-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, G4LaDAHphseUKex0JG4t2SAnb6i1PH9G6GRu7nHwy0VgyWsJpoSjB8DcsVNPwayL 2I0D0RE/nXeDuHEm5/gJBA== 0000012400-94-000011.txt : 19940315 0000012400-94-000011.hdr.sgml : 19940315 ACCESSION NUMBER: 0000012400-94-000011 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940314 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BLACK HILLS CORP CENTRAL INDEX KEY: 0000012400 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 460111677 STATE OF INCORPORATION: SD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-07978 FILM NUMBER: 94515832 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 POWER & LIGHT CO DATE OF NAME CHANGE: 19860409 10-K 1 1993 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 Form 10-K X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1993 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ___________ to ___________ Commission file Number 1-7978 BLACK HILLS CORPORATION Incorporated in South Dakota IRS Identification Number 46-0111677 625 Ninth Street, P.O. Box 1400 Rapid City, South Dakota 57709 Registrant's telephone number, including area code (605) 348-1700 Securities registered pursuant to Section 12(b) of the Act: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED Common stock of $1.00 par value New York Stock Exchange Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] State the aggregate market value of the voting stock held by non- affiliates of the Registrant. At February 28, 1994 $305,709,166 Indicate the number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date. CLASS OUTSTANDING AT FEBRUARY 28, 1994 Common stock, $1.00 par value 14,277,277 shares DOCUMENTS INCORPORATED BY REFERENCE 1. Pages 11 through 32 of the Annual Report to Stockholders of the Registrant for the year ended December 31, 1993, are incorporated by reference in Part I and Part II and appended hereto. 2. Definitive Proxy Statement of the Registrant filed pursuant to Regulation 14A for the 1994 Annual Meeting of Stockholders to be held on May 24, 1994, is incorporated by reference in Part III. TABLE OF CONTENTS Page No. DEFINITIONS PART I. ITEM 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . 1 GENERAL . . . . . . . . . . . . . . . . . . . . . . 1 ELECTRIC POWER SALES AND SERVICE TERRITORY. . . . . 2 ELECTRIC POWER SUPPLY . . . . . . . . . . . . . . . 5 RATE REGULATION . . . . . . . . . . . . . . . . . . 9 COMPETITION IN ELECTRIC UTILITY BUSINESS. . . . . .13 CONSTRUCTION AND CAPITAL PROGRAMS . . . . . . . . .17 COAL SALES. . . . . . . . . . . . . . . . . . . . .18 OIL AND GAS OPERATIONS. . . . . . . . . . . . . . .21 ENVIRONMENTAL REGULATION. . . . . . . . . . . . . .22 EMPLOYEES . . . . . . . . . . . . . . . . . . . . .28 CORPORATE DEVELOPMENT . . . . . . . . . . . . . . .28 ITEM 2. PROPERTIES. . . . . . . . . . . . . . . . . . . . .29 UTILITY PROPERTIES. . . . . . . . . . . . . . . . .29 MINING PROPERTIES . . . . . . . . . . . . . . . . .30 OIL AND GAS PROPERTIES. . . . . . . . . . . . . . .31 ITEM 3. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . .32 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS EXECUTIVE OFFICERS OF THE COMPANY. . . . .33 PART II. ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . .33 ITEM 6. SELECTED FINANCIAL DATA . . . . . . . . . . . . . .34 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. . . . . . . .34 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . .34 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. . . . . . . .34 PART III. ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT . . . . . . . . . . . . . . . . . .34 ITEM 11.EXECUTIVE COMPENSATION. . . . . . . . . . . . . . .34 ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT . . . . . . . . . . . . . . . . . . . .34 ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. . .34 PART IV. ITEM 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. . . . . . . . . . . . . .35 SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . .41 APPENDICIES FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA LIST OF SUBSIDIARIES DEFINITIONS WHEN THE FOLLOWING TERMS ARE USED IN THE TEXT THEY WILL HAVE THE MEANINGS INDICATED. Term Meaning Black Hills Power Black Hills Power and Light Company, the assumed business name of the Company under which its electric operations are conducted Basin Electric Basin Electric Power Cooperative, Inc., a rural electric cooperative engaged in generating and transmitting electric power to its member RECs Company Black Hills Corporation DEQ Department of Environmental Quality of the State of Wyoming EAFB Ellsworth Air Force Base, a military air force base near Rapid City, South Dakota FERC Federal Energy Regulatory Commission Indenture Indenture of Mortgage and Deed of Trust of the Company Neil Simpson Unit #1 A 20 megawatt coal-fired electric generating plant owned by the Company and located adjacent to the Wyodak Plant Neil Simpson Unit #2 An 80 megawatt coal-fired power plant the Company now has under construction at the site of the Wyodak Plant and the Neil Simpson Unit #1 Pacific Power PacifiCorp, which operates its electric utility operations under the assumed names of Pacific Power & Light Company and Utah Power & Light Company RECs Rural electric cooperatives, which are owned by their customers and which rely primarily on the Rural Electrification Administration of the United States for their financing needs SDPUC The South Dakota Public Utilities Commission WAPA Western Area Power Administration of the Department of Energy of the United States of America WPSC The Wyoming Public Service Commission Western Production Western Production Company, a wholly owned subsidiary of Wyodak Resources Wyodak Resources Wyodak Resources Development Corp., a wholly owned subsidiary of the Company Wyodak Plant A 330 megawatt coal-fired electric generating plant which is owned 20 percent by the Company and 80 percent by Pacific Power and located near Gillette, Wyoming PART I ITEM 1. BUSINESS GENERAL The Company was incorporated under the laws of South Dakota in 1941 under the name Black Hills Power and Light Company. In 1986 the Company changed its name to Black Hills Corporation and now operates its investor-owned electric public utility operations under the assumed name of Black Hills Power and Light Company. In addition the Company has diversified into coal mining through Wyodak Resources and into oil and gas production through Western Production. Black Hills Power is engaged in the generation, purchase, transmission, distribution and sale of electric power and energy to approximately 53,330 customers in 11 counties in western South Dakota, northeastern Wyoming and southeastern Montana. The territory served by Black Hills Power includes 20 incorporated communities and various unincorporated and rural areas with a population estimated at 165,000. The largest community served is Rapid City, South Dakota, with a population, including environs, estimated at 75,000. Rapid City is the major retail, wholesale and health care center for a 250-mile radius. Principal industries in the territory served are tourism (including small stake casino gambling at Deadwood), cattle and sheep raising, farming, milling, meat packing, lumbering, the production of cement, the mining of bentonite, stone, gravel, silica sand, gold, silver, coal and other minerals, the manufacture of electronic products, wood products and gold jewelry, and the production and refining of oil. Black Hills Power serves a substantial portion of the electric needs of the Black Hills tourist region which includes the National Shrine of Democracy, Mount Rushmore National Memorial and the Crazy Horse Memorial, a large granite mountain carving under construction as a memorial to native Americans and one of their leaders. Tourism has been and is expected to continue to be enhanced significantly by the establishment of small stakes casino gambling at Deadwood, South Dakota, which is a part of Black Hills Power's service territory. Although only a small portion of EAFB is served by Black Hills Power, EAFB forms a significant economic base for the territory served. Wyodak Resources, incorporated under the laws of Delaware in 1956, is engaged in the mining and sale of sub-bituminous coal. The coal mining operation is located approximately five miles east of Gillette, Wyoming. In 1986, Wyodak Resources acquired all of the outstanding capital stock of Western Production, an oil and gas exploration, producing and operating company incorporated under the laws of Wyoming. Western Production is an oil producing and operating company with interests located in the Rocky Mountain Region and Texas. Western Production also has a partial interest in a natural gas processing plant. Information as to the continuing lines of business of the Company for the calendar years 1991-1993 is as follows:
1993 1992 1991 (in thousands) Revenue from sales to unaffiliated customers: Electric $97,885 $97,232 $97,922 Coal mining 19,775 18,485 16,918 Oil and gas production 11,396 9,599 9,077 Revenue from intercompany sales: Electric $ 270 $ 216 $ 236 Coal mining 10,047 9,811 9,220
Reference is made to the Consolidated Statements of Income and Note 11 of "Notes to Consolidated Financial Statements" appended hereto. ELECTRIC POWER SALES AND SERVICE TERRITORY ELECTRIC POWER SALES--RETAIL. Even though Black Hills' service area again experienced milder than normal summer weather, Black Hills Power's firm kilowatt hour sales increased in 1993 by 3.5 percent over 1992. The increase in energy sales is largely due to an increase in the number of customers and their use of electricity. Firm energy sales are forecast to increase over the next ten years at an annual compound growth rate of approximately 2.5 percent. During the next ten years the peak system demand is forecast to increase at an annual compound growth rate of 2.6 percent. These forecasts are from studies conducted by Black Hills Power with the help of outside consultants whereby the service territory of Black Hills Power is carefully examined and analyzed 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. In the past Black Hills Power's forecasts have tracked actual sales within a band of reasonable performance. Electric sales are materially affected by weather. Like 1992, Black Hills Power's electric service territory again experienced a cool summer in 1993, resulting in degree days that were 59 percent lower than normal for the 1993 summer months. Consequently, energy sales and peak demand were substantially less during the cooling season than they would have been in a normal weather year. RETAIL ELECTRIC SERVICE TERRITORY. Black Hills Power's service territory is currently protected by assigned service area and franchises that generally grant to Black Hills Power the exclusive right to sell all electric power consumed therein, subject to providing adequate service. See--COMPETITION IN ELECTRIC UTILITY BUSINESS--COMPETITION IN SERVICE AT RETAIL under this Item 1. At the end of 1993, Black Hills served electric energy to 53,330 customers in a population island that includes the major population centers of the Black Hills area in western South Dakota and northeastern Wyoming and a small oil field in southeastern Montana. (See--GENERAL under this Item 1 for a general description of the service territory.) Black Hills Power's electric service territory is experiencing modest business and population growth. In 1993 the value of commercial building permits in Rapid City increased by 91 percent, and residential building permits increased 10.5 percent. South Dakota's unemployment rate in 1993 averaged 3.4 percent. Personal income in South Dakota increased 7.3 percent in 1993 and visitor spending in South Dakota increased by 14 percent. The Company believes that this growth in its electric service territory will continue; however, the Company can give no assurances. One of the major employers in the Rapid City area is the United States Defense Department's EAFB. EAFB is a military air force base near Rapid City, South Dakota. Its current mission is to serve as the training, operation and maintenance base for the Air Force's B-1 bombers. There are now stationed at EAFB 30 B-1 bombers, out of the Defense Department's total of 96 B-1s, of which 80 are operational. Black Hills Power does not provide electric service to EAFB. However, currently EAFB employs approximately 5,200 military and 600 civilian personnel. In addition to these direct employees, additional nongovernmental employees residing in Rapid City and the surrounding area depend upon the continual operation of EAFB. Many of the persons with these jobs reside in the service territory of Black Hills Power. Many businesses in Black Hills Power's service territory are at least partially dependent upon the operations at EAFB. The exact economic impact from a closing of EAFB on Black Hills Power's electric sales cannot be estimated. While the impact would be felt, there are other businesses that would not be affected and are experiencing growth for other reasons in Black Hills Power's electric service territory. While the future of EAFB is not certain, management believes that the mission of EAFB assures that the base will continue. Emphasis on reducing the budget deficit and the deemphasis of military spending are expected to result in additional military base closings. The independent commission that recommends base closings is expected to make its recommendations in 1995 for the next base closings. If the United States Congress or the Administration does not interfere with those recommendations, those bases as recommended for closing are expected to be subsequently closed. There are many criteria used by the independent commission in making its decision, but three of the most important considerations are the strategic importance of the mission of the base, civilian encroachments interfering with the safe operation of the base, and the amount and timing of the savings or payback to the government resulting from such closings. EAFB personnel have been complaining about certain civilian business and housing encroachments to the flight line of the base. The City of Box Elder and the State of South Dakota are expected to take corrective action to satisfy those complaints, but no assurances can be given that the encroachments will be eliminated. Box Elder has already placed a moratorium on new buildings in the encroachment zone. Because of the large number of employees at EAFB and the cost of maintaining EAFB, a large savings would result to the Department of Defense from the closing. The Company believes, however, that the strategic mission of the base (the training, maintenance and operation of the B-1 bombers) and the open, low-populated area in western South Dakota and eastern Wyoming that is available for practicing bombing runs along with strong community support of the base should result in no EAFB closing. This may depend, however, upon the continual support by the Department of Defense and Congress of the B-1 bomber program. Due to cost overruns and failures of some tactical ancillary equipment along with debates on the need for long-range bombing capability in light of the end of the cold war have caused the B-1 bomber program to be somewhat controversial. This controversy has led to a decision to run the B-1 through extensive tests during 1994. EAFB has announced that those tests will be conducted at EAFB. Currently the Clinton Administration's budget provides for the Air Force to maintain an active, operational B-1 bomber fleet of 50. A fleet of 50 is believed to require the B-1s to be operated from two bases. The current Air Force plan is to base its operational B-1s only at EAFB and Dyess Air Force Base, Texas. The EAFB receives strong support from the Black Hills communities and the State of South Dakota and is the only major military establishment of the Department of Defense located in South Dakota. For all of these reasons, the Company believes that the EAFB will survive the next round of base closings, but the Company can give no assurances. Two other major industries in Black Hills' service territory suffering some stress are the lumbering industry and gold mining industry. The lumbering industry has already suffered substantial cutbacks due to government cutbacks in timber harvesting. Some impact has already occurred. The gold mining industry, including Homestake Mining Company (representing 11.8 percent of Black Hills' total firm KWH sales in 1993 and 8.2 percent of firm electric sales revenue) depends largely upon the price of gold and continuing to find economically minable ore reserves. Homestake has gradually over the years reduced the number of employees, and this impact has substantially occurred. Homestake recently abandoned a deep exploration program 6,000 feet underground to a location north of its present mine to locate another ore body that would have economically justified the construction of another shaft and the extension of the underground mine for several years. However, Homestake did recently report the discovery of some additional deep reserves at its present underground mining location below the 7,000-foot level. Unless a substantial reduction in the current price of gold occurs, the Company believes that the gold mining industry will be stable in the Black Hills area for at least the next ten years; however, the life of mines cannot be