reporting purposes. If the Company 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 the Company's regulated generation operations. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would 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 the Company'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 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. Available-for-sale Securities 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 SFAS 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 stated at the lower of cost or market on a first-in, first-out basis. Property, Plant and Equipment The components of property, plant and equipment are as follows, at December 31: 2000 1999 (in thousands) Independent energy $ 430,979 $ 125,371 Electric utility 530,529 523,461 Communications 110,486 50,621 Other 135 591 ---------- --------- $1,072,129 $ 700,044 ========== ========= 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 9.7, 8.3 and 10.1 percent during 2000, 1999 and 1998, respectively. In addition, the Company capitalizes interest, when applicable, on certain non-regulated construction projects. The amount of AFUDC and interest capitalized was $2.0 million, $1.2 million and $0.2 million in 2000, 1999 and 1998, 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 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 2.8 percent in 2000, 3.1 percent in 1999 and 3.0 percent in 1998. Non-regulated property, plant and equipment is depreciated on a straight-line basis using estimated useful lives ranging from 3 to 39 years. Depletion of coal, oil and gas properties is computed using the cost method. The Company periodically evaluates assets under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of," which requires that such assets be probable of future recovery at each balance sheet date. As of December 31, 2000 and 1999, no significant write-downs were required. Goodwill and Intangible Assets Goodwill represents the excess of acquisition costs over the fair market value of the net assets of acquired businesses and is being amortized on a straight-line basis over the estimated useful lives of such assets, which range 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 $3.1 million, $2.7 million and $0.7 million in 2000, 1999 and 1998, respectively. Accumulated amortization was $6.7 million, $3.6 million and $0.9 million at December 31, 2000, 1999 and 1998, respectively. 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. To the extent such income taxes are recoverable or payable through future rates, regulatory assets and liabilities have been recorded in the accompanying consolidated balance sheets. Deferred taxes are provided on all significant temporary differences, principally depreciation and depletion. Investment tax credits have been deferred in the electric operation and the accumulated balance is amortized as a reduction of income tax expense over the useful lives of the related electric property which gave rise to the credits. Revenue Recognition Generally, revenue is recognized at the time products and services are delivered. 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. In the fourth quarter of 2000, the Company adopted Securities and Exchange Commission Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB 101), which provides guidance on the recognition, presentation and disclosure of revenue in financial statements. The adoption of SAB 101 did not have a material impact on the financial statements. 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 may not exceed the present value of proved reserves. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles 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. Ultimate results could differ from those estimates. Reclassifications Certain 1999 and 1998 amounts in the financial statements have been reclassified to conform to the 2000 presentation. These reclassifications had no effect on the Company's common stockholder's equity or results of operations, as previously reported. Accounting Pronouncements In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 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. The Statement 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 special hedge accounting for fair value and cash flow hedges. The Statement 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." Upon adoption of SFAS 133, most of the Company's energy trading activities previously accounted for under Emerging Issues Task Force Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) will fall under the purview of SFAS 133. The effect from this adoption on the energy trading companies and energy trading activities will not be material because, unless otherwise noted, the trading companies will not designate their energy trading activities as hedge instruments. This "no hedge" designation will result in these derivatives being measured at fair value and gains and losses recognized currently in earnings. This treatment under SFAS 133 will be comparable to the accounting under EITF 98-10. At December 31, 2000, the Company had certain non-trading energy contracts documented as cash flow hedges. These contracts are defined as derivatives under SFAS 133 and meet the requirements for cash flow hedges. Because these non-trading energy contracts were documented as hedges prior to adoption, the transition adjustment will be reported in accumulated other comprehensive income. The aggregated entry for the derivatives identified as energy cash flow hedges will increase derivative assets by $1.4 million, increase the derivative liabilities by $4.0 million and decrease accumulated other comprehensive income by $2.6 million. At December 31, 2000, the Company had interest rate swaps documented as cash flow hedges. These contracts are defined as derivatives under SFAS 133 and meet the requirements for cash flow hedges. Because these contracts were documented as hedges prior to adoption, the transition adjustment will be reported in accumulated other comprehensive income. The interest rate swap transactions have a notional amount of $127.4 million and the associated transition adjustments will increase derivative liabilities by $7.5 million and decrease accumulated other comprehensive income by $7.5 million. (2) PRICE RISK MANAGEMENT The Company is