predicted, and no assurances can be given. The new industry of low stakes casino gambling at Deadwood (located in Black Hills Power's service territory) continues to experience modest growth despite the South Dakota voters' rejection of raising the $5 betting limit to $100. The Black Hills area continues to attract new small businesses and retirees who are attracted by a quality place to live. ELECTRIC SALES--WHOLESALE. At this time the only firm wholesale customer of Black Hills Power is the municipal electric system at Gillette, Wyoming. Service is rendered under a long- term contract expiring July 1, 2012 wherein Black Hills Power undertakes the obligation to serve the City of Gillette 60 percent of its highest demand and that associated energy as if the demand served by Black Hills Power was always Gillette's first demand. The agreement also allows Gillette to obtain the benefits of a 4,000 kilowatt average firm power purchase agreement from WAPA. Gillette's highest demand to date is 38.78 megawatts, making Black Hills' current base load obligation to serve 23 megawatts. The most recent average yearly capacity factor of this 23 megawatt demand has been approximately 80 percent. Revenue from sales to Gillette represented 8 percent of revenue from total sales in 1993. Black Hills Power is further obligated to serve the next increment of 10 megawatts of Gillette's demand above 33 megawatts if Gillette is unable to obtain other sources. Subject to certain emergency conditions, once Black Hills Power serves a full increment of another 10 megawatts, that increment is added to Black Hills Power's firm obligation to serve. When Gillette serves 10 megawatts, that increment is added to Gillette's firm obligation to serve. At this time Gillette has obtained resources to serve its load above the 60 percent of base load obligation of Black Hills Power. However, Gillette's resources come from short-term contracts, so Black Hills Power is required to stand by to serve a 10 megawatt increment of capacity to Gillette. Other than this firm sale to the City of Gillette, Black Hills Power has made only minimal energy sales to other utilities. FUTURE WHOLESALE OPPORTUNITIES. Black Hills Power has not had sufficient surplus resources in the past to effectively engage in the wholesale electric market. Therefore, to date Black Hills Power has not developed any wholesale markets other than the Gillette sale. If utility retail sales do not increase as expected, the addition of Neil Simpson Unit #2 may result in surplus power and energy. In that event, Black Hills Power would explore all possible avenues to sell that surplus power. Due to the inability to serve firm power to the east of Black Hills Power's service territory without high-cost AC-DC-AC converter stations because of the incompatibility of the east and west transmission systems, Black Hills Power's opportunities for wholesale sales are restricted to the western system. Black Hills Power maintains two firm interconnections to the western system, one with WAPA's western transmission system at Stegall, Nebraska and one with Pacific Power's transmission system at the Wyodak Plant. These two interconnections give Black Hills Power the potential ability to sell power wholesale to any utility entity in the western part of the United States if transmission charges are paid. See--COMPETITION IN ELECTRIC UTILITY BUSINESS - --TRANSMISSION ACCESS under this Item 1. Whether physical transmission limitations exist that would restrict such sales by Black Hills Power is unknown for any particular sale, but Black Hills Power believes that the western transmission system is adequate at this time to accommodate the relatively small sale of wholesale power required for Black Hills Power to sell any surplus resulting from Neil Simpson Unit #2. The revenue received from such a sale would depend on transmission costs, the type of sale Black Hills Power would make (i.e., firm long-term or short-term, capacity sale with minimum energy or base load sale with maximum energy, unit power from Neil Simpson Unit #2 only or system power with reserves), and the competitive market at the time such sale is made. The needs of Black Hills to serve its present retail and wholesale commitments and the regulatory treatment of Neil Simpson Unit #2 will govern the type of power and energy sale Black Hills Power would be able to make. All of these conditions are unknown at this time, but Black Hills Power will be carefully studying these conditions as the operating date for Neil Simpson Unit #2 approaches. ELECTRIC POWER SUPPLY GENERAL. In 1993 Black Hills Power retired three 5 megawatt low-pressure units at the Kirk Station. Obsolescence and high costs of operation made these units no longer economical to operate and maintain. Black Hills Power owns generation with a nameplate rating totalling 283.21 megawatts. See--UTILITY PROPERTIES under Item 2. Black Hills Power also purchases electric power from other entities. See--PACIFIC POWER COLSTRIP CONTRACT, TRI-STATE CONTRACT, RESERVE CAPACITY INTEGRATION AGREEMENT, and SUNFLOWER AGREEMENT following. RESERVES. Black Hills Power is not a member of a power pool. To meet its reserve margin, Black Hills Power utilizes the criteria established by the Western System Coordinating Council, a voluntary technical review and standard setting association composed of all electric utilities in the western United States. This criteria generally requires resources in reserve that are capable of (i) replacing the most severe single contingency, (ii) plus 5 percent of the utility's firm load responsibilities without firm purchased power and (iii) an allowance for auxiliary operations for the lost generator. Currently the most severe single contingency for Black Hills Power is the loss of its 20 percent interest in the 330 megawatt Wyodak Plant. Neil Simpson Unit #2 with a normal capability of 80 megawatt will be Black Hills Power's largest generation resource when it comes into commercial operation in late 1995 or early 1996 and, therefore, the most severe single contingency. Generating plants' capabilities to generate power will change depending on ambient air temperatures. Generally, a power plant's net output capability is higher in the winter and lower in the summer. Therefore, the reserve margin, the loss of the largest unit, is less in summer (because the unit generates less power) than in the winter. One reserve margin test is to determine the reserve margin based on a summer rating, a time when generators are producing less power and the utilities' requirements are at their peak. The following chart illustrates a Black Hills Power estimated summer rating reserve calculation for 1994 as compared to 1996 when Neil Simpson Unit #2 is expected to be in commercial operation. Reserve Analysis--Estimated (1)Net Dependable Capability-- Summer Rating
1994 1996 Base Load Resources kilowatts kilowatts Osage Station--3 units 30,450 30,450 Kirk Plant 16,100 16,100 Ben French Station--Coal unit 21,600 21,600 Neil Simpson Unit #1 14,600 14,600 Wyodak Plant (20%) 59,000 59,000 Neil Simpson Unit #2 (4) 72,000 Pacific Power Colstrip Contract 75,000 75,000 Tri-State Contract(2) 20,000 Total Base Load Resources 236,750 288,750 Peaking Resources Ben French Station --Combustion Turbines 67,200 67,200 --Diesel Units 10,000 10,000 Pacific Reserve Integration Agreement 32,800 32,800 Sunflower Peaking Contract(3) 40,000 Total Peaking Resources 150,000 110,000 Total Base Load and Peaking Resources 386,750 398,750 Less: Reserves 71,000 82,000 Resources to Serve Load, less reserves 315,750 316,750 _________________________ (1) See--UTILITY PROPERTIES under Item 2 for the nameplate rating of Black Hills Power's generating resources. (2) Tri-State contract can be extended for 40 megawatts of firm capacity and energy to December 31, 1997. Black Hills Power can cancel agreement for 1996. (3) Sunflower contract expires September 30, 1996. (4) This assumes Neil Simpson Unit #2 is in production in 1996.
PACIFIC POWER COLSTRIP CONTRACT. Additional base load power was acquired by Black Hills Power through a 40-year purchased power agreement executed in 1983 with Pacific Power. The agreement provides that Black Hills Power purchase from Pacific Power 75 megawatts of electric power and associated energy until December 31, 2023. The price for the power and energy is based on Pacific Power's annual levelized fixed cost and variable cost in Units 3 and 4 of the Colstrip coal-fired generating plant located near Colstrip, Montana and a fixed payment for transmission. Although Black Hills Power's payments are based upon Units 3 and 4, Pacific Power has agreed to deliver the power and energy from its system, notwithstanding the operational capabilities of Units 3 and 4, at a load factor varying from a minimum of 41 percent to a maximum of 80 percent as scheduled monthly by Black Hills Power. Under the agreement, Black Hills Power would not be obligated to pay capacity and energy charges for power not delivered because of a default by Pacific Power in delivering electric power. The Company has incurred capacity charges of $18,000 to $19,000 per megawatt month and $13 per megawatt hour over the last three years of this agreement. The Company's load factor related to this contract has been approximately 68 percent over the last three years. The energy purchased under this agreement in 1993 was approximately 23 percent of Black Hills Power's expected total requirements. See RATE REGULATION under this Item 1. TRI-STATE CONTRACT. In 1992 Black Hills Power entered into a firm capacity and energy purchase agreement under which Tri-State Generation and Transmission Association, Inc., a rural electric cooperative headquartered in Colorado, has agreed to supply Black Hills Power 20 megawatts of firm capacity and associated energy up to a 75 percent capacity factor commencing October 1, 1993 and continuing to December 31, 1997 for a capacity charge of $8,400 per megawatt month and $16 per megawatt hour. Black Hills Power has the option to be exercised by September 1, 1995 to terminate the contract at a date earlier, but not before December 31, 1995, if Black Hills Power anticipates that Neil Simpson Unit #2 will commence commercial operations at the time of termination. Black Hills Power further has the option to purchase an additional 20 megawatts up to December 31, 1997 at a capacity charge of $8,900 per megawatt month if a one-year notice is given and $9,400 per megawatt month if a six-month notice is given. RESERVE CAPACITY INTEGRATION AGREEMENT. Black Hills Power entered into a reserve capacity integration agreement in 1987 with Pacific Power under the terms of which for a period of 25 years Pacific Power shall have the right to schedule power that is produced from Black Hills Power's four 25 megawatt combustion turbines; and in return Pacific Power shall make available to Black Hills Power during the 25 years, at Black Hills Power's option, 100 megawatts of reserve capacity from Pacific Power's system. Black Hills Power shall have the right to schedule power from this reserve only at such times when Black Hills Power, under prudent utility practice, would have operated the combustion turbines. At such times that Black Hills Power schedules Pacific Power's reserves, it has agreed to pay (i) Pacific Power's incremental costs of generation (largely the cost of coal) from a Pacific Power coal-fired plant operating as of the time of the schedule or (ii) the cost of fuel (oil or natural gas) for the combustion turbines, whichever is lower in price. Notwithstanding Pacific Power's rights to the combustion turbines, Black Hills Power reserves a prior right to schedule power from the combustion turbines if required to serve its customers because of transmission outages or low voltage conditions. The agreement further requires Pacific Power to pay the operation and maintenance expenses of the combustion turbines, except for property taxes and insurance, during the 25 years, and pay Black Hills Power $50,000 per month for the entire 25-year period. This reserve integration agreement was a part of the PacifiCorp Settlement as outlined in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the Annual Report to Shareholders of the Company for the year ended December 31, 1993, on pages 12 through 18, incorporated herein by reference. SUNFLOWER AGREEMENT. In 1993 Black Hills Power entered into a Peaking Capacity Agreement with Sunflower Electric Power Cooperative ("Sunflower"), a rural electric cooperative headquartered in Kansas. Sunflower agreed to supply Black Hills Power for a period of three years commencing October 1, 1993, seasonal firm peaking capacity with a monthly load factor of 15 percent. For winter seasons the contract provides for 15 megawatts in the 1993-94 winter and 20 megawatts and 30 megawatts in the next two winter seasons, respectively. For the summer season, the contract provides 40 megawatts for 1994, 50 megawatts for 1995 and 20 megawatts for 1996. The term of the sale may be extended from year to year if neither party cancels the agreement. The sale is conditioned upon WAPA agreeing to maintain a transmission path for Sunflower for delivery to Black Hills Power at Stegall, Nebraska. Black Hills agreed to pay Sunflower for the capacity purchased $3,200/megawatt month for 1993, $3,780/megawatt month for 1994, $4,410/megawatt month for 1995 and $4,630/megawatt month for 1996. For the energy purchased Black Hills agreed to pay Sunflower's peaking fuel cost plus a charge for operation and maintenance costs and overhead, estimated to be $34.20/megawatthour. The cost of all power purchased is either included in rates or is substantially being passed through to customers under automatic fuel and purchased power adjustment provisions in Black Hills Power's rates. See RATE REGULATION--SOUTH DAKOTA REGULATION under this Item 1. Black Hills Power purchased additional non-firm, short-term power during 1993 from other electric power suppliers. NEIL SIMPSON UNIT #2. Neil Simpson Unit #2, an 80 megawatt coal-fired electric generating plant to be located adjacent to Wyodak Resources' coal mine near Gillette, Wyoming, is now under construction by Black Hills Power. The new plant will increase Black Hills Power's current utility rate base approximately 58 percent. See--RATE REGULATION--GUARANTEE OF THE CONSTRUCTION COSTS OF NEIL SIMPSON UNIT #2 under this Item 1. Neil Simpson Unit #2 will be equipped with a pulverized coal boiler with low NOx burners and overfire air to control NOx emissions, a circulating dry scrubber and electrostatic precipitator to control SO2 and particulate emissions. See--ENVIRONMENTAL REGULATIONS--AIR QUALITY--EMISSION LIMITATIONS AT NEIL SIMPSON UNIT #2 under this Item 1. The plant is being designed to be capable of generating at 70 degrees F ambient air temperature a minimum of 80 megawatts net of the power required to operate the plant. The new plant, in the opinion of management, will allow Black Hills Power to keep its rates competitive, to provide for an orderly retirement of existing generation, to capture low construction and financing costs and to stabilize the Company's earnings. While benefiting the Company and its shareholders, Black Hills Power's electric customers will also benefit from what management believes to be its lowest cost alternative to continue providing reliable electric service on a long-term basis. Black Hills Power commenced construction of Neil Simpson Unit #2 in August of 1993, and commercial operation is scheduled by December 31, 1995. The estimated capital costs of Neil Simpson Unit #2 are $113,624,000 plus $11,265,000 of allowance for funds used during construction for a total estimated capital cost of $124,889,000. All governmental construction permits required to construct Neil Simpson Unit #2 were obtained by Black Hills Power. The construction permits are all in full force and effect, and there is currently no litigation or appeals pending affecting those permits. Whether the SDPUC and WPSC allow the new facility in rates will be determined at a later time. See--RATE REGULATION--1995 RATE CASES under this Item 1. In obtaining all governmental permits to construct Neil Simpson Unit #2, Black Hills Power committed to maintain certain levels of pollutant emissions (see--ENVIRONMENTAL REGULATION--AIR QUALITY--EMISSION LIMITATIONS AT NEIL SIMPSON UNIT #2 under this Item 1), committed to a guarantee of the construction costs (see - --RATE REGULATION--GUARANTEE OF THE CONSTRUCTION COSTS OF NEIL SIMPSON UNIT #2 under this Item 1), committed Wyodak Resources to a coal contract (see--COAL SALES--CONTRACT TO SUPPLY COAL TO NEIL SIMPSON UNIT #2 under this Item 1) and committed to certain other regulatory studies (see--RATE REGULATION--OTHER REGULATORY CONDITIONS OF APPROVING OF NEIL SIMPSON UNIT #2 under this Item 1). See--CONSTRUCTION AND CAPITAL PROGRAMS--FINANCING NEIL SIMPSON UNIT #2 under this Item 1. RATE REGULATION GUARANTEE OF THE CONSTRUCTION COSTS OF NEIL SIMPSON UNIT #2. The Company has guaranteed to the WPSC and the SDPUC that the Company will never include in rate base for the determination of electric rates in those jurisdictions those capital costs of Neil Simpson Unit #2 which exceed $124,889,000 (the "Guaranteed Cost"), including allowance for funds used during construction. The Company currently receives from retail sales in South Dakota and Wyoming approximately 