exposed to market risk stemming from changes in commodity prices. These changes could cause fluctuations in the Company's earnings and cash flows. In the normal course of business, the Company actively manages its exposure to these market risks by entering into various hedging transactions, which are authorized under its policies that place clear controls on these activities. Hedging transactions involve the use of a variety of derivative financial instruments. Effective January 1, 1999, the Company adopted the provisions of EITF 98-10, pursuant to the implementation requirements stated therein. The resulting effect of adoption of the provisions of EITF 98-10 was to alter the Company's comprehensive method of accounting for energy-related contracts, as defined in that Statement. The Company accounts for all energy trading activities at fair value as of the balance sheet date and recognizes currently the net gains or losses resulting from the revaluation of these contracts to fair value in its results of operations. As a result, substantially all of the energy trading activities of the Company's gas marketing, crude oil marketing, and coal marketing operations are accounted for under fair value accounting methodology as prescribed in EITF 98-10. The Company, through its independent energy business group, utilizes financial instruments for its fuel marketing services. These financial instruments include fixed-for-float swap financial instruments, basis swap financial instruments and costless collars traded in the over-the-counter financial markets. These derivatives are not held for speculative purposes but rather serve to hedge the Company's exposure related to commodity purchases or sales commitments. Under EITF 98-10, these transactions qualify as energy trading activities that must be accounted for at fair value. As such, realized and unrealized gains and losses are recorded as a component of income. Because the Company does not as a policy permit speculation with "open" positions, substantially all of its trading activities are back-to-back positions where a commitment to buy/(sell) a commodity is matched with a committed sale/(buy) or financial instrument. The quantities and maximum terms of derivative financial instruments held for trading purposes at December 31, 2000 and 1999 are as follows:
Max. Term December 31, 2000 Volume Covered (Years) - ----------------- -------------- ------- (MMBtus) Natural gas basis swaps purchased 25,577,894 2 Natural gas basis swaps sold 26,059,621 2 Natural gas fixed-for-float swaps purchased 6,476,222 1 Natural gas fixed-for-float swaps sold 7,360,560 1 (Tons) Coal tons sold 988,000 1 Coal tons purchased 896,000 1 Max. Term December 31, 1999 Volume Covered (Years) - ----------------- -------------- ------- (MMBtus) Natural gas futures contracts purchased 860,000 1 Natural gas basis swaps purchased 17,741,500 4 Natural gas basis swaps sold 18,390,517 4 Natural gas fixed-for-float swaps purchased 9,490,486 1 Natural gas fixed-for-float swaps sold 10,994,521 1 Natural gas collar transactions; puts purchased, calls sold 408,500 1 Natural gas collar transactions; calls purchased, puts sold 318,500 1
As required under EITF 98-10, energy trading activities were marked to fair value on December 31, 2000, and the gains and losses recognized in earnings. The entries for the accompanying consolidated balance sheet and income statement are as follows (in thousands):
Instrument Asset Liability Gain (loss) - ---------- ----- --------- ---------- Natural gas basis swaps $13,391 $23,963 $(10,572) Natural gas fixed-for-float swaps 24,617 27,110 (2,493) Natural gas physical 23,391 9,427 13,964 Coal transactions 5,370 4,460 910 Crude oil transactions 1,523 1,000 523 ------- ------- -------- Totals $68,292 $65,960 $ 2,332 ======= ======= ========
There were no significant differences between the fair values of derivative assets and liabilities at December 31, 1999. Non-trading Energy Activities To reduce risk from fluctuations in the price of oil and natural gas, the Company enters into swaps and costless collar transactions. The transactions are used to hedge price risk from sales of the Company's forecasted crude oil and natural gas production. For such transactions, the Company utilizes hedge accounting. At December 31, 2000, the Company had fixed-for-float swaps for 17,000 barrels per month for the year 2001 to hedge its crude oil price risk with a fair value that approximates cost. The Company had fixed-for-float swaps for 10,000 barrels per month for the year 2002 to hedge its crude oil price risk with a fair value of $0.4 million. The Company also had costless collars (purchased puts - sold calls) for 10,000 barrels per month for 2001 with a fair value of $0.3 million. The Company hedged its forecasted 2001 natural gas production with fixed-for-float swaps. The Company had fixed-for-float swaps for 1,581,000 MMBtus with a fair value of $(3.4) million. These amounts are not reflected in the Company's December 31, 2000 consolidated balance sheet, but will be recorded as part of the adoption of SFAS 133 on January 1, 2001. Financing Activities To reduce risk from fluctuations in interest rates, the Company enters into interest rate swap transactions. These transactions are used to hedge interest rate risk for variable rate debt financing. For such transactions, the Company utilizes hedge accounting. At December 31, 2000, the Company had interest rate swaps with a notional amount of $127.4 million, having a maximum term of six years and a fair value of $(7.5) million. At December 31, 2000, the Company had $162.2 million of outstanding, floating-rate debt of which $34.8 million was not offset with interest rate swap transactions that effectively convert the debt to a fixed rate. Credit Risk In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. While the Company has not experienced significant losses due to the credit risk associated with these arrangements, the Company has off-balance sheet risk to the extent that the counterparties to these transactions may fail to perform as required by the terms of each such contract. (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 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 $6.9 million and $4.8 million as of December 31, 2000 and 1999, respectively. The partnership had assets of $22.0 million and $15.7 million, liabilities of $1.0 million and $1.6 million, and net income (loss) of $2.8 million and $(0.2) million as of, and for the years ended December 31, 2000 and 1999, respectively. o As part of the Indeck Capital, Inc. acquisition, the Company acquired a 5 percent, 6 percent and 5 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 $8.4 million at December 31, 2000. 