91 percent of all electric revenues. The Guaranteed Cost does not include the costs of additions to Neil Simpson Unit #2 subsequent to commercial operation or the operating costs of the plant. Due to the Guaranteed Cost, the Company would likely be forced to write off against earnings any construction costs of Neil Simpson Unit #2 in excess of the Guaranteed Cost. Black & Veatch Architects/Engineers of Kansas City, Missouri is furnishing the Neil Simpson Unit #2 design, engineering, and construction management services for a fixed fee. Contracts have been entered into with a general contractor and with other contractors and vendors to provide the various components of Neil Simpson Unit #2, such as the boiler, the turbine generator, the air quality control system, the condenser, the distributive control information system, the structural steel, the transformers, the coal silo and the coal conveying system. All contracts provide for either fixed contract sums or fixed unit prices. The Company estimates that as of March 1, 1994, contracts have been entered into with contractors and vendors providing approximately 90 percent of the completion costs of the project. The balance of the contracts yet to be entered into are for certain supplies and small components and are expected to be finalized by April 1994. The contract between the Company and the architect/engineer provides that Black & Veatch will furnish the Company an estimate of the costs of completing the construction of Neil Simpson Unit #2 on which the engineer represents that the Company can rely with a high level of confidence. The contract provides for damages, both direct and consequential, not to exceed $35 million for any damages incurred by the Company arising out of the negligence of the architect/engineer in performing the contract. Each of the contracts for the various components of the construction of Neil Simpson Unit #2 provide for certain obligations to correct defective work, warranties and liquidated damages provisions which the Company believes will provide some compensation to the Company for damages resulting from any failure of the various contractors and vendors to perform. Performance bonds from reputable surety companies have also been required to guarantee performance of all of the erection contracts. However, notwithstanding that the Company believes it has negotiated contracts with reputable businesses requiring damages for breach of performance and sureties to guarantee performance of erection contracts, the Company can give no assurances that Neil Simpson Unit #2 will be constructed on time and within the Guaranteed Cost, and if not, that the Company would be adequately compensated for all damages incurred due to any breaches of contracts. The contracts contain defenses to paying damages if the failure to perform was caused by events beyond the control of the contractors. Unexpected costs can result from various causes beyond the control of any party such as labor unrest, transportation delays, weather conditions, governmental interference and other causes. While the Company believes it has properly protected itself to the extent reasonably possible through its contracts with its architect/engineer and contractors and vendors, the Company, through its guarantee to the SDPUC and the WPSC, did assume the risk of not being able to earn a return on any costs in excess of the Guaranteed Cost caused by (i) events beyond the control of any contracting party, (ii) uncompensated consequential damages and direct damages in excess of contractual liquidated damages and litigation costs resulting from contract breaches, (iii) any inability to enforce contracts or performance bonds due to any unexpected lack of financial responsibility of contractors, vendors or sureties and (iv) costs in excess of estimates for the remaining 10 percent of Neil Simpson Unit #2 for which contracts have yet to be let. As of the date of finalizing this 10-K, the construction of Neil Simpson Unit #2 is proceeding as scheduled. Based upon all current contracts and the estimate furnished by the architect/engineer, the Company expects to construct Neil Simpson Unit #2 within the time as scheduled and at a cost not to exceed the Guaranteed Cost. As of the date of finalizing this 10-K, the guaranteed construction cost of $124,889,000 includes an unallocated contingency of approximately $4,400,000. Black Hills Power receives no bonus or incentive ratemaking benefit if it is able to bring Neil Simpson Unit #2 into commercial operation at total capital costs of less than the Guaranteed Cost. OTHER REGULATORY CONDITIONS OF APPROVING NEIL SIMPSON UNIT #2. As a condition to the WPSC granting a certificate of public convenience and necessity allowing Black Hills Power to build Neil Simpson Unit #2, Black Hills Power agreed to certain regulatory procedures consisting of implementing a cost-effective demand-side management program, establishing and perpetuating an Integrated Resource Planning Advisory Group, studying the feasibility of wind generation and pursuing all reasonable cost containment measures in the construction and operation of Neil Simpson Unit #2 and the overall electric utility operations of Black Hills Power. Management is of the opinion that while these conditions are important and Black Hills Power will comply with all of the conditions, such conditions do not constitute anything more than what Black Hills is required to do as an electric utility under today's regulatory environment. Black Hills Power is in the process of implementing a demand-side management program in attempting to find cost-effective programs that would reduce the demand on Black Hills' system, thereby postponing to that degree the need for further electric power resources. Black Hills Power has implemented the Integrated Resource Planning Advisory Group consisting of members of the staffs of the SDPUC and the WPSC as well as representatives of Black Hills Power and its customers. This group will serve as a communication conduit for Black Hills Power to keep all regulators advised of its continuing integrated resource planning process. 1995 RATE CASES. Black Hills Power expects to file general rate cases during 1995 to request a rate increase which would include the full costs, including allowance for funds during construction, of Neil Simpson Unit #2. Based upon assumptions of load growth, inflation and costs, Black Hills Power anticipates gradual small rate increases during construction of Neil Simpson Unit #2 totaling 2.5 percent by the operation of automatic fuel and power purchased adjustment tariffs that have been approved in all jurisdictions in Black Hills Power's service area. Neil Simpson Unit #2 is expected to increase Black Hills Power's electric utility rate base approximately 58 percent. Taking into account the reduction of purchased power expense when Neil Simpson Unit #2 is placed into operation and other projections, the 1995 general rate filing is projected to result in a 10 percent increase in total revenue. Percentages of increases for different customer classes will vary depending upon final approved cost of service allocations. In granting Black Hills Power's application to the WPSC for a certificate of public convenience and necessity on June 2, 1993 authorizing Black Hills Power to construct Neil Simpson Unit #2, the WPSC found that Neil Simpson Unit #2 provides Black Hills Power the least cost approach, consistent with adequate and reliable service, to the resource needs of Black Hills Power and its customers; and Neil Simpson Unit #2 is a sensible resource addition choice for Black Hills Power. On May 26, 1993, the SDPUC issued an order denying a request by Rosebud Enterprises, Inc. ("Rosebud") that the SDPUC determine Black Hills Power's resource needs and the avoided costs of the needed resource and to establish a legally enforceable obligation requiring Black Hills Power to purchase power from Rosebud to be generated from a waste fuel facility that would be qualified under the Public Utility Regulatory Policies Act. The SDPUC further denied Rosebud's request to issue an order finding that Black Hills Power may be imprudent to proceed to construct Neil Simpson Unit #2. The SDPUC did find that Black Hills Power has in good faith planned and permitted Neil Simpson Unit #2 in order to fulfill Black Hills Power's duty to serve its customers. However, the SDPUC made no finding of prudency or imprudency concerning Black Hills Power's decision to proceed with the construction of Neil Simpson Unit #2. The Commission did find that it had no authority under South Dakota law to make its own determination as to a utility's need for additional capacity or the timing of that need. The Commission found that it has established a strong precedent of placing the risk of determining the need for construction of new facilities and the timing of that need on each utility serving in South Dakota. It stated that South Dakota utilities have a duty to serve their respective service areas under South Dakota law, including the decision to add capacity. The Commission found that it would review the prudency of capacity additions only when a utility attempts to include the additional capacity in rates. Neither the WPSC nor the SDPUC has made any determinations of rate treatment resulting from Neil Simpson Unit #2. These decisions are expected to be made in response to the 1995 general rate filings when Black Hills Power will request the full inclusion of Neil Simpson Unit #2 into rate base. While Black Hills Power believes that both the WPSC's and the SDPUC's orders were supportive of Neil Simpson Unit #2, the Company can give no assurances that the regulatory commissions will allow the full cost of Neil Simpson Unit #2 in rate base. Questions concerning the prudency of Black Hills Power to construct Neil Simpson Unit #2 may arise in the rate proceedings, and Black Hills Power assumes the risk of being able to prove to the regulatory commissions that Black Hills Power did need Neil Simpson Unit #2 and was prudent to construct the plant. If the impact of rate increases is high on a customer class, some regulatory commissions will find reasons to phase in the rate increases over a period of time after construction. Sometimes regulatory commissions will initially allow only the debt portion of the cost of new plant and disallow all or a part of the equity portion if the commissions find that management was either imprudent in building a power plant or the utility assumed the risk that the plant would be needed when completed. The result of such rulings would be to deny the Company a return on a portion of their investment in new plant until such time as the entire plant is included in the rate base. The justification of regulatory commissions in second-guessing utilities as to the need for new plant is that the risk of building new plant is on the utility and not the customer. While Black Hills Power will urge that such rulings would be unfair and the Company should not be penalized if an unforeseen event occurs beyond the control of the Company, the Company can give no assurances that it will be successful in getting the entire construction cost of Neil Simpson Unit #2 in rate base if to do so will result in what may be considered as onerous rate increases to some of the customer classes. If Black Hills Power is not in a surplus power condition at the time of the rate case, management believes that they should be successful in getting the entire plant into rate base. Black Hills Power does not believe it will be in a surplus condition. See--ELECTRIC POWER SALES AND SERVICE TERRITORY and ELECTRIC POWER SUPPLY--RESERVES under this Item 1. If, on the other hand, Black Hills Power is perceived by the regulators to be in a surplus power condition at the time Neil Simpson Unit #2 comes into commercial operation, there is a higher probability of the disallowance of a portion of Neil Simpson Unit #2 in rate base for a period of time. The Company believes that even if Black Hills Power is in a surplus power condition at the time Neil Simpson Unit #2 comes into commercial operation and a portion of Neil Simpson Unit #2 is not allowed in rate base, Black Hills Power should be able to make up the deficit in revenue by sales of the surplus power to other utilities until such time that the power is needed for Black Hills Power's customers or sell a portion of Neil Simpson Unit #2. Management believes that there will be a sufficient need for power in the area that such sales are probable. However, management can give no assurances that such market will exist and that the market prices for the power contract terms Black Hills Power could offer will be satisfactory. See--ELECTRIC POWER SALES AND SERVICE TERRITORY--FUTURE WHOLESALE OPPORTUNITIES and ELECTRIC POWER SUPPLY--RESERVES under this Item 1. SOUTH DAKOTA REGULATION. In South Dakota, representing 84 percent of revenue from total 1993 electric sales, Black Hills Power has not had a formal rate case before the SDPUC since 1982. However, as a result of an investigation by the SDPUC concerning the effect of the reduced corporate income tax rates under the Tax Reform Act of 1986 and affiliated transactions, the SDPUC in 1988 allowed Black Hills Power to include in its base rates the full cost of purchased power under the Pacific Power 40-year contract. South Dakota law and the SDPUC allow Black Hills Power to incorporate in its rates automatic adjustment clauses which allow all increases and decreases in the cost of purchased power and fuel to be added to or subtracted from rates without a rate case or order from the SDPUC. However, the clauses place a limitation on that portion of the cost of coal purchased by Black Hills Power from its affiliate Wyodak Resources which can be allowed in rates. This limitation provides that Black Hills Power may not include in rates any cost of coal which allows Wyodak Resources to earn a return on equity on sales to Black Hills Power in excess of a percentage equal to (i) the average interest rate paid by electric utilities with an "A" rating on long-term bonds plus (ii) 400 basis points (4%). The return on equity is calculated as of each April 1 and applied to determine if any refund is due for the cost of coal passed on to rate payers during the previous calendar year. If a refund is due, the refund is credited without interest over the 12 months following the April 1 date of calculation. Black Hills Power estimates that the return on equity to be applied in 1993 to determine the refund will be 11.6 percent. The Company has accrued $1,060,000 in 1993 in anticipation of what Black Hills Power estimates the refund to be for 1993 under this adjustment clause. The SDPUC rate order specifically provides that the limitation applies only to purchases by Black Hills Power, which tonnage sales represented 33 percent of Wyodak Resources' total sales of coal in 1993. Retail rates in South Dakota decreased approximately 4 percent in 1993 over 1992. WYOMING--RETAIL. In Wyoming, where revenue from retail sales represented 7 percent of revenue from total electric sales in 1993, Black Hills has not had a formal rate case before the WPSC since 1981. Every three months, Black Hills Power files an application to adjust rates to reflect changes in the cost of purchased power. The WPSC has been consistently approving these applications. Retail electric rates in Wyoming averaged 0.7 percent lower in 1993 than 1992. MONTANA. Black Hills Power's revenue from sales of electric power in Montana in 1993 represented only 1 percent of revenues from total sales. The last formal rate application in Montana was in 1983. Every three months, Black Hills Power files an application to adjust rates to reflect changes in the cost of fuel and purchased power. The Montana Public Service Commission has been consistently approving these applications. WYOMING--WHOLESALE. The only wholesale customer of Black Hills Power is the City of Gillette, Wyoming. See--ELECTRIC POWER SALES AND SERVICE TERRITORY--ELECTRIC SALES--WHOLESALE. The rates paid by Gillette are subject to regulation by the FERC. Either party may apply to the FERC for rate modifications. The current rates were determined by negotiations between Gillette and Black Hills Power. None of the above-referenced rate orders and rate adjustments caused Black Hills Power to earn less than a rate of return which would have been allowed by any of the regulatory commissions through a general rate case filing. Black Hills Power has not experienced major problems in the recent past with regulatory bodies allowing it to increase its rates on a timely basis and allowing all operating costs and electric plant in rate base, but no assurances can be given that major problems will not occur in the future. COMPETITION IN ELECTRIC UTILITY BUSINESS COMPETITION IN SERVICE AT RETAIL. In addition to Black Hills Power, RECs and the federal government through WAPA provide electric service in and around the service territory of Black Hills Power. WAPA retails electric service to certain government facilities. Black Hills Power and the RECs serve in territories which are protected by state laws or regulations which generally give each entity the exclusive right to serve retail in its respective territory; however, these laws or regulations are subject to change and there are certain exceptions. In South Dakota, the SDPUC