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 As part of the Indeck Capital acquisition, the Company acquired a 50 percent financial interest in two natural gas-fired cogeneration facilities located in Rupert and Glenns Ferry, Idaho. At December 31, 2000 the Company's carrying amount in the investment is $4.1 million 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, 2000, these projects had assets of $26.0 million, liabilities of $18.7 million and net income of $0.9 million. o As part of the Indeck Capital acquisition, the Company directly and indirectly acquired approximately 32 percent of Harbor Cogeneration Company, which in turn owns an 80 megawatt cogeneration facility located near the City of Long Beach in Los Angeles County, California. At December 31, 2000 the Company's carrying amount in the investment is $42.2 million, which includes $13.7 million that 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, 2000, Harbor had assets of $41.7 million, liabilities of $0.8 million and net income of $28.8 million. (4) COMMON STOCK During 2000, the Company became a wholly-owned subsidiary of Black Hills Corporation. See Note 1 - Business Description. Black Hills Corporation assumed all of the Company's stock option, employee stock purchase and dividend reinvestment and stock purchase plans. (5) PREFERRED STOCK During 2000, the Company issued 4,000 preferred shares in the Indeck Capital acquisition. The preferred shares issued were 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. In the "plan of exchange" with Black Hills Corporation, the preferred stock held by the Indeck shareholders was exchanged for preferred stock of the holding company and the Company converted all of its preferred stock held by the holding company into shares of common stock. (6) LONG-TERM DEBT Long-term debt outstanding at December 31 is as follows (in thousands):
2000 1999 ---- ---- First mortgage bonds: 6.50% due 2002 $ 15,000 $ 15,000 9.00% due 2003 3,215 4,255 8.06% due 2010 30,000 30,000 9.49% due 2018 5,130 5,420 9.35% due 2021 35,000 35,000 8.30% due 2024 45,000 45,000 --------- -------- 133,345 134,675 --------- -------- 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 3,911 2,855 --------- -------- 28,411 27,355 --------- -------- Project financing debt: Floating-rate term loans at a weighted average rate of 8.05% at December 31, 2000 due 2009 through 2010 (a) 159,296 - --------- --------- Total long-term debt 321,052 162,030 Less current maturities (13,960) (1,330) --------- --------- Net long-term debt $ 307,092 $160,700 ========= =========
- --------------- (a) Approximately 80 percent of the December 31, 2000 balance has been hedged with an interest rate swap moving the floating rates to fixed rates with a weighted average interest rate of 7.69 percent (see Note 2-Price Risk Management). 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 are in compliance with at December 31, 2000. Scheduled maturities for the next five years are: $14.0 million in 2001, $30.0 million in 2002, $16.0 million in 2003, $16.4 million in 2004, and $17.6 million in 2005. (7) NOTES PAYABLE The Company had committed lines of credit with various banks of $290.0 million at December 31, 2000 and $115.0 million at December 31, 1999, which were available to support bank borrowings or to provide for letters of credit. There were $211.0 million of borrowings and $20.6 million of letters of credit issued under these lines of credit at December 31, 2000, and there were $96.6 million of borrowings and no letters of credit issued at December 31, 1999. The Company has no compensating balance requirements associated with these lines of credit. The lines of credit are subject to periodic review and renewal during the year by the banks. In addition to the above lines of credit, Enserco Energy, Inc. has a $90.0 million uncommitted, discretionary line of credit to provide support for the purchases of natural gas. The Company and its subsidiaries provide no guarantee to the lender. At December 31, 2000 and 1999, there were outstanding letters of credit issued under the facility of $69.8 million and $19.9 million respectively, with no borrowing balances on the facility. In addition to the above lines of credit, Black Hills Energy Resources, Inc. has a $25.0 million uncommitted, discretionary credit facility. The transactional line of credit provides credit support for the purchases of crude oil of Black Hills Energy Resources. The Company and its subsidiaries provide no guarantee to the lender. At December 31, 2000 and 1999, Black Hills Energy Resources, Inc. had letters of credit outstanding of $8.5 million and $13.2 million, respectively and no balance outstanding on the overdraft line. Our credit facilities contain restrictive covenants and include commitment fees ranging from .125 percent to .375 percent; our credit facilities with ABN AMRO Bank, NV also include utilization fees of .75 percent on the amount by which facility loans exceed 50 percent of the total facility commitment. The Company and its subsidiaries had complied with all the covenants at December 31, 2000. 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 (9.5 percent at December 31, 2000) to prime rate plus 1.5 percent, or (ii) on the London Interbank Offered Rate (LIBOR) (6.5 percent for a one-month LIBOR at December 31, 2000) based borrowings rates varying from LIBOR plus .625 percent to LIBOR plus 1.375 percent. (8) FAIR VALUE OF FINANCIAL INSTRUMENTS Cash of the Company is invested in money market investments such as municipal put bonds, money market preferreds, commercial paper, Eurodollars and certificates of deposit. 