may allow a new customer with a load of over 2,000 kilowatts to choose to be served by a utility other than the utility in whose territory the new customer locates. Each municipality in Black Hills Power's service territory has the right upon meeting certain conditions to acquire or construct a municipally-owned electric system and to serve the customers within its city. Black Hills Power is not aware of any such movement by any municipality in its service territory, which does not already have a municipally-owned electric system, to create one. In Wyoming, public utilities operate in service territories assigned by the WPSC, and a franchise granted by the municipality's governing body is required to serve within the said municipality. Black Hills Power's franchise for the City of Newcastle, Wyoming, representing approximately 2,000 customers and 6 percent of Black Hills Power's electric revenue, expires in 1999. The franchise may be renewed by action of the city's common council. Black Hills Power may apply for and obtain the right to serve in another utility's electric service territory if it is found to be in the public interest to do so, but such applications are rarely granted. The respective service territories of Black Hills Power and the RECs were assigned originally on the basis of where each was serving at the time of assignment. Since the RECs were serving in rural areas (the purpose for which they were formed), a large portion of the rural area surrounding the municipalities in which Black Hills Power serves constitutes REC service territory. Although Black Hills Power has traditionally served considerable territory outside of municipalities and, therefore, has been assigned a large amount of such territory, the RECs have the largest portion of such area and, if the laws are not changed, will over a long period of time tend to receive a larger portion of the growth of the population centers. To assist in the planning of new resources and to minimize the risk of the loss of large loads, Black Hills Power does endeavor to contract with its large industrial users to serve all electric power needs for a term of years. Currently Homestake Mining Company is under a 9-year contract to purchase all of its electric power requirements, the South Dakota State Cement Plant is under a similar 6-year contract and the City of Gillette (See--ELECTRIC POWER SALES AND SERVICE TERRITORY--ELECTRIC SALES--WHOLESALE) is under an 18-year contract for 60 percent of its base load. These three customers together in 1993 accounted for 29 percent of Black Hills' total firm KWH sales and 21 percent of firm electric sales revenue. The primary competing fuel in Black Hills Power's territory is natural gas which is available to approximately 80 percent of its customers. COMPETITION IN ELECTRIC GENERATION. Under the Public Utility Regulatory Policies Act, certain small power generators burning waste fuel and renewable fuel and certain cogenerators that utilize excess steam for a purpose other than power generation are deemed to be qualified facilities and the owner can force an electric utility such as Black Hills Power to purchase power for its avoided costs. Generally avoided costs are those costs that would be avoided if it purchased power from the qualifying facility. To date Black Hills Power's only interface with qualifying facilities under PURPA was the attempt by Rosebud Enterprises, Inc. to build a waste fuel facility and sell power to Black Hills Power to avoid the building of Neil Simpson Unit #2. See--RATE REGULATION--1995 RATE CASES under this Item 1. In addition to competition from RECs and the federal government from central station sources, Black Hills Power could face the competition of industrial and public customers constructing self-generation facilities using alternative fuels, such as waste material, natural gas or oil. To date Black Hills Power has not faced any material competition from such sources. Management does not believe that such sources are cost effective but can give no assurances that material competition from these sources will not occur. Under the new federal Energy Policy Act of 1992, a new class of wholesale-only electric generators, referred to as exempt wholesale generators (EWGs) was created. The EWGs are now exempt from the Public Utility Holding Company Act of 1935 (PUHCA). Under PUHCA, the parent company of a participant in a power project could become a public utility holding company subject to PUHCA, resulting in unacceptable restrictions and regulations. To some extent this impediment to creating EWGs as a subsidiary of a nonutility company has now been removed. An EWG must be engaged exclusively in the ownership and/or operation of "eligible facilities." An "eligible facility" is an electric generating facility whose output is sold only at wholesale. An EWG is not subject to restrictions relating to type of fuel, maximum size, technology or permissible utility ownership as a qualifying facility is under PURPA. An EWG is subject to regulation by the FERC. A regulated electric utility may purchase power from an EWG in which the utility has an interest if each state commission with regulatory authority over the purchasing utility's retail rates approves such transaction. The Energy Policy Act of 1992 encourages independent power producers to effectively compete with qualifying facilities under PURPA and the electric utility itself to construct the future electric generation as it is needed. Black Hills Power's experience with competing qualified facilities and the effect of the new Energy Policy Act of 1992 indicate that Black Hills Power will be challenged by other alternatives each time it proposes to build generation. To be able to build its own generation, Black Hills Power will have to demonstrate under an integrated resource plan that its proposal is the least cost and most reliable of all other proposals. As a result of this competition, Black Hills Power is not necessarily going to be the sole generator of its future power requirements as it was in the past. The Energy Policy Act of 1992 does not prevent the Company from engaging in the business of an independent power producer in other utilities' service territories and could lead to additional opportunities for the Company in the future due to the Company's coal fuel supply with mine-mouth plants that have been permitted. TRANSMISSION ACCESS. The Energy Policy Act of 1992 granted the FERC broad authority to mandate transmission access to the EWGs as well as others engaged in wholesale power transactions. Under the new law, any electric utility or any other entity generating wholesale energy may apply to FERC for an order requiring a utility to transmit such energy, including enlargement of relevant facilities. If the utility refuses to wheel or furnish transmission service to an independent power producer, the FERC may, but is not required, order wheeling in response to an application. FERC is not to order wheeling if to do so would impair the transmitting utility's reliability of service. The new law does provide for the transmitting utility to obtain its full cost of transmission service, to be determined by the FERC. The new Energy Policy Act of 1992 specifically prevents the FERC from ordering wheeling to end users (retail wheeling). Black Hills Power does now furnish transmission service for competing RECs and for its only wholesale customer, the City of Gillette, Wyoming. Therefore, the Energy Policy Act is not likely to have any effect in allowing transmission access by other electric utilities serving at retail. However, the Energy Policy Act can require Black Hills Power to furnish transmission service for competing EWGs and qualifying facilities, thereby increasing competition for Black Hills Power. As long as the states in which Black Hills Power operates continue to grant exclusive service territories and the federal government does not preempt this state jurisdiction, the increase in transmission access through the Energy Policy Act of 1992 through Black Hills Power's transmission system is likely not to have an effect upon Black Hills Power. However, if the electric rates of Black Hills Power become noncompetitive with alternative sources of power or such a trend develops throughout the country, further pressure on both Congress and the state legislators for more competition could result in modifications to the utility's service territory and retail wheeling could be mandated, all of which could have an adverse effect upon Black Hills Power's electric business. On the other hand, if Black Hills Power can continue to acquire low- cost new generation and can offer power at competitive rates, retail wheeling may become a positive opportunity for the Company. PRICE COMPETITION. Each of Black Hills Power and the RECs serving around its service territory offers a package of rates and services designed to recognize the costs and needs of various customer classes. The following rate comparisons are provided to show the difference in cost that typical customers are currently experiencing. REGULAR RESIDENTIAL SERVICE Percentage That REC is Higher (+) Monthly Cost or Lower (-) (500kWh) Than BHP SD - Black Hills Power $41.59 --- SD - Black Hills Electric (REC) $61.70 +48 SD - Butte Electric (REC) $57.64 +39 SD - West River Electric (REC) $52.50 +26 WY - Black Hills Power $38.19 --- WY - Tri-County Electric (REC) $35.34 -8 Small Commercial Service Percentage That REC is Higher (+) Monthly Cost or Lower (-) (6,000 kWh,30 kW) Than BHP SD - Black Hills Power $507.44 --- SD - Black Hills Electric (REC) $410.90 -19 SD - Butte Electric (REC) $389.70 -23 SD - West River Electric (REC) $631.80 +25 WY - Black Hills Power $451.55 --- WY - Tri-County Electric (REC) $300.02 -51 Large Commercial/Industrial Service Percentage That REC is Higher(+) Monthly Cost or Lower(-) (120,000 kWh, 300 kW) Than BHP SD - Black Hills Power $6,406.20 --- SD - Black Hills Electric (REC) $7,053.00 +10 SD - Butte Electric (REC) $8,283.00 +29 SD - West River Electric (REC) $7,827.80 +22 WY - Black Hills Power $6,681.63 --- WY - Tri-County Electric (REC) $6,523.90 -2 Of the group, only Black Hills Power and Tri-County Electric have their rates established by commission order. This allows the South Dakota RECs the opportunity to offer incentive rates and services to commercial and industrial users designed to attract new customers without regulatory review while Black Hills Power may be denied this opportunity by regulation of its rates. As Black Hills Power constructs new generation, its electric rates will need to be increased. (See RATE REGULATION--1995 RATE CASES under this Item 1.) While its REC competitors also have continual needs for new construction, the RECs serving in Black Hills Power's service territory do have available surplus power from Basin Electric at this time. Depending on the timing of construction costs and other economic factors such as power sale fluctuations and other costs and loss or gain of customers of Black Hills Power and its competitors, Black Hills Power's rates could become less competitive with other electric suppliers. However, the RECs could experience higher costs of financing due to government attempts to balance the budget to offset the surplus power advantage. Black Hills Power's management forecasts that its construction program and anticipated load growth will result in rate increases higher than inflation during the next three years but will be lower than inflation when averaged over ten years. If this forecast is accurate, management believes Black Hills Power's rates will remain favorably competitive with other electric suppliers in its service territory. Many factors beyond the control of the Company could affect this, such as higher than expected construction costs, unfavorable regulatory treatment and unexpected loss of load. No assurances can be given in this area. CONSTRUCTION AND CAPITAL PROGRAMS The construction and capital costs for 1993 for its electric, mining and oil and gas production operations were $25,932,000, $7,425,000 and $6,933,000, respectively. The Company reviews its construction and capital program annually. Current estimates of construction and capital expenditures for 1994 through 1996 are as follows:
1994 1995 1996 (IN THOUSANDS) Electric Neil Simpson Unit #2 $65,113 $45,035 $------ Other Production 2,255 859 897 Transmission 4,128 1,617 8,478 Distribution 6,511 6,503 6,876 General 1,448 814 2,354 Total $79,583 $54,828 $18,605 Coal mining $ 2,129 $ 853 $ 2,042 Oil and gas production $ 5,000 $ 6,000 $ 6,000 Total $86,712 $61,681 $26,647
BLACK HILLS POWER. The 1993 construction costs for the Company were financed primarily with internally generated funds, common stock sales and short-term borrowings. The above capital budget includes approximately $110,148,000 for the completion of the design and construction of Neil Simpson Unit #2. See--ELECTRIC POWER SUPPLY--NEIL SIMPSON UNIT #2 under this Item 1. FINANCING NEIL SIMPSON UNIT #2. The Company's plans to finance the construction of Neil Simpson Unit #2 and its other construction program include the sale of additional shares of common stock, the issuance of long-term bonds and the increasing of dividends paid by Wyodak Resources to the Company. In 1993 the Company sold 525,000 shares of additional common stock in a public offering at 25 3/8. Net proceeds to the Company from this sale were approximately $12.7 million. The Company also modified its dividend reinvestment program so that the Company can elect to either issue new stock or purchase stock on the market to satisfy the shareholders' requests to reinvest dividends. The Company's expectations at this time are to raise an additional $4 million of equity capital from the dividend reinvestment program by the time Neil Simpson Unit #2 is operational. To complete the equity portion of the capital budget, the Company plans to cause Wyodak Resources to upstream $45 million of dividends during 1994 and 1995. To finance the debt portion of the construction program, the Company is planning to issue approximately $87 million of long- term bonds under the Company's first mortgage Indenture. The bonds are expected to be issued commencing in mid-1994 and continuing through 1995, probably in two or three issues. Based upon its projections, the financing program is designed to create a capital ratio at the time Neil Simpson Unit #2 becomes operational of 50 percent equity and 50 percent debt for the consolidated Company and 55 percent debt and 45 percent equity for Black Hills Power's capital structure for ratemaking purposes. WYODAK RESOURCES. The capital program of Wyodak Resources includes coal handling facilities and replacement of other mining equipment. Wyodak Resources plans to finance these additions with internally generated funds. During 1993 Wyodak Resources constructed new coal handling facilities in conjunction with Pacific Power. See--MINING PROPERTIES under Item 2. WESTERN PRODUCTION. Western Production's capital program is planned to be devoted primarily to oil and gas development drilling in Texas and the Rocky Mountain Region. Secondary emphasis will be on production acquisitions and exploration drilling. The capital program is planned to be financed with internally generated funds and approximately $3 million of short- term bank borrowings. COAL SALES CONTRACT TO SUPPLY COAL TO NEIL SIMPSON UNIT #2. Black Hills Power and Wyodak Resources entered into the Restated and Amended Coal Supply Agreement for Neil Simpson Unit #2 on February 12, 1993. Under this agreement, Wyodak Resources agrees to supply all of the fuel requirements for Neil Simpson Unit #2 for its useful life and reserve 20 million tons of coal reserves for that purpose. Black Hills Power made a commitment to both the SDPUC and the WPSC that coal would be furnished and priced as provided by this agreement for the life of the plant. Under this agreement, Wyodak Resources agrees that its earnings from coal sales to Black Hills Power (including the 20 percent share on the Wyodak Plant and all sales to Black Hills Power's other plants) will be limited to a return on Wyodak Resources' original cost, depreciated investment base. The return agreed to is 4 percent (400 basis points) above A-rated utility bonds to be applied to a new investment base each year. In addition, Wyodak Resources committed to further reduce the coal price for coal to be used in any of Black Hills' power plants during the period of time that under prudent dispatch that power plant would not have been operated if it were not for the discounted price of coal. In South Dakota (84 percent of Black Hills Power's electric revenues), Black Hills Power is currently precluded from passing on to its customers any cost of coal from Wyodak Resources which would exceed the same rate of return, but the dispatch discount is an additional accommodation not applied at this time. Since Wyodak Resources is expected to incur only minimal additional capital costs to fulfill the coal supply agreement for Neil Simpson Unit #2, Wyodak Resources is not expected to increase its earnings from such sale. Since Wyodak Resources is a subsidiary of the Company, regulators limit the amount of Black Hills Power's coal costs it can include in electric rates charged to its customers. The Company believes that the above methodology requiring Wyodak Resources' return on sales to Black Hills Power to be based on an original cost depreciated investment base will continue to be applied by the SDPUC and the WPSC which regulate approximately 89 percent of the Company's electric sales. However, regulatory commissions may in the future apply a different methodology such as limiting Black Hills Power to include in rates only what the commission determines to be a fair market purchase price of coal. Such fair market purchase price could be less than what Wyodak Resources requires to earn a rate of return on its investment base. Earnings from the intercompany sales of coal at this time represent approximately 7 percent of the Company's consolidated earnings. OTHER SALES. The coal mining industry is highly competitive and significant new sales opportunities are limited. Wyodak Resources operates in an area with many other mining companies which have substantial unused capacity. They, like Wyodak Resources, have the permits and capability for large increases in production. Wyodak Resources has no train load-out facilities and is not able to compete for large coal sales which require unit train (usually 110 cars) loading capabilities, and the current market price for such sales does not support the cost of constructing the necessary facilities. Until coal prices substantially improve, Wyodak Resources' coal sales will be confined to a size less than a unit train and to sales for consumption at or near the mine. Wyodak Resources will have some increased coal sales to fuel Neil Simpson Unit #2, but increased profits from those sales are unlikely. See--COAL SALES--CONTRACT TO SUPPLY COAL TO NEIL SIMPSON UNIT #2 under this Item 1. No assurances can be given that there will be new plants or the degree of profitability of any such new coal sales. See--CORPORATE DEVELOPMENT in this Item 1. Sales and production statistics for the last five calendar years are as follows: Revenue From Sale % Revenue of Coal Derived From Tons of Coal Sold Year (in thousands) Black Hills Power (in thousands) 1993 $29,822 34% 3,027 1992 28,296 35 2,958 1991 26,138 35 2,742 1990 26,528 36 2,908 1989 21,456 37 2,349 Wyodak Resources furnishes all of the fuel supply for the Wyodak Plant in which Black Hills Power owns a 20 percent interest and Pacific Power an 80 percent interest. See Note 6 of "Notes to Consolidated Financial Statements" appended hereto. The price for unprocessed coal sold to the Wyodak Plant is based on a coal supply agreement entered into by Black Hills Power, Pacific Power and Wyodak Resources in 1974 and terminating in the year 2013. This agreement was amended and restated in 1987 as discussed below. Wyodak Resources, Black Hills Power and Pacific Power entered into settlement agreements in 1987 which settled a dispute over the quantity of coal Pacific Power was required to purchase to operate the Wyodak Plant and Pacific Power's obligation to purchase additional coal commencing in 1990 under a contract which would have provided coal for a since canceled second unit at the Wyodak Plant. Said agreements are referred to as the PacifiCorp Settlement which is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1993 Annual Report to Shareholders of the Company on pages 12 through 18, incorporated herein by reference. Revenue from coal sales to the Wyodak Plant totaled $21,438,000 in 1993 or 72 percent of revenue for all coal sold by Wyodak Resources. The quantity of coal sold in 1993 for the Wyodak Plant was 2,118,000 tons, as compared to 2,079,000 tons sold in 1992. Barring unusual periods of maintenance, the quantity of coal for the maximum consumption capability of the Wyodak Plant for one year is approximately 2,100,000 tons and the average yearly consumption is 1,900,000. The average consumption is expected to continue during the remaining 20 years of the coal agreement. However, from time to time, the plant's physical operating capabilities will affect the quantity of coal burned. Wyodak Resources sells coal to Black Hills Power pursuant to an agreement entered into in 1977 and last amended in 1987 which is approximately the same as the original Wyodak Plant agreement except for an additional amount for processing the coal and a discount for all coal delivered in a year in excess of 500,000 tons. Wyodak Resources has reserved sufficient coal, presently estimated at 9,000,000 tons, for the generating plants of Black Hills Power until such plants are retired. Black Hills Power expects its power plants, with the exception of the Wyodak Plant, to continue to consume approximately the same quantity of coal as in 1993 unless unexpected mechanical failures occur. Of the 3,027,000 tons of coal sold by Wyodak Resources in 1993, 1,009,000 tons were sold to Black Hills Power, 1,696,000 tons were sold to Pacific Power and 322,000 tons were sold to others. Wyodak Resources' revenue from sales of coal to Pacific Power and Black Hills Power as compared to its revenue from all sales to other customers for the last three years was as follows: Revenue from All Sales to Unaffiliated Revenue from Revenue from Customers Sales to Sales to(1) (includes Pacific Power Black Hills Power Pacific Power) Year (in thousands) 1993 $17,448 $10,047 $19,775 1990 16,541 9,811 18,485 1991 14,632 9,220 16,918 (1) Is not adjusted for refunds under South Dakota rate order. See--RATE REGULATION of this Item 1. In addition to the coal sold to the Wyodak Plant and to Black Hills Power, Wyodak Resources sells coal to the South Dakota State Cement Plant under an all requirements contract expiring on December 1, 1997. Wyodak Resources sold 240,000 tons under this contract in 1993. Smaller amounts of coal are sold to various businesses and for residential use. All long-term contracts contain adjustment clauses based upon certain costs and government indices. In 1988 Wyodak Resources agreed to the termination of a long-term coal supply agreement with the City of Grand Island, Nebraska. Under this agreement, Wyodak Resources will receive approximately $155,000 per year for 14 years during which Grand Island will have an option to purchase coal. Wyodak Resources has reserved sufficient coal in the eventuality that Grand Island exercises its option. Many factors can significantly affect sales of coal and revenue under the existing contracts. Examples include the seller's or buyer's inability to perform due to machinery breakdown, damage to equipment, governmental impositions, labor strikes, coal quality problems, transportation problems and other unexpected events. OIL AND GAS OPERATIONS SIZE AND COMPETITION. Oil and gas operations have not been a significant percent of the Company's total operations. Net income and assets related to oil and gas operations have been 7 percent or less of the Company's consolidated amounts over the last five years. The oil and gas industry is highly competitive. Western Production encounters strong competition from many oil and gas producers, including many which possess substantial resources, in acquiring drilling prospects and producing properties. MARKETS AND SALES. The Company's oil and gas production is sold at or near the wellhead, generally at posted prices. Gas production is generally sold in the spot market at prevailing prices. Western Production has been able to market all of its oil and gas production. Operating revenue by source for the last five years is as follows: Oil and Gas Gas Plant Field Sales Revenue Services (in thousands) 1993 $7,489 $ 759 $3,148 1992 5,640 701 3,258 1991 4,789 693 3,595 1990 4,240 876 3,480 1989 3,681 1,082 3,581 Quantities and sale prices for oil and gas production are affected by market factors beyond the control of the Company. Such factors include the extent of domestic production, level of imports of foreign oil and gas, general economic conditions that determine levels of industrial production, political events in foreign oil-producing regions and variations in governmental regulations and tax laws. There can be no assurance that oil and gas prices will not decrease in the future. Such declines would decrease net revenues from oil and gas properties and reduce the value of such assets. These declines could result in the write down of certain oil and gas assets. Management estimates that oil prices must average $14 to $15 per barrel for its oil operations to remain profitable. PRODUCTION. Western Production produced approximately 456,000 equivalent barrels of oil in 1993. Approximately 48 percent of this production came from the Finn-Shurley Field which is comprised primarily of stripper wells (wells producing less than 10 barrels per day). DRILLING ACTIVITY. Western Production participated in the drilling of 24 wells in 1993. Western Production's average working interest in such wells was 53.1 percent, or 12.74 net wells. Approximately 83 percent of the wells were classified as development wells and 17 percent were classified as exploratory wells. A development well is a well drilled within the presently proved productive area of an oil and gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir. An exploratory well is a well drilled in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. ENVIRONMENTAL REGULATION The Company is subject to present and developing laws and regulations with regard to air and water quality, land use, land reclamation and other environmental matters by various federal and state authorities. AIR QUALITY EMISSION LIMITATIONS AT NEIL SIMPSON UNIT #2. One of the governmental permits required to build Neil Simpson Unit #2 was a prevention of significant deterioration permit to be granted by the DEQ, Division of Air Quality. On April 14, 1993, Black Hills Power received the permit ("PSD Permit") allowing Black Hills to proceed with the construction of Neil Simpson Unit #2. The PSD Permit sets certain emission rate limitations for pollutants which cannot be exceeded during the operation of Neil Simpson Unit #2. Wyoming law requires that after a 120-day start-up period, Black Hills will require an operating permit. During the start-up period, performance tests are conducted to determine if the plant can be operated within the emission limitations of the PSD Permit. The PSD Permit sets emission rate limitations on particulate, sulfur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide and particulate emissions and opacity limitations. The PSD Permit requires constant monitoring to determine continual compliance with the SO2, NOx and opacity limitations. The SO2 emissions are not to exceed 0.20 lbs./MMBtu on a two-hour rolling average and 0.17 lbs./MMBtu on a 30-day rolling average. To control SO2 and particulate emissions, Neil Simpson Unit #2 will include a circulating dry scrubber and electrostatic precipitator wherein the flue gases from the pulverized coal boiler will be treated in the scrubber with a lime reagent and the matter will be removed by the precipitator. The manufacturer of the scrubber and precipitator has guaranteed particulate and SO2 limitation emission rates sufficient to meet the PSD Permit limitations. The guarantee requires a six-month 100 percent availability and compliance period. The manufacturer further guaranteed under certain conditions for a period of five years corrosion minimums and operation and maintenance costs. The PSD Permit sets the initial NOx emission rate limitation at 0.23 lbs./MMBtu; however, the permit provides that during the first two years of operation if Black Hills Power demonstrates that the 0.23 lbs./MMBtu limitation can be lowered to the manufacturer's guarantee of 0.17 lbs./MMBtu, the Wyoming Department of Environmental Quality reserves the right to lower the NOx emissions limitation permanently. The method of control of NOx for Neil Simpson Unit #2 are low NOx burners with overfire-air controls. The PSD Permit does not require any further devices to remove NOx such as selective catalytic reduction or selective noncatalytic reduction systems. The manufacturer of the boiler for Neil Simpson Unit #2 has guaranteed that the boiler will meet the NOx limitations. The guarantee is based upon tests to be conducted under ideal operating conditions during the 12 months after commercial operation. The boiler is being designed so that a selective catalytic reduction system could be installed if later required to meet the NOx limitations. The Company believes that Neil Simpson Unit #2 is being designed to meet all emission limitations. However, both the SO2 and NOx emission limitations are some of the lowest emission rates in the United States, and flaws in design or unexpected coal quality or other events could cause additional unexpected capital costs in being able to operate with these limitations. EMISSIONS FROM OTHER PLANTS. All of Black Hills Power's generating plants are believed by management to be operating in full compliance with air quality laws and regulations. Applications for continued operation of the Kirk power plant has been submitted for the approval of the South Dakota Department of Environment and Natural Resources ("DENR"). ASBESTOS. Black Hills Power completed the majority of the asbestos removal work at the Osage power plant in 1993. This included that removal work being performed in conjunction with the reinforcement of the walls of the three boiler units. The remaining asbestos at the Osage, Neil Simpson, Kirk and Ben French facilities is believed to be adequately encapsulated. Its removal will occur as other projects necessitate or as deterioration occurs. No cost determination has been made for the additional work required. THE CLEAN AIR ACT AMENDMENTS. Legislation enacted by the Congress of the United States in late 1990 to amend the Clean Air Act will have an impact on Black Hills Power's power plants. All of the power plants other than the Wyodak Plant are made up of units with generating capacity of 25 megawatts or less and are believed to be exempt from most of the limitations and requirements of the Act. All facilities, however, are subject to the payment of fees calculated on the basis of tons per year of emissions of sulfur dioxide, nitrous oxide and particulate. The annual fees for those facilities located in South Dakota totaled approximately $25,000 for 1993. Fee assessments have not yet been made for Wyoming facilities, however, it is estimated that they will not exceed $90,000. According to analyses of emissions from the plant stacks, all four of the power plants operated by Black Hills Power are believed to be operating in compliance with current federal and state law. Black Hills Power does not maintain continuous monitoring on all of these four plants, and unexpected changes in coal quality or problems with plant operations can cause violations which could result in penalties being imposed in the future. Black Hills Power endeavors to operate the plants to prevent such excursions, but the potential remains for human error and equipment failure. The Wyodak Plant is equipped with sulfur removal equipment and the plant is already in compliance with the new sulfur emissions requirements of the Clean Air Act. New equipment is not necessary to bring the facility in compliance with the NOx requirements of the Act, but continuous monitoring equipment for NOx has been purchased and installed at a cost to Black Hills Power of $147,000. The amendments do require a three-year study on designated hazardous pollutants which may result in future regulations, but the impact of that study on the Wyodak Plant is not yet known. AIR ALLOWANCES. The Clean Air Act Amendments put into place a program designed to allow each affected facility to emit into the atmosphere on an annual basis only that quantity of sulfur dioxide for which it has authorization by virtue of its control of air allowances. An air allowance is a right to emit one ton of sulfur dioxide. These allowances are transferable between facilities and can be sold to other owners of power production facilities. As a result of the pollution control equipment already in place at the Wyodak Plant, the Company will be granted beginning in the year 2000 approximately 1,800 allowances per year in excess to the needs of its 20 percent interest in the Wyodak Plant. None of the Company's existing wholly owned power plants will require air allowances. Neil Simpson Unit #2 will require approximately 850 air allowances each year beginning in 2000. Allowances required for Neil Simpson Unit #2 will come from the allowances allocated as the Company's share of the Wyodak Plant. By voluntarily complying with the requirements of Phase I of the Clean Air Act Amendments, and obtaining approval from the Environmental Protection Agency, the Company is expected to be able to receive an advance of its air allowances at the Wyodak Plant for the years 1995 and 1996, that can in turn be sold. This requires a host unit Phase I facility to substitute the Wyodak Plant air allowances for its requirements. The Company has located a host unit Phase I facility and entered into an agreement for the sale of a portion of the Company's allowances as a substitution unit, with the allowances to be taken by the host unit sometime after 1995. This transaction is subject to EPA approval, which is expected to require the Company to then pay these allowances back to EPA ten to twenty years after the sale. Additional sales of allowances prior to the year 2000 by facilities voluntarily complying with Phase I appear to be in serious doubt in view of recent Environmental