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. Available-for-sale Securities 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, 2000 and 1999. An unrealized loss on the Company's investments of $0.8 million was recorded as of December 31, 2000. At December 31, 1999 fair value approximated cost. Long-Term Debt The fair value of the Company's long-term debt is estimated based on quoted market rates for utility 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. The estimated fair values of the Company's financial instruments are as follows: 2000 ---- (in thousands) Carrying Amount Fair Value --------------- ---------- Cash and cash equivalents $ 24,913 $ 24,913 Securities available-for-sale 2,113 2,113 Long-term debt 321,052 337,446 1999 ---- (in thousands) Carrying Amount Fair Value --------------- ---------- Cash and cash equivalents $ 16,482 $ 16,482 Securities available-for-sale 7,586 7,586 Long-term debt 162,030 165,958 (9) WYODAK PLANT 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, 2000, the Company's investment in the Plant included $71.8 million in electric plant and $22.4 million in accumulated depreciation. The Company's share of direct expenses of the Plant was $5.6 million, $4.9 million and $5.8 million for the years ended December 31, 2000, 1999 and 1998, respectively, and is included in the corresponding categories of operating expenses in the accompanying consolidated statements of income. Wyodak Resources supplies coal to the Plant under an agreement expiring in 2013 with a Pacific Power option to renew the agreement for an additional 10 years. This coal supply agreement is collateralized by a mortgage on and a security interest in some of Wyodak Resources' coal reserves. At December 31, 2000, approximately 17,966,000 tons of coal were covered under this agreement. Wyodak Resources' sales to the Plant were $23.2 million, $24.9 million and $23.2 million, for the years ended December 31, 2000, 1999 and 1998, respectively. (10) COMMITMENTS AND CONTINGENCIES Pacific Power's Power Sales Agreement In 1983, the Company entered into a 40 year power 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 $14.6 million, $17.8 million and $17.5 million in 2000, 1999 and 1998, respectively. Reclamation 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, 2000, accrued reclamation costs were approximately $17.7 million. Legal Proceedings On August 14, 2000, Wyodak Resources Development Corp. ("Wyodak") initiated an action against PacifiCorp as it concerns the Further Restated and Amended Coal Supply Agreement, dated as of May 5, 1987 ("Coal Supply Agreement"). The action has been filed in the United States District Court for the District of Wyoming as Case No. 00CV155-B. Wyodak alleges that PacifiCorp has failed and refused to make complete payment to Wyodak for coal sold under the Coal Supply Agreement, and there was at that time approximately $5.0 million outstanding and allegedly due Wyodak from PacifiCorp. Wyodak alleged that PacifiCorp's actions constitute a breach of contract and asked for the appropriate monetary relief. On August 31, 2000, PacifiCorp answered the Wyodak Complaint and additionally brought a counterclaim against Wyodak and Black Hills Corporation. In its action, PacifiCorp alleged that as a result of Wyodak's actions as it concerns its billings under the Coal Supply Agreement, PacifiCorp was entitled to cancel and terminate the Coal Supply Agreement and Coal Handling Agreement, as well as the recovery of damages. PacifiCorp alleged that Wyodak had not properly adjusted upward and downward the components which make up the coal price under the Coal Supply Agreement, and as a result PacifiCorp had been overbilled appproximately $35.0 million to $40.0 million and that Wyodak continued to overcharge PacifiCorp under the Coal Supply Agreement and the Coal Handling Agreement. PacifiCorp further alleged that the overcharges would result in additional overcharges of approximately $150.0 million through the balance of the term of the Coal Supply Agreement, which expires in June of 2013. In its action, PacifiCorp sought not only to cancel and terminate the contract but also to discharge and excuse any further obligation under the same, as well as recovery of damages as set forth above. Management is of the opinion that Wyodak has properly billed PacifiCorp under the terms of the Coal Supply Agreement and Coal Handling Agreement and PacifiCorp's withholding of payment constitutes a breach of contract on their part. Although it is impossible to predict whether or not Black Hills Corporation and Wyodak will ultimately be successful in defending the claim or, if not, what the impact might be, management believes that the disposition of this matter will not have a material adverse effect on the Company's consolidated results of operations. In addition, 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 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. Net pension income for the Plan was as follows:
2000 1999 1998 ---- ---- ---- (in thousands) Service cost $ 967 $ 1,174 $ 895 Interest cost 2,885 2,598 2,406 Estimated return on assets (5,257) (4,162) (4,146) Amortization of transition amount (90) (90) (90) Amortization of prior service cost 231 89 89 Recognized net actuarial gain (537) - (272) -------- --------- -------- Net pension income $ (1,801) $ (391) $(1,118) ======== ========= ======== Actuarial assumptions: Discount rate 7.5% 6.75% 7.5% 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%
A reconciliation of the beginning and ending balances of the projected benefit obligation is as follows:
2000 1999 ---- ---- (in thousands) Beginning projected benefit obligation $39,615 $39,490 ------- ------- Service cost 967 1,174 Interest cost 2,885 2,598 Actuarial losses (48) (3,590) Benefits paid (2,105) (1,903) Plan amendments - 1,846 ------- ------- Net increase 1,699 125 ------- ------- Ending projected benefit obligation $41,314 $39,615 ======= =======
A reconciliation of the fair value of plan assets as of October 1 of each year is as follows:
2000 1999 ---- ---- (in thousands) Beginning market value of plan assets $51,212 $40,638 Benefits paid (2,105) (1,903) Investment income 7,453 12,477 --------- -------- Ending market value of plan assets $56,560 $51,212 ======= =======
Funding information for the Plan as of October 1 each year was as follows:
2000 1999 ---- ---- (in thousands) Fair value of plan assets $56,560 $51,212 Projected benefit obligation (41,314) (39,615) ------- ------- Funded status 15,246 11,597 Unrecognized: Net gain (13,812) (12,105) Prior service cost 2,054 2,285 Transition asset - (90) ------- ------- Prepaid pension cost $ 3,488 $ 1,687 ======= ======= Accumulated benefit obligation $33,374 $31,914 ======= =======
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, $0.4 million and $0.4 million in 2000, 1999 and 1998, respectively. 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:
2000 1999 1998 ---- ---- ---- (in thousands) Service cost $282 $225 $135 Interest cost 523 362 290 Amortization of transition obligation 150 150 150 (Gain)/loss 68 1 (42) ------ ---- ---- $1,023 $738 $533 ====== ==== ====
Funding information as of October 1 was as follows:
2000 1999 ---- ---- (in thousands) Accumulated postretirement benefit obligation: Retirees $2,478 $2,608 Fully eligible active participants 1,203 1,195 Other active participants 3,172 3,278 ------- ------- Unfunded accumulated postretirement benefit obligation 6,853 7,081 Unrecognized net loss (1,001) (1,667) Unrecognized transition obligation (1,797) (1,947) ------- ------- Accrued postretirement cost $4,055 $3,467 ====== ======
For measurement purposes, an 8.5 percent annual rate of increase in healthcare benefits was assumed for 2000; the rate was assumed to decrease gradually to 6 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 $0.2 million or 21.8 percent and the net periodic postretirement cost $0.2 million or 24.1 percent. A one percent decrease would reduce the service and interest cost by $0.1 million or 16.9 percent and decrease the net periodic postretirement cost $0.2 million or 18.6 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 $0.6 million for 2000. (12) INCOME TAXES Income tax expense for the years indicated was:
2000 1999 1998 ---- ---- ---- (in thousands) Current $28,421 $13,498 $14,243 Deferred 2,576 2,931 (1,886) Tax credits, net (639) (640) (649) ------- ------- ------- $30,358 $15,789 $11,708 ======= ======= =======
The temporary differences which gave rise to the net deferred tax liability at December 31, 2000 and 1999 were as follows:
Net Deferred Income Tax Asset December 31, 2000 Assets Liabilities (Liability) ------ ----------- ----------- (in thousands) Accelerated depreciation and other plant-related differences $ 5,393 $63,559 $(58,166) Regulatory asset 1,621 - 1,621 Regulatory liability - 1,447 (1,447) Unamortized investment tax credits 886 - 886 Mining development and oil exploration 3,605 8,450 (4,845) Employee benefits 3,308 1,347 1,961 Other 3,711 6,400 (2,689) ------- ------- -------- $18,524 $81,203 $(62,679) ======= ======= ========
Net Deferred Income Tax Asset December 31, 1999 Assets Liabilities (Liability) ------ ----------- ----------- (in thousands) Accelerated depreciation and other plant-related differences $ - $48,223 $(48,223) Regulatory asset 1,792 - 1,792 Regulatory liability - 1,380 (1,380) Unamortized investment tax credits 1,058 - 1,058 Mining development and oil exploration 3,605 6,893 (3,288) Employee benefits 2,833 695 2,138 Other 2,184 1,949 235 ------- ------- -------- $11,472 $59,140 $(47,668) ======= ======= ========
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
2000 1999 1998 ---- ---- ---- Federal statutory rate 35.0% 35.0% 35.0% State income tax 1.4 - - Amortization of investment tax credits (1.0) (0.9) (1.3) Tax-exempt interest income - (0.5) (1.1) Percentage depletion in excess of cost (1.1) (1.6) (1.7) Other 2.2 (2.1) 0.3 ----- ------ ----- 36.5% 29.9% 31.2% ==== ==== ====
(13) 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, 2000, 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; Independent 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 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; Independent Power, which produces and sells power to wholesale customers; and Communications and Others, which primarily markets communications and software development services. Segment information follows the same accounting policies as described in Note 1 - - BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES. Segment information included in the accompanying Consolidated Balance Sheets and Consolidated Statements of Income is as follows (in thousands):
ASSETS Independent Energy -------------------------------------------------- Oil and Fuel Independent Communications Electric Mining Gas Marketing Power & Others Eliminations Total ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------ At December 31, 2000 Current assets $ 133,542 $167,820 $ 3,452 $ 330,352 $ 25,645 $ 13,213 $ (255,016) $ 419,008 Total assets 627,930 251,136 36,396 346,333 375,811 132,722 (440,943) 1,329,385 At December 31, 1999 Current assets $ 93,837 $ 57,427 $ 1,988 $ 84,867 $ 52,471 $ 9,698 $ (113,931) $ 186,357 Total assets 522,285 136,372 29,381 99,064 52,690 72,711 (244,011) 668,492 At December 31, 1998 Current assets $ 43,760 $ 25,872 $ 1,335 $ 77,402 $ 4 $ 6,067 $ (13,960) $ 140,480 Total assets 451,404 93,480 26,666 86,300 57 18,441 (116,931) 559,417
Independent Energy -------------------------------------------------- Year ended Oil and Fuel Independent Communications December 31, 2000 Electric Mining Gas Marketing Power & Others Eliminations Total ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------ Electric revenues $ 173,308 $ - $ - $ - $ - $ - $ - $ 173,308 Coal revenues - 30,530 - 37,099 - - - 67,629 Gas revenues - - 9,335 871,296 - - (14,320) 866,311 Oil revenues - - 7,211 458,575 - - - 465,786 Other operating Revenues - - 3,782 - 39,660 11,371 (4,011) 50,802 ---------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------- Total operating Revenues $ 173,308 $ 30,530 $ 20,328 $1,366,970 $ 39,660 $ 11,371 $ (18,331) $ 1,623,836 ---------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------- Depreciation, depletion and amortization $ 14,966 $3,525 $ 4,071 $ 644 $ 3,646 $ 6,012 $ - $ 32,864 Operating income (loss) 68,208 8,794 7,906 23,774 20,374 (14,306) - 114,750 Interest expense 17,411 8,006 372 535 11,911 6,350 (14,243) 30,342 Income taxes (benefit) 19,469 2,660 2,609 9,323 3,154 (6,857) - 30,358 Net income (loss) available for common 37,100 7,173 4,992 14,009 3,241 (12,557) (1,188) 52,770 Property additions, investments and acquisition of net assets 25,257 2,419 9,259 (3) 81,335* 58,922 - 177,189 *Excludes the non-cash acquisition of Indeck Capital, Inc. as described in Note 14.