Protection Agency proposed action. Whether funds received from the sale of air allowances can be retained by the electric utility or flowed through to the benefit of the customers has yet to be determined in the Company's regulatory jurisdictions. NEW MAJOR EMITTING FACILITIES. The Federal Clean Air Act Amendments of August 7, 1977, require states, among other things, to classify their land into control areas to prevent significant deterioration of air quality wherein certain limitations in ambient air quality will be established so as to allow new major emitting facilities (as defined) to be constructed in those areas only if the particulate emissions therefrom together with existing emissions would not cause the ambient air in that area to exceed those limitations. Wyodak Resources is presently authorized to mine up to 10,000,000 tons per year under its permit and existing clean air laws and regulations and the Neil Simpson #2 power plant has been permitted at that site. WATER QUALITY All of the power plants operated by Black Hills Power require permits under the National Pollutant Discharge Elimination System. Renewal applications for the permits for the Ben French and the Kirk power plants have been submitted to the DENR, and the permits for the other facilities are current, including authorizations for storm water discharge. The Osage plant has recently experienced an inability to meet the permit levels for pH at one of its discharge points. The nature of the ash generated at the facility is believed to be the source of the high pH values. The utilization of the new discharge pond at the site has resulted in a shorter period of time to allow the pH to neutralize. Black Hills Power has been working closely with the DEQ and has hired a consultant in an effort to resolve the problem. In- plant treatment efforts have not proven successful. CO2 injection equipment currently being installed at the discharge point is expected, however, to return the effluent to an acceptable pH level. In the event this effort fails, it will be necessary to seek a modification of the permit and utilize a sulfuric acid treatment. The cost of the project including the CO2 equipment is not expected to exceed $20,000. No penalties, claims or actions have been taken against the Company because of the discharge levels, and none are expected. The other plants are in compliance with their stated permit discharge levels. Pollution prevention plans are in place for the plant facilities, and the current Spill Prevention Control and Countermeasures plans are in the process of being updated, and will include hazardous materials contingency plans. LAND QUALITY SOLID WASTE DISPOSAL. Black Hills Power disposes of power plant wastes from its Ben French, Kirk and Osage power plants at several locations at or near each of said plants. Such disposal is done under authority of permits either issued or under temporary authority pending action on applications. An application has been submitted seeking the expansion of the current ash disposal site for the Ben French power plant and is under consideration by the DENR. At Osage, a permit was granted for the new ash dam facility, and use began in October 1993. Applications are pending for reclamation of a historic disposal site at Osage, for renewal and expansion of its landfill permit, and for closure of the old ash dam. Management is not aware of any unusual problems which may arise from locating new sites or from maintaining the existing disposal sites in full compliance with the law. RECLAMATION. Under federal and state laws and regulations, Wyodak Resources is required to submit to and receive approval from the DEQ for a complete mining and reclamation plan (Plan) which provides for the orderly mining, reclaiming and restoring of all land in conformity with all laws and regulations relating thereto. The current approved State Program Permit (Permit) authorizes Wyodak Resources to mine coal for a period of five years up to 1995 in compliance with the Plan and all conditions of the Permit. The Permit is subject to annual reporting and must be renewed after extensive review every five years, at which time the DEQ may impose further conditions. In 1992 Wyodak Resources received a modification of its Permit to include an additional 37,300,000 tons of reserves acquired through coal lease modifications. The Permit imposes a variety of conditions which the DEQ believes are required to comply with applicable laws and regulations and to establish reclamation with a minimal impact on land, water and air. These conditions are continuing and require monitoring of water and land that could reveal factors unknown at this time. The exact costs of complying with these conditions cannot be accurately ascertained until years later when reclamation is completed. Conditions which could result in material unexpected increases in costs of reclamation relate to three depressions, the existing south pit depression and an additional north pit depression and north extension depression which will result from future mining. Because of the thick coal seam and relatively shallow overburden, the present Plan for restoration leaves areas of the mine that will have limited reclamation potential because of their location in depressions with interior drainage only. While the DEQ has allowed these depressions in the present Plan as modified, the DEQ has reserved the right to review and evaluate future mining plans proposed by Wyodak Resources. Such plans are reviewed for the feasibility and desirability of causing Wyodak Resources to place additional overburden generated elsewhere for the purpose of reducing the depressions if the DEQ finds that the placement is necessary to prevent degradation of more acres than expected. Each time Wyodak Resources files an application to mine additional coal reserves, the DEQ extensively reviews the reclamation of the depressions. The DEQ has allowed the depressions at the minimum acres specified, and subject to the maintenance of water quality at the sites. Exceedence of the acreage limitations or degradation of water quality could result in additional requirements being placed upon Wyodak Resources, including the placement of additional quantities of overburden in the depressions and restoring water quality. The extent and costs of reclaiming the depressions and other reclamation requirements that may be imposed upon Wyodak Resources cannot be accurately ascertained at this time. 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 $650,000 is charged to operations as reclamation expense annually. As of December 31, 1993, accrued reclamation costs were approximately $7,290,000. Wyodak Resources supports reclamation procedures which are economically feasible and consistent with sound environmental practices, but it can give no assurances that it will be successful in doing so. GENERAL PCB's. The Company's electrical system contains an undetermined number of polychlorinated biphenyl (PCB or PCB's) contaminated transformers. PCB's are believed to have cancer causing and toxic effects on humans and are heavily regulated in their use and disposal as a toxic substance at levels in excess of 50 parts per million. Black Hills Power is beginning its third year of a five-year testing program that is intended to remove PCB contaminated transformers. If PCBs are present in levels above 50 parts per million, the equipment is removed from the system and disposed of in accordance with the current federal Toxic Substances Control Act. A concern is always present that an incident involving a PCB contaminated transformer could result in substantial cleanup costs for the Company. Those incidents which might involve a fire or the release of PCB-contaminated oil into a waterway are of the greatest concern and result in substantial damage claims. PCB-contaminated equipment and oils at levels below 50 parts per million are disposed of through a licensed facility located in Colman, South Dakota. Those items with contamination at higher levels are transported and disposed of through an EPA permitted incineration facility located in Deer Park, Texas. Black Hills Power has exclusively used these facilities for a number of years, and its management believes the disposal contractors are operating their respective facilities in full compliance with governmental regulation. OIL RELEASES. Two unauthorized oil releases occurred in 1993 as a result of equipment owned by Black Hills Power. Both involved minor quantities of petroleum products and only minimal remedial measures were required by the DENR. No penalties, claims or actions have been taken against the Company because of the releases, and none are expected. UNDERGROUND STORAGE TANKS. Black Hills Power does not have any underground storage tanks in operation at this time. The residual contamination from underground storage tanks that were removed from the Wyodak Resources mine site was believed to have caused some contamination of ground waters. The DEQ, however, has not required any further remediation action at the site. BEN FRENCH OIL SPILL. Assessment and remediation efforts have continued during 1993 on Black Hills Power property located near the Ben French power plant. The extensive contamination of the site with fuel oil is historic, but was discovered in 1990 and 1991 when the Company took steps to cleanup a release caused by an overflow that had resulted from an equipment failure. The Company hired experts to aid in the assessment and remediation and has worked closely with the DENR. Soil borings and the operation of monitoring wells on the perimeters of Black Hills Power's property show no indication of contamination beyond Black Hills Power's property at this time. The confinement of the contamination is attributed to the contour of the land at the site. The fuel oil is, however, migrating toward a natural drainage area which could allow it to enter area waterways. In such event, the clean-up costs could be greatly increased. In order to prevent such an occurrence, one duct-bank remediation system is currently in place and a second such system is expected to be installed in 1994. These systems are designed to channel the oil to a recovery location. Additional monitoring wells were installed in the area during 1993, and fuel oil as a free product continues to be removed from the site on a weekly basis. Although the quantity of free product being removed is greatly diminished from that earlier recovered, no time frame for the completion of the remediation work has been established. Costs for the cleanup in excess of $20,000 are expected to be reimbursed from the South Dakota Petroleum Release Compensation Fund up to a $1,000,000 limit. To date, no penalties, claims or actions have been taken or threatened against the Company because of this release. No assurances can be given, however, that no actions will be taken or what the eventual cost of this cleanup will be. MUSH CREEK CLEANUP. In 1993 Western Production undertook the clean-up of an unpermitted oil disposal site located near its facilities outside Newcastle, Wyoming. The initial disposal at the site is believed to have occurred sometime in 1983 or 1984 before Western Production ownership. The crude oil and some contaminated soils have been removed from the site and properly disposed of under the authorizations of the DEQ. The Company intends to apply for the renewal of the existing solid waste permit for the remediation of the site. The extent of the remaining clean-up effort required is not known at this time. Western Production plans further testing of soils and groundwater in the area of the site to determine the potential costs. The clean-up effort was begun in cooperation with other businesses who had used the disposal site, but in view of the higher-than-expected costs, disputes have now surfaced over responsibility for the cleanup. The cost of the project to date exceeds $140,000, but future costs remain undetermined pending further site assessment. To date, only $7,500 of these costs have been paid by others. ELECTROMAGNETIC FIELDS The SDPUC has opened a docket to study electromagnetic fields ("EMF") issues. A number of studies have examined the possibility of adverse health effects from EMF. Certain states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. None of the jurisdictions in which Black Hills Power operates has adopted formal rules or programs with respect to EMF or EMF considerations in the siting of electric facilities. Black Hills Power expects that public concerns will make it more difficult to site and construct new power lines and substations in the future. It is uncertain whether Black Hills Power's operations may be adversely affected in other ways as a result of EMF concerns. Black Hills Power is designing all new transmission lines under EMF standards adopted by other states so as to minimize the EMF effect. SUMMARY The Company makes ongoing efforts to comply with new as well as existing environmental laws and regulations to which it is subject. It is unable to estimate the ultimate effect of existing and future environmental requirements upon its operations. EMPLOYEES At December 31, 1993, the number of employees of the Company (including Black Hills Power), Wyodak Resources and Western Production were 359, 58 and 42, respectively, for a total of 459 employees. CORPORATE DEVELOPMENT The Company's strategic plan for corporate development includes the plan to search for opportunities for growth in its present business segments. The Company's primary focus will be in the development of additional mine-mouth power plants and Wyodak Resources' coal mine. To encourage the further development of Wyodak Resources' coal and to continue to assure the availability of electric generation in the future, the Company's plan is to cause Black Hills Power to participate in the construction of new generating facilities as they are needed by Black Hills Power either individually, with other traditional electric utilities or non- utility entities at Wyodak Resources' mine. See--ELECTRIC POWER SALES AND SERVICE TERRITORY--FUTURE WHOLESALE OPPORTUNITIES and COMPETITION IN ELECTRIC UTILITY BUSINESS under this Item 1. Management believes that surplus power in the western United States is decreasing and estimates that new plants will be required in the middle to late 1990's. Due to a four- to six- year lead time to construct plants, management believes the planning process should be in process. Management is continuing to explore the possibility of the Company engaging in the business, either by itself or in concert with others, of an exempt wholesale generator. This generation would be designed to sell power to traditional electric utilities other than Black Hills Power. (See the discussion of the new Energy Policy Act of 1992 under COMPETITION IN ELECTRIC UTILITY BUSINESS--COMPETITION IN ELECTRIC GENERATION under this Item 1.) The negative aspects of being able to engage in that business are the small size and lack of resources of the Company. The independent power producing business is concentrating in companies of a much larger size than the Company. However, the Company does have expertise in the power generation business and the potential for low-cost generation at Wyodak Resources' coal mine, the site of the Wyodak Plant, Neil Simpson Unit #1 and Neil Simpson Unit #2. If the Company is precluded from generating its own electric power needs, it may find a niche in the independent power business. Western Production continues to locate opportunities to acquire existing oil and gas production, to develop additional oil reserves by drilling and to investigate investing in oil and gas working interests with other entities. Opportunities depend on the sensitivity of oil and gas prices that are all beyond the control of Western Production. ITEM 2. PROPERTIES UTILITY PROPERTIES The following table provides information on the generating plants of Black Hills Power. During 1993, 99 percent of the fuel used in electric generation, measured in Btus (British thermal units), was coal.
GENERATING UNITS PLANT TOTALS NET GENERATION TWELVE MONTHS NAME PLATE ENDED YEAR OF RATING PRINCIPAL DECEMBER 31, 1993 INSTALLATION (KILOWATTS)(A) FUEL (THOUSANDS OF KWH) Osage Plant 1948 11,500 Coal (Osage, WY) 1950 11,500 Coal 1952 11,500 Coal 237,936 Kirk Plant 1956 18,750 Coal 105,149 (Lead, SD) Ben French Station 1960 25,000 Coal (Rapid City, 1965 10,000 Oil South Dakota) 1977(b) 50,400 Oil 1978(b) 25,200 Oil or gas 1979(b) 25,200 Oil or gas 161,168 Neil Simpson Unit #1 1969 21,760 Coal 153,795 (Wyodak, WY) Wyodak Plant 1978(c) 72,400 Coal 569,036 (Wyodak, WY) Total 283,210 1,227,084 (a) Nameplate rating is the capacity assigned to the generating unit by the manufacturer. Actual generating capability depends upon duration of usage, conditions of operation and other factors. See--ELECTRIC POWER SUPPLY--Reserves for an Analysis of the Net Dependable Capability--Summer Rating for these resources. (b) These combustion turbines are those referenced by the reserve capacity integration agreement with Pacific Power. See ELECTRIC POWER SUPPLY under Item 1 and the PacifiCorp Settlement. (c) Black Hills Power's 20 percent interest. See Note 6 of "Notes to Consolidated Financial Statements" appended hereto and the following discussion concerning the acquisition of the Wyodak Plant at CONSTRUCTION AND CAPITAL PROGRAM under Item 1.