Independent Energy -------------------------------------------------- Year ended Oil and Fuel Independent Communications December 31, 1999 Electric Mining Gas Marketing Power & Others Eliminations Total ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ---------- Electric revenues $ 133,222 $ - $ - $ - $ - $ - $ - $ 133,222 Coal revenues - 31,095 - 39,212 - - - 70,307 Gas revenues - - 5,399 382,809 - - - 388,208 Oil revenues - - 4,676 192,207 - - - 196,883 Other operating Revenues - - 2,977 - - 3,423 (3,145) 3,255 ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ----------- Total operating Revenues $ 133,222 $ 31,095 $ 13,052 $ 614,228 $ - $ 3,423 $(3,145) $ 791,875 ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ----------- Depreciation, depletion and amortization $ 15,552 $ 3,259 $ 2,953 $ 2,757 $ - $ 546 $ - $ 25,067 Operating income (loss) 52,286 12,606 3,978 (2,248) (157) (4,574) - 61,891 Interest expense 13,830 1,260 568 719 111 1,172 (2,200) 15,460 Income taxes (benefit) 12,446 3,439 968 50 (58) (1,056) - 15,789 Net income (loss) available for common 27,362 9,715 2,462 (185) (109) (1,263) (915) 37,067 Property additions, investments and acquisition of net assets 31,911 5,422 9,968 5,947 52,319 49,042 - 154,609
Independent Energy --------------------------------------------------- Year ended Oil and Fuel Independent Communications December 31, 1998 Electric Mining Gas Marketing Power & Others Eliminations Total ------------- ---------- ------------ ------------ -------------- ----------------- ------------- ---------- Electric revenues $ 129,236 $ - $ - $ - $ - $ - $ - $ 129,236 Coal revenues - 31,413 - 12,924 - - - 44,337 Gas revenues - - 4,073 375,136 - - - 379,209 Oil revenues - - 5,131 117,185 - - - 122,316 Other operating Revenues - - 3,358 798 - 2,437 (2,437) 4,156 ------------- ---------- ------------ ------------ -------------- ----------------- ------------- ---------- Total operating Revenues $ 129,236 $ 31,413 $ 12,562 $ 506,043 $ - $ 2,437 $ (2,437) $ 679,254 ------------ ---------- ------------ ------------ -------------- ----------------- ------------- ---------- Depreciation, depletion and amortization $ 14,881 $ 3,252 $ 18,760** $ 690 $ - $ - $ - $ 37,583 Operating income (loss) 49,896 12,723 (12,340)** 41 - (1,087) - 49,233 Interest income 13,572 10 355 731 - 39 - 14,707 Income taxes (benefit) 12,612 4,126 (4,689)** (116) (64) (161) - 11,708 Net income (loss) available for common 24,825 9,750 (7,976)** (346) (118) (226) (101) 25,808 Property additions, investments and acquisition of net assets 11,451 1,406 10,169 2,384 - 1,815 - 27,225 **Includes the impact of a $13.5 million pre-tax write-down of certain oil and natural gas properties.
(14) ACQUISITIONS On July 7, 2000, the Company acquired Indeck Capital, Inc. and merged it into Black Hills Energy Capital, Inc. The new entity owns varying financial interests in 14 operating independent power plants in California, New York, Massachusetts, Colorado and Idaho totaling approximately 350 megawatts. 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 (approximately 7 percent of the Company's common stock after the transaction), along with $4 million in preferred stock, resulting in a purchase price of approximately $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. The earn-out consideration will be 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 will be recorded as an increase to goodwill. The acquisition has been accounted for under the purchase method of accounting and, accordingly, the purchase price has been 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 approximately $151.1 million (excluding goodwill) and liabilities assumed of approximately $138.7 million. As of December 31, 2000, the purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by approximately $25.4 million, which was recorded as goodwill and is being amortized over 25 years on a straight-line basis. Prior to the closing of the Indeck Capital transaction, there was no material relationship between its shareholders and the Company or any of its affiliates, any director or officer of the Company or any of their associates, except that the Company through its subsidiaries and Indeck Capital jointly owned Black Hills Colorado, LLC and both parties held interests in Indeck North American Power Partners, L.P. and Indeck North American Power Fund, L.P. Black Hills Colorado owns 111 megawatts of combustion turbine generating facilities in the Front Range of Colorado. In addition, 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 approximately $13.0 million in cash. o Acquired a 39.6 percent financial interest in each of Northern Electric Power Company, L.P. and South Glens Falls Limited Partnership for approximately $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 approximately $12.9 million in cash. Operating activities of the above acquired companies have been included in the accompanying consolidated financial statements since their respective acquisition dates. The following unaudited pro forma condensed results of operations presents the effect of the acquisitions as if they had occurred on January 1, 1999. The pro forma financial data is provided for informational purposes only and does not purport to be indicative of the results that would have been obtained if the acquisitions had been effected on January 1, 1999. The pro forma financial information reflects the amortization of the excess purchase price over the fair value of net assets acquired and the income tax effect thereof for the years ended December 31, 2000 and 1999 as follows: 2000 1999 ---- ---- (Unaudited, in thousands) Revenues $1,668,851 $840,891 Operating income $139,053 $73,900 Net income available for common stock $57,542 $34,310 (15) OIL AND GAS RESERVES (Unaudited) Black Hills Exploration and Production has interests in 639 producing oil and gas properties in seven states. Black Hills Exploration and Production also holds leases on approximately 185,926 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, 2000, 1999 and 1998, 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.