Black Hills Power owns transmission lines and distribution systems in and adjoining the communities served consisting of 445 miles of 230 kV, 4 miles of 115 kV, 532 miles of 69 kV, 8 miles of 47 kV and numerous distribution lines of less voltage. Black Hills Power owns a service center in Rapid City, several district office buildings at various locations within its service area, and an eight-story home office building at Rapid City, South Dakota housing its home office on four floors, with the balance of the building rented to three tenants. MINING PROPERTIES Wyodak Resources is engaged in mining and processing sub- bituminous coal near Gillette in Campbell County, Wyoming. The coal averages 8,000 Btus per pound. Mining rights to the coal are based upon coal owned and five federal leases. The estimated tons of recoverable coal from each source as of December 31, 1993 are set forth in the following table: ESTIMATED TONS OF RECOVERABLE COAL (IN THOUSANDS) Fee coal 1,381 Federal lease dated May 1, 1959 19,763 Federal lease dated April 1, 1961 7,703 Federal lease dated October 1, 1965 117,534 Federal lease dated September 28, 1983 20,355 Federal lease dated March 1, 1983 22,604 189,340 Coal reserves are estimated at 189,340,000 tons of which approximately 32,250,000 tons are committed to be sold to the Wyodak Plant, approximately 10,000,000 tons to Black Hills Power's other plants, and 20,000,000 tons for Neil Simpson Unit #2. Purchase options are granted on 52,000,000 tons of which options for 50,000,000 tons can be exercised only if Wyodak Resources has not committed the coal reserves to other buyers prior to such exercise. Because the coal purchase price that will be paid if the options are exercised would be substantially higher than prices being paid under new coal contracts, it is unlikely that the options will be exercised. In 1989 an oil and gas developer established two oil- producing wells on the north portion of the lease dated October 1, 1965. The oil was leased to the developer by the owner of the oil rights, the State of Wyoming, and the coal is leased by Wyodak Resources from the owner of the coal rights, the federal government through its BLM. The oil is produced from a formation at a depth of approximately 9,000 feet while the coal is mined by the open pit method at a depth of 200 to 300 feet. Therefore, it is impossible to mine coal in the vicinity of the oil wells and maintain and operate the oil wells at the same time. The law is uncertain as to who would have priority under these circumstances. To date this conflict would affect approximately 15,000,000 tons of coal. At this time Wyodak Resources does not plan any mining operations at the site of the oil wells for at least 15 years, but the life of oil wells may extend for many years beyond 15. To mitigate its potential damages, Wyodak Resources has negotiated an option to purchase the oil wells at fair market value if a mining conflict should occur. Each federal lease grants Wyodak Resources the right to mine all of the coal in the land described therein, but the government has the right at the end of 20 years from the date of the lease to readjust royalty payments and other terms and conditions. All of the federal leases provide for a royalty of 12.5 percent of the selling price of the coal. Each federal lease requires diligent development to produce at least one percent of all recoverable reserves within either 10 years from the respective dates of the 1983 leases or 10 years from the date of adjustment of the other leases. Each lease further requires a continuing obligation to mine, thereafter, at an average annual rate of at least one percent of the recoverable reserves. All of the federal leases and its remaining fee coal constitute one logical mining unit and is treated as one lease for the purpose of determining diligent development and continuing operation requirements. All coal is to be mined within 40 years from 1992, the date of the logical mining unit. Even if federal coal leases are not mined out in 40 years, the federal coal is likely to be available for further lease after the 40 years. Wyodak Resources' current coal agreements require production which should be sufficient to satisfy the diligent development and continual operation requirements of present law. Wyodak Resources will require additional coal sales in order to mine all of its federal coal within the 40 year requirement. The law, which requires that an owner of land that is primarily devoted to agriculture must approve a reclamation plan before the state will approve a permit for open pit mining, affects approximately 3,100,000 tons of the recoverable coal included in the federal lease dated October 1, 1965. Wyodak Resources has excluded these tons of coal from its mine plan and will not mine such coal until a surface consent has been negotiated or the right to mine has been settled by litigation. Approximately 32,250,000 tons of the Federal Coal Lease dated October 1, 1965, has been mortgaged as security for the performance of its obligations under the coal supply agreement for the Wyodak Plant. In 1992, Pacific Power, the Company and Wyodak Resources entered into an agreement providing for the construction of new coal handling facilities. The new coal handling facilities consist of an in-pit system (consisting of in-pit movable crushers and a conveyor to a secondary crusher transfer point), an out-of-pit system (consisting of the secondary crusher), new truck load-out facilities, a conveyor to deliver coal to Neil Simpson Unit #1 and a conveyor to deliver coal to the Wyodak Plant and eventually to Neil Simpson Unit #2. The total construction costs of these facilities is expected to be $24,500,000, of which Pacific Power will pay $19,000,000 and Wyodak Resources $5,500,000. The reason for the large amount being paid by Pacific Power is that under the PacifiCorp Settlement, Pacific Power was obligated to pay up to $15,000,000, plus an amount to adjust for inflation since 1987, for new coal handling facilities which were required to extend the mining of coal to another pit, the Peerless area, situated west of the Wyodak Plant. Under the agreement among PacifiCorp, the Company and Wyodak Resources, Wyodak Resources will operate the in-pit system, the conveyor to Neil Simpson Unit #1 and the truck load-out system, and PacifiCorp will operate the secondary crusher transfer building and the conveyor to the Wyodak Plant. The agreement provides for the use of the new coal handling facilities to deliver coal to the Wyodak Plant, Neil Simpson Unit #1, Neil Simpson Unit #2, the truck load-out and, if there is sufficient capacity, to additional power plants to be constructed at the site. The agreement provided for Black Hills Power to own certain undivided interests of these facilities, but Black Hills Power and Wyodak Resources have entered into an agreement providing for the transfer of all interests of Black Hills Power in these facilities to Wyodak Resources. This transfer is consistent with the agreement of Wyodak Resources to deliver Black Hills Power completely processed coal. OIL AND GAS PROPERTIES Western Production operates 347 wells as of December 31, 1993. The vast majority of these wells are in the Finn Shurley Field, located in Weston and Niobrara Counties, Wyoming. Twelve of the wells Western Production operates are located in Adams and Weld Counties, Colorado, two are located in Washakie County, Wyoming and two are located in Fall River County, South Dakota. Western Production does not operate but owns a working interest in 39 producing properties located in Wyoming, Kansas, Colorado, Montana, North Dakota and Texas. The majority of wells operated by Western Production were drilled between 1977 and 1984, prior to its acquisition by Wyodak Resources. They were drilled under drilling programs wherein working interests were sold to various investors. Approximately 232 investors own working interests in wells operated by Western Production. Western Production owns a 44.7 percent interest in a natural gas processing plant also located at the Finn Shurley Field. The gas plant is operated by Western Gas Resources, Inc. of Denver, Colorado, which owns a 50 percent interest therein and processes all the gas produced from the Finn Shurley Field and the Boggy Creek Field. The following table summarizes Western Production's estimated quantities of proved developed and undeveloped oil and natural gas reserves at December 31, 1993 and 1992, and a reconciliation of the changes between these dates using constant product prices for the respective years. 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.
1993 1992 Oil Gas Oil Gas (in thousands of barrels of oil and MCF of gas) Proved developed and undeveloped resources: Balance at beginning of year 2,199 3,243 2,524 4,799 Production (327) (777) (247) (379) Additions 259 1,847 193 272 Revisions to previous estimates due to changed economic conditions (1,015) (1,554) (271) (1,449) Balance at end of year 1,116 2,759 2,199 3,243 Proved developed reserves at end of year included above 1,116 2,759 1,630 2,633 Year-end prices $13.00 $ 2.35 $18.75 $ 1.65
Western Production has approximately 99,000 gross and 65,000 net acres of oil and gas leases, out of which 25,000 gross and 15,000 net acres are producing and 74,000 gross and 50,000 net acres are undeveloped. Approximately 23 percent of the undeveloped acres are held by production thereby not requiring annual delay rental payments. No representations are made that reserves can be attributed to any undeveloped oil and gas leases. Undeveloped leasehold that are not held by production have varying provisions but generally terminate if oil and gas is not produced within the primary term of the lease. ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries are involved in minor routine administrative proceedings and litigation incidental to the businesses, none of which, in the opinion of management, will have a material effect on the consolidated financial statements of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders during the fourth quarter of 1993. EXECUTIVE OFFICERS OF THE COMPANY The following is a list of all executive officers of the Company. There are no family relationships among them. Officers are normally elected annually. Daniel P. Landguth, born May 9, 1946, Chairman, President, and Chief Executive Officer of Black Hills Corporation Mr. Landguth was elected to his present position in January 1991. He had served as President of Black Hills Corporation since October 1989, President and Chief Operating Officer of Black Hills Power since June 1987, and Senior Vice President and Chief Operating Officer since 1985. Dale E. Clement, born August 1, 1933, Senior Vice President - Finance Mr. Clement was elected to his present position in September 1989. He had served on the Board of Directors since 1979. Prior to joining the Company he was Dean and Professor of Finance at the University of South Dakota, School of Business. Joseph E. Rovere, born July 7, 1929, Vice President - Public Affairs/District Administration Mr. Rovere was elected to his present position in October 1982. Roxann R. Basham, born August 6, 1961, Secretary and Treasurer Mrs. Basham was elected to her present position January 1, 1993. She had served as Assistant Secretary/Treasurer since May 1991 and as Financial Analyst since February 1985. Gary R. Fish, born August 1, 1958, Controller Mr. Fish was elected to his present position in August 1988. Everett E. Hoyt, born August 8, 1939, President and Chief Operating Officer of Black Hills Power Mr. Hoyt was elected to his present position in October 1989. Prior to joining the Company he was Senior Vice President - Legal, Corporate Secretary, and Assistant Treasurer of Northwestern Public Service Company. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The information required by Item 5 is provided in the Annual Report to Shareholders of the Company for the year ended December 31, 1993, on page 32 appended hereto and market price information is shown in Note 13 of "Notes to Consolidated Financial Statements" on page 29 of the Annual Report to Shareholders of the Company for the year ended December 31, 1993, appended hereto. ITEM 6. SELECTED FINANCIAL DATA The information required by Item 6 is provided under an identical caption in the Annual Report to Shareholders of the Company for the year ended December 31, 1993, on page 29 appended hereto. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION The information required by Item 7 is provided under a similar caption in the Annual Report to Shareholders of the Company for the year ended December 31, 1993, on pages 12 through 18 appended hereto. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by Item 8 is provided under proper captions in the Annual Report to Shareholders of the Company for the year ended December 31, 1993, on pages 20 through 29 appended hereto. Selected quarterly financial data is shown in Note 13 of "Notes to Consolidated Financial Statements" on page 29 of the Annual Report to Shareholders of the Company for the year ended December 31, 1993, appended hereto. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE No change of accountants or disagreements on any matter of accounting principles or practices or financial statement disclosure have occurred. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding the directors of the Company is incorporated herein by reference to the Proxy Statement for the Annual Shareholders' Meeting to be held May 24, 1994. For information regarding the executive officers of the Company refer to Part I, Item 4. ITEM 11. EXECUTIVE COMPENSATION Information regarding management remuneration and transactions is incorporated herein by reference to the Proxy Statement for the Annual Shareholders' Meeting to be held May 24, 1994. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information regarding the security ownership of certain beneficial owners and management is incorporated herein by reference to the Proxy Statement for the Annual Shareholders' Meeting to be held May 24, 1994. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information regarding certain relationships and related transactions is incorporated herein by reference to the Proxy Statement for the Annual Shareholders' Meeting to be held May 24, 1994. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1. Index to Consolidated Financial Statements Page Reference* Report of Independent Public Accountants. . . . .19 Consolidated Statements of Income and Retained Earnings for the three years ended December 31, 1993. . . . . . . . . . . . .20 Consolidated Statements of Cash Flows for the three years ended December 31, 1993. . . . .21 Consolidated Balance Sheets at December 31, 1993 and 1992 . . . . . . . . . . . . . . . . . . . .22 Consolidated Statements of Capitalization at December 31, 1993 and 1992 . . . . . . . . . . .23 Notes to Consolidated Financial Statements. . 24-29 2. Schedules ** V Property, Plant, and Equipment for the three years ended December 31, 1993 VI Accumulated Depreciation and Depletion of Property, Plant, and Equipment for the three years ended December 31, 1993 IX Short-Term Borrowings for the three years ended December 31, 1993 * Page References are to the incorporated portion of the Annual Report to Shareholders of the Company for the year ended December 31, 1993. ** All other 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 *3(a) Bylaws dated December 10, 1991 (Exhibit 3(a) to Form 10-K for 1991). *3(b) Restated Articles of Incorporation dated July 28, 1986 (Exhibit 3(b) to Form 10-K for 1986). Articles of Amendment to Restated Articles of Incorporation dated May 21, 1987, (Exhibit 3(b) to Form 8-K for May 1987, File No. 0-0164). Articles of Amendment to Restated Articles of Incorporation dated May 16, 1989 (Exhibit 3(b) to Form 10-K for 1989). Articles of Amendment to Restated Articles of Incorporation dated May 28, 1992 (Exhibit 3(b) to Form 10-K for 1992). Articles of Correction to Amendment to Restated Articles of Incorporation, dated September 13, 1993 (Exhibit 4.03 to Form S-3 dated September 22, 1993, Registration No. 33- 69234). *4(a) Reference is made to Article Fourth (7) of the Restated Articles of Incorporation of the Company and the Articles of Amendment to Restated Articles of Incorporation (Exhibit 3(b) hereto). *4(b) Indemnification Agreement and Company and Directors' and Officers' indemnification insurance (Exhibit 4(b) to Form 10-K for 1987). *4(c) Indenture of Mortgage and Deed of Trust, dated September 1, 1941, and as amended by supplemental indentures (Exhibit B to Form 8-K, File No. 2-4832); (Exhibit 7-B, File No. 2-6576); (Exhibit 7-C, File No. 2-7695); (Exhibit 7-D, File No. 2-8157); (Exhibit A to Form 10-K for fiscal year 1950, File No. 2-4832); (Exhibit 4-I, File No. 2-9433); (Exhibit 4-H, File No. 2-13140); (Exhibit 4-I, File No. 2-14829); (Exhibits 4-J and 4-K, File No. 2-16756); (Exhibits 4-L, 4-M, and 4-N, File No. 2-21024); (Exhibits 2(q), 2(r), 2(s), 2(t), 2(u), and 2(v) to Form S-7, File No. 2-57661); (Exhibit (b) to Form 8-K for February 1977, File No. 2-4832); (Exhibit II-1 to Form 10-Q for quarter ended April 30, 1977, File No. 2-21024); (Exhibit II-1 to Form 10-Q for quarter ended July 31, 1977, File No. 2-21024); (Exhibit 4(b) to Form S-3, File No. 2-81643); (Exhibit II-6a to Form 10-Q for quarter ended September 30, 1986, File No. 0-0164); (Exhibit II-6a to Form 10-Q for quarter ended September 30, 1987, File No. 0-0164); (Exhibit II-6a to Form 10-Q for quarter ended September 30, 1988, File No. 0-0164); and (Exhibit 4(d) and 4(e) to Post- Effective Amendment No. 1 to Form S-8, File No. 33-15868). *10(a) Coal Supply Agreement dated May 12, 1975, between Wyodak Resources Development Corp. and the South Dakota Cement Commission (Exhibit 5(d) to Form S-7, File No. 2-57661). Extension of Coal Supply Agreement dated June 2, 1980, and First Supplement dated February 8, 1983 (Exhibit 10(c) to Form 10-K for 1983). Second Supplement to Extension of Coal Supply Agreement dated June 1, 1985 (Exhibit 10(c) to Form 10-K for 1985). Third Supplement to Extension of Coal Supply Agreement dated July 14, 1986 (Exhibit 10(c) to Form 10-K for 1986). Fourth Supplement to Extension of Coal Supply Agreement dated December 1, 1987 (Exhibit 10(c) to Form 10-K for 1987). Fifth Supplement to Extension of Coal Supply Agreement dated March 12, 1992 (Exhibit 10(a) to Form 10-K for 1992). *10(b) Agreement for Transmission Service and The Common Use of Transmission Systems dated January 1, 1986, among the Company, Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc., and Butte Electric Cooperative, Inc. (Exhibit 10(d) to Form 10-K for 1987). *10(c) Restated and Amended Coal Supply Agreement for Neil Simpson Unit #2 dated February 12, 1993 (Exhibit 10(c) to Form 10-K for 1992). *10(d) Coal Supply Agreement and First Amendment dated September 1, 1977, between the Company and Wyodak Resources Development Corp. (Exhibit 5(g) to Form S-7, File No. 2-60755). Second Amendment to Coal Supply Agreement dated November 2, 1987 (Exhibit 10(f) to Form 10-K for 1987). *10(e) Coal Lease dated May 1, 1959, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 5(i) to Form S-7, File No. 2-60755). Modified coal lease dated January 22, 1990, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(h) to Form 10-K for 1989). *10(f) Coal Lease dated April 1, 1961, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 5(j) to Form S-7, File No. 2-60755). Modified coal lease dated January 22, 1990, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(i) to Form 10-K for 1989). *10(g) Coal Lease dated October 1, 1965, between Wyodak Resources Development Corp. and the Federal Government, as amended (Exhibit 5(k) to Form S-7, File No. 2-60755). Modified coal lease dated January 22, 1990, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(j) to Form 10-K for 1989). *10(h) Participation Agreement dated May 16, 1978, and various related agreements dated June 8, 1978, including, without limitation, Lease Agreement, Amended and Restated Coal Supply Agreement, Coal Supply System Agreement and Security Agreement, and Real Estate Mortgage (all relating to the lease financing of the Wyodak Plant and the dedication by Wyodak Resources Development Corp. of coal deposits with respect thereto) filed pursuant to item 6(b) of Amendment No. 1 to Registrant's Current Report on Form 8-K for June 1978 and located in Commission File No. 2-4832. Further Restated and Amended Coal Supply Agreement dated May 5, 1987 (Exhibit 10(k) to Form 10-K for 1987). *10(i) Coal Supply Agreement dated August 24, 1978, between Wyodak Resources Development Corp. and the City of Grand Island, Nebraska (Exhibit 5(l) to Form S-7, File No. 2-64014). Restated and Amended Coal Supply Agreement dated March 4, 1983 (Exhibit 10(l) to Form 10-K for 1983). First Amendment to Restated and Amended Coal Supply Agreement dated October 29, 1987 (Exhibit 10(l) to Form 10-K for 1987). *10(j) Power Sales Agreement dated December 31, 1983, between Pacific Power & Light Company and the Company (Exhibit 7(b) to Form 8-K for January 1984, File No. 0-0164). *10(k) Coal Supply Agreement for Wyodak Unit #2 dated February 3, 1983, and Ancillary Agreement dated February 3, 1982, between Wyodak Resources Development Corp. and Pacific Power & Light Company and the Company (Exhibit 10(o) to Form 10-K for 1983). Amendment to greement for Coal Supply for Wyodak #2 dated May 5, 1987 (Exhibit 10(o) to Form 10-K for 1987). *10(l) Coal lease dated February 16, 1983, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(p) to Form 10-K for 1983). *10(m) Coal lease dated September 28, 1983, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(q) to Form 10-K for 1983). *10(n) Indenture of Trust dated as of August 1, 1984, City of Gillette, Campbell County, Wyoming, to Norwest Bank Minneapolis, N.A. as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(r) to Form 10-K for 1984). Indenture of Trust dated as of June 1, 1992, City of Gillette, Campbell County, Wyoming, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(n) to Form 10-K for 1992). *10(o) Loan Agreement dated as of August 1, 1984, by and between City of Gillette, Campbell County, Wyoming, and the Company (Exhibit 10(s) to Form 10-K for 1984). Loan Agreement dated as of June 1, 1992, by and between City of Gillette, Campbell County, Wyoming, and the Company (Exhibit 10(o) to Form 10-K for 1992). *10(p) Loan Agreement dated as of June 1, 1992, by and between Lawrence County, South Dakota and the Company (Exhibit 10(p) to Form 10-K for 1992). *10(q) Indenture of Trust dated as of June 1, 1992, Lawrence County, South Dakota, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(q) to Form 10-K for 1992). *10(r) Loan Agreement dated as of June 1, 1992, by and between Pennington County, South Dakota and the Company (Exhibit 10(r) to form 10-K for 1992). *10(s) Indenture of Trust dated as of June 1, 1992, Pennington County, South Dakota, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(s) to Form 10K for 1992). *10(t) Loan Agreement dated as of June 1, 1992, by and between Weston County, South Dakota and the Company (Exhibit 10(t) to Form 10-K for 1992). *10(u) Indenture of Trust dated as of June 1, 1992, Weston County, Wyoming, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(u) to Form 10-K for 1992). *10(v) Loan Agreement dated as of June 1, 1992, by and between Campbell County, South Dakota and the Company (Exhibit 10(v) to Form 10-K for 1992). *10(w) Indenture of Trust dated as of June 1, 1992, Campbell County, Wyoming, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(w) to Form 10-K for 1992). *10(x) Restated Electric Power and Energy Supply and Transmission Agreement and Restated Seasonal Non-Firm Power Sale Agreement both dated December 21, 1987, both by and between the Company and the City of Gillette, Wyoming (Exhibit 10(t) to Form 10-K for 1987). *10(y) Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and the Company (Exhibit 10(u) to Form 10-K for 1987). *10(z) Firm Capacity and Energy Purchase Agreement between Tri-State Generation and Transmission Association, Inc. and the Company dated May 11, 1992 (Exhibit 10(aa) to Form 10-K for 1992). 10(aa) Firm Capacity and Energy Purchase Agreement between Sunflower Electric Power Cooperative and the Company dated October 11, 1993. *10(bb) Compensation Plan for Outside Directors (Exhibit 10(bb) to Form 10-K for 1992). *10(cc) Retirement Plan for Outside Directors dated January 1, 1993 (Exhibit 10(cc) to Form 10-K for 1992). *10(dd) Pension Equalization Plan of Black Hills Corporation dated January 1, 1990 (Exhibit 10(dd) to Form 10-K for 1992). 10(dd) Amendment #1 to Pension Equalization Plan of Black Hills Corporation dated April 27, 1993. 10(ee) Black Hills Corporation 1994 Executive Gainsharing Program. 10(ff) Black Hills Corporation 1994 Results Compensation Program. *10(gg) Pension Plan of Black Hills Corporation as amended and restated effective October 1, 1989. First amendment to the Pension Plan of Black Hills Corporation dated September 25, 1992. Amendment to the Pension Plan of Black Hills Corporation dated December 4, 1992. Amendment to the Pension Plan of Black Hills Corporation dated February 5, 1993 (Exhibit 10(ff) to form 10-K for 1992). *10(hh) Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for 1992). *10(ii) Agreement for Supplemental Pension Benefit for Dale E. Clement dated December 19, 1991 (Exhibit 10(hh) to Form 10-K for 1992). 13 Annual Report to Shareholders of the Registrant for the year ended December 31, 1993. 22 Subsidiaries of the Registrant. 23 Consent of Independent Public Accountants. _________________________ * Exhibits incorporated by reference. (b) No reports on Form 8-K have been filed in the quarter ended December 31, 1993. (c) See (a) 3. above. (d) See (a) 2. above. _________________________________________________________________ REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in Black Hills Corporation's 1993 Annual Report to Shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 28, 1994. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed as a part of Item 14.(a)2. in this Form 10-K are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Minneapolis, Minnesota, January 28, 1994 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BLACK HILLS CORPORATION By DANIEL P. LANDGUTH Daniel P. Landguth, Chairman, President, and Chief Executive Dated: March 11, 1994 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 11, 1994 Daniel P. Landguth (Chairman, Executive Officer President, and Chief Executive) DALE E. CLEMENT Director and Principal March 11, 1994 Dale E. Clement (Senior Vice Financial Officer President - Finance) GARY R. FISH Principal Accounting March 11, 1994 Gary R. Fish (Controller) Officer GLENN C. BARBER Director March 11, 1994 Glenn C. Barber BRUCE B. BRUNDAGE Director March 11, 1994 Bruce B. Brundage MICHAEL B. ENZI Director March 11, 1994 Michael B. Enzi JOHN R. HOWARD Director March 11, 1994 John R. Howard EVERETT E. HOYT Director and Officer March 11, 1994 Everett E. Hoyt (President and Chief Operating Officer of Black Hills Power) KAY S. JORGENSEN Director March 11, 1994 Kay S. Jorgensen CHARLES T. UNDLIN Director March 11, 1994 Charles T. Undlin Schedule V BLACK HILLS CORPORATION Property, Plant, and Equipment Year ended December 31, 1993
Balance at Additions Other Balance at Beginning at Retire- Changes End of of Year Cost (a) ments(b) add(deduct) Year (in thousands) Utility property: Production $143,212 $ 2,549 $2,440 $ 4 $143,325 Transmission and distribution 141,324 12,483 1,115 10 152,702 General 23,905 4,422 776 - 27,551 308,441 19,454 4,331 14 323,578 Construction work in progress 9,829 6,478 - 1,967 18,274 Total utility property 318,270 25,932 4,331 1,981 341,852 Other property: Coal mining Coal land and land rights 7,117 - - - 7,117 Coal leases and rights 7,188 - - - 7,188 Buildings 1,183 404 7 (2) 1,578 Mining equipment 28,688 7,154 98 (106) 35,638 Housing properties 105 - 25 - 80 Oil and gas production 28,465 6,933 3,027 - 32,371 Other 41 - - - 41 72,787 14,491 3,157 (108) 84,013 Construction work in progress 202 (133) - - 69 Total other property 72,989 14,358 3,157 (108) 84,082 Total $391,259 $40,290 $7,488 $1,873 $425,934 (a) See summary of significant accounting policies in consolidated financial statements (Note 1) for information relative to allowance for funds used during construction included in additions. (b) Costs applicable to retirements, other than non-utility property, are charged to the accumulated depreciation account (Schedule VI).
___________________________________________________________________________ Schedule VI BLACK HILLS CORPORATION Accumulated Depreciation and Depletion of Property, Plant, and Equipment Year ended December 31, 1993
Additions Balance at Charged to Balance at Beginning Costs and Retire- End of of Year Expenses ments Year (in thousands) Utility property $104,582 $ 9,990 $4,130 $110,442 Other property- Coal mining 18,827 1,953 106 20,674 Oil and gas production 9,481 4,146 251 13,376 28,308 6,099 357 34,050 Total $132,890 $16,089 $4,487 $144,492
Schedule V BLACK HILLS CORPORATION Property, Plant, and Equipment Year ended December 31, 1992
Balance at Additions Other Balance at Beginning at Retire- Changes End of of Year Cost (a) ments(b) add(deduct) Year (in thousands) Utility property: Production $139,791 $ 4,155 $ 734 $ - $143,212 Transmission and distribution 135,408 7,217 1,301 - 141,324 General 24,031 1,378 1,504 - 23,905 299,230 12,750 3,539 - 308,441 Construction work in progress 7,072 2,757 - - 9,829 Total utility property 306,302 15,507 3,539 - 318,270 Other property: Coal mining Coal land and land rights 7,117 - - - 7,117 Coal leases and rights 7,188 - - - 7,188 Buildings 1,125 58 - - 1,183 Mining equipment 23,893 4,822 27 - 28,688 Housing properties 111 - 6 - 105 Oil and gas production 23,486 5,180 201 - 28,465 Other 41 - - - 41 62,961 10,060 234 - 72,787 Construction work in progress 81 121 - - 202 Total other property 63,042 10,181 234 - 72,989 Total $369,344 $25,688 $3,773 $ - $391,259 (a) See summary of significant accounting policies in consolidated financial statements (Note 1) for information relative to allowance for funds used during construction included in additions. (b) Costs applicable to retirements, other than non-utility property, are charged to the accumulated depreciation account (Schedule VI).
___________________________________________________________________________ Schedule VI BLACK HILLS CORPORATION Accumulated Depreciation and Depletion of Property, Plant, and Equipment Year ended December 31, 1992
Additions Balance at Charged to Balance at Beginning Costs and Retire- End of of Year Expenses ments Year (in thousands) Utility property $ 98,589 $ 9,614 $3,621 $104,582 Other property- Coal mining 17,377 1,482 32 18,827 Oil and gas production 6,608 2,764 (109) 9,481 23,985 4,246 (77) 28,308 Total $122,574 $13,860 $3,544 $132,890
Schedule V BLACK HILLS CORPORATION Property, Plant, and Equipment Year ended December 31, 1991
Balance at Additions Other Balance at Beginning at Retire- Changes End of of Year Cost (a) ments(b) add(deduct) Year (in thousands) Utility property: Production $127,586 $12,180 $ 85 $ 110 $139,791 Transmission and distribution 127,970 8,018 580 - 135,408 General 19,906 4,955 830 - 24,031 275,462 25,153 1,495 110 299,230 Construction work in progress 2,360 4,712 - - 7,072 Total utility property 277,822 29,865 1,495 110 306,302 Other property: Coal mining Coal land and land rights 6,107 1,009 - 1 7,117 Coal leases and rights 7,188 - - - 7,188 Buildings 1,125 - - - 1,125 Mining equipment 23,745 171 23 - 23,893 Oil and gas 1,687 - - (1,687) - Housing properties 111 - - - 111 Oil and gas production 16,000 5,987 188 1,687 23,486 Other 41 - - - 41 56,004 7,167 211 1 62,961 Construction work in progress 132 (51) - - 81 Total other property 56,136 7,116 211 1 63,042 Total $333,958 $36,981 $1,706 $ 111 $369,344 (a) See summary of significant accounting policies in consolidated financial statements (Note 1) for information relative to allowance for funds used during construction included in additions. (b) Costs applicable to retirements, other than non-utility property, are charged to the accumulated depreciation account (Schedule VI).
___________________________________________________________________________ Schedule VI BLACK HILLS CORPORATION Accumulated Depreciation and Depletion of Property, Plant, and Equipment Year ended December 31, 1991
Additions Balance at Charged to Balance at Beginning Costs and Retire- End of of Year Expenses ments Year (in thousands) Utility property $ 91,236 $ 9,164 $1,811 $ 98,589 Other property- Coal mining 16,046 1,572 241 17,377 Oil and gas production 3,829 3,015 236 6,608 19,875 4,587 477 23,985 Total $111,111 $13,751 $2,288 $122,574
Schedule IX BLACK HILLS CORPORATION Short-Term Borrowings
Weighted Weighted Maximum Average Average Average Amount Amount Interest Interest Outstanding Outstanding Rate Balance at Rate at During During During Year December 31 December 31 the Year the Year the Year (in thousands) 1993 $11,700 4.5% $17,350 $11,059 5.2% 1992 $6,000 5.8% $12,600 $5,616 6.0% 1991 $5,100 6.7% $17,000 $4,552 8.3%
The Company's short-term borrowings consist solely of notes payable to banks. See Note 4 in the consolidated financial statements for additional discussion on notes payable to banks. The average amount of short-term borrowings outstanding during the year represents an average of daily balances. The weighted average interest rate during the year was based on a weighting of interest rates associated with these balances. ___________________________________________________________________________ APPENDIX BLACK HILLS CORPORATION The following items, appended hereto, are incorporated into the Form 10-K from the 1993 Annual Report to Shareholders: PART II Pages Item 5 Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . 32 Item 6 Selected Financial Data. . . . . . . . . . . . 29 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operation. . . . .12-18 Item 8 Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . .20-29 EXHIBIT INDEX EX-10.aa Firm Capacity and Energy Purchase Agreement between Sunflower Electric Power Cooperative and the Company dated October 11, 1993. EX-10.dd Amendment #1 to Pension Equalization Plan of Black Hills Corporation dated April 27, 1993. EX-10.ee Black Hills Corporation 1994 Executive Gainsharing Program. EX-10.ff Black Hills Corporation 1994 Results Compensation Program. EX-13 Annual Report to Shareholders of the Registrant for the year ended December 31, 1993. EX-22 Subsidiaries of the Registrant. EX-23 Consent of Independent Public Accountants. EX-10.AA 2 SUNFLOWER PURCHASE POWER AGREEMENT EX-10.aa PEAKING CAPACITY AGREEMENT between BLACK HILLS POWER AND LIGHT COMPANY and SUNFLOWER ELECTRIC POWER CORPORATION This Firm Peaking Capacity Agreement ("Agreement") made and entered into this 11th day of October, 1993, by and between Sunflower Electric Power Corporation ("SEPC"), a Kansas Corporation, and Black Hills Power and Light Company ("BHP"), a South Dakota Corporation; with SEPC and BHP being sometimes hereinafter referred to as "Parties" collectively or as a "Party" singularly. WHEREAS, the Parties to this Agreement are engaged in the business of generation, transmission, and sale of electric power and energy and either own, or have available for their use, and operate and maintain electric generation and transmission facilities; and WHEREAS, BHP requires firm peaking capacity to meet its public obligation to