2000 1999 1998 ---- ---- ---- Oil Gas Oil Gas Oil Gas --- --- --- --- --- --- (in thousands of barrels of oil and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 4,109 19,460 2,368 15,952 2,495 9,052 Production (352) (3,285) (309) (2,801) (353) (2,068) Additions 625 4,228 376 7,718 1,149 10,721 Property sales - - (164) (66) - - Revisions to previous estimates 31 (1,999) 1,838 (1,343) (923) (1,753) ------- ------- ------- -------- ------- -------- Balance at end of year 4,413 18,404 4,109 19,460 2,368 15,952 ======= ======= ======= ======= ======= ======= Proved developed reserves at end of year included above 3,047 16,418 2,819 14,391 1,463 10,041 ======= ======= ======= ======= ======= ======= Year-end prices $26.80 $9.78 $24.28 $1.99 $9.16 $1.93 ====== ===== ====== ===== ===== =====
In December 1998, Black Hills Exploration and Production recognized a $13.5 million pre-tax loss related to a write-down of oil and gas properties. The write-down was primarily due to historically low crude oil prices, lower natural gas prices and decline in value of certain unevaluated properties. (16) 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 2000 and 1999.
First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- (in thousands) 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 1999: Operating revenues $168,201 $186,195 $219,779 $217,700 Operating income 15,980 13,786 16,675 15,450 Net income available for common stock 9,035 7,763 9,725 10,544
(17) SUBSEQUENT EVENT (Unaudited) On March 8, 2001, Black Hills Energy Capital, Inc., the Company's independent power subsidiary announced it had signed a definitive agreement to purchase a 240 megawatt gas-fired turbine generation facility (Fountain Valley) located near Colorado Springs, Colorado from Enron Corporation. The transaction is expected to close around March 31, 2001. The Fountain Valley facility features six LM-6000 simple-cycle, gas-fired turbines, a technology identical to existing Company facilities in Colorado and Wyoming. All necessary permitting has been approved and the plant is expected to phase in its generation capacity beginning in May 2001. The Company also announced that it has signed an 11-year contract with Public Service of Colorado to utilize the plant for peaking purposes. The contract is a tolling arrangement in which the Company assumes no fuel costs. The cost of the project is expected to be approximately $175 million. The Company expects to finance the project primarily with non-recourse debt and negotiations are presently under way with certain lenders. 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 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. 3. Exhibits Exhibit Number Description 2* Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)). 3.1* Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)). 3.2 Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000. 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999). 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 Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)). 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* Further Restated and Amended Coal Supply Agreement dated May 5, 1987 between Wyodak Resources Development Corp. and Pacific Power & Light Company (filed as Exhibit 10(k) to the Registrant's Form 10-K for 1987). 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). 10.11*+ Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 6, 2000 (filed as Exhibit 10.11 to Black Hills Corporation'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 Black Hills Corporation'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 Black Hills Corporation's Form 10-K for 2000). 10.14*+ Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to Black Hills Corporation's Form 10-K for 2000). 10.15*+ 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). 10.16*+ Change in Control Agreements for various officers (filed as Exhibit 10(af) to the Registrant's Form 10-K for 1995). 10.17*+ Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1997). 10.18*+ Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1997). 10.19*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999). 10.20* 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) 10.21* 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). 10.22* 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). 10.23* 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). 10.24* 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). - ---------- * 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 filed the following Reports on Form 8-K since September 30, 2000. Form 8-K filed December 22, 2000. Reported the formation of the holding company structure through a "Plan of Exchange" between Black Hills Corporation and Black Hills Holding Corporation on December 22, 2000. (c) See (a) 3. Exhibits above. (d) See (a) 2. Schedules above. SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT. The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation. 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 POWER, INC. By DANIEL P. LANDGUTH Daniel P. Landguth, Chairman and Chief Executive Officer Dated: March 30, 2001 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.
DANIEL P. LANDGUTH Director and Principal March 30, 2001 - --------------------------------------------- Executive Officer Daniel P. Landguth, Chairman, and Chief Executive Officer MARK T. THIES Principal Financial Officer March 30, 2001 - --------------------------------------------- Mark T. Thies, Senior Vice President and Chief Financial Officer ROXANN R. BASHAM Principal Accounting Officer March 30, 2001 - --------------------------------------------- Roxann R. Basham, Vice President-Controller, and Assistant Secretary ADIL M. AMEER Director March 30, 2001 - --------------------------------------------- Adil M. Ameer BRUCE B. BRUNDAGE Director March 30, 2001 - --------------------------------------------- Bruce B. Brundage DAVID C. EBERTZ Director March 30, 2001 - --------------------------------------------- David C. Ebertz GERALD R. FORSYTHE Director March 30, 2001 - --------------------------------------------- Gerald R. Forsythe JOHN R. HOWARD Director March 30, 2001 - --------------------------------------------- John R. Howard EVERETT E. HOYT Director and Officer March 30, 2001 - --------------------------------------------- Everett E. Hoyt, President and Chief Operating Officer KAY S. JORGENSEN Director March 30, 2001 - --------------------------------------------- Kay S. Jorgensen DAVID S. MANEY Director March 30, 2001 - --------------------------------------------- David S. Maney THOMAS J. ZELLER Director March 30, 2001 - --------------------------------------------- Thomas J. Zeller
INDEX TO EXHIBITS Exhibit Number Description 2* Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)). 3.1* Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)). 3.2 Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000. 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999). 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)). 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* Further Restated and Amended Coal Supply Agreement dated May 5, 1987 between Wyodak Resources Development Corp. and Pacific Power & Light Company (filed as Exhibit 10(k) to the Registrant's Form 10-K for 1987). 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). 10.11*+ Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 6, 2000 (filed as Exhibit 10.11 to Black Hills Corporation'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 Black Hills Corporation'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 Black Hills Corporation's Form 10-K for 2000). 10.14*+ Black Hills Corporation 1999 Stock Option Plan (filed as Exhibit 10.14 to Black Hills Corporation's Form 10-K for 2000). 10.15*+ 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). 10.16*+ Change in Control Agreements for various officers (filed as Exhibit 10(af) to the Registrant's Form 10-K for 1995). 10.17*+ Black Hills Corporation 1996 Stock Option Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1997). 10.18*+ Outside Directors Stock Based Compensation Plan (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1997). 10.19*+ Officers Short-Term Incentive Plan (filed as Exhibit 10(s) to the Registrant's Form 10-K for 1999). 10.20* 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, Moncia 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). 10.21* 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). 10.22* 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, Moncia 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). 10.23* 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). 10.24* 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). - ---------- * Previously filed as part of the filing indicated and incorporated by reference herein. + Indicates a board of director or management compensatory plan. EX-3.(I) 2 0002.txt ARTICLES OF AMENDMENT TO THE ARTICLES OF INCORP Exhibit 3.2 ARTICLES OF AMENDMENT TO THE ARTICLES OF INCORPORATION OF BLACK HILLS CORPORATION The undersigned hereby execute, acknowledge, and deliver to the Secretary of State of South Dakota the following Articles of Amendment: 1. The name of the corporation is Black Hills Corporation. 2. The following amendment was adopted by the shareholders of the Corporation on June 20, 2000: Article I of the Articles of Incorporation is hereby amended to read as follows: The name of the Corporation is Black Hills Power and Light Company. 3. The number of shares of the Corporation outstanding at the time of such adoption was 20,428,852, and the number of shares entitled to vote thereon was 20,428,852. 4. The number of shares voted for such amendment was 12,987,600, which was 70.4% of all issued and outstanding shares at this time. The number of shares voted against this amendment was 1,861,557. The number of shares abstaining from voting on this amendment was 2,225,459. The number of shares held by brokers and not voted was 3,354,236. IN WITNESS WHEREOF, these Articles of Amendment to the Articles of Incorporation of Black Hills Corporation were executed on this 22nd day of December, 2000. BLACK HILLS CORPORATION By /s/ James M. Mattern James M. Mattern Its Senior Vice President - Corporate Administration And /s/ Roxann R. Basham Roxann R. Basham Its Vice President - Controller and Corporate Secretary ARTICLES OF AMENDMENT TO THE ARTICLES OF INCORPORATION OF BLACK HILLS POWER AND LIGHT COMPANY The undersigned hereby execute, acknowledge, and deliver to the Secretary of State of South Dakota the following Articles of Amendment: 1. The name of the corporation is Black Hills Power and Light Company. 2. The following amendment was adopted by the shareholders of the Corporation on June 20, 2000: Article I of the Articles of Incorporation is hereby amended to read as follows: The name of the Corporation is Black Hills Power, Inc. 3. The number of shares of the Corporation outstanding at the time of such adoption was 100, and the number of shares entitled to vote thereon was 100. 4. The number of shares voted for such amendment was 100. The number of shares voted against this amendment was 0. IN WITNESS WHEREOF, these Articles of Amendment to the Articles of Incorporation of Black Hills Power and Light Company were executed on this 22nd day of December, 2000. BLACK HILLS POWER AND LIGHT COMPANY By /s/ James M. Mattern James M. Mattern Its Senior Vice President - Corporate Administration And /s/ Roxann R. Basham Roxann R. Basham Its Vice President - Controller and Corporate Secretary EX-27 3 0003.txt
UT YEAR DEC-31-2000 DEC-31-2000 PER-BOOK 358,180,000 509,133,000 419,008,000 43,064,000 0 1,329,385,000 23,416,000 77,326,000 191,482,000 291,411,000 0 0 307,092,000 211,679,000 0 0 13,960,000 0 0 0 505,243,000 1,329,385,000 1,623,836,000 30,358,000 1,509,086,000 1,539,444,000 84,392,000 (1,202,000) 83,190,000 30,342,000 52,848,000 78,000 52,770,000 23,527,000 13,094,000 74,472,000 2.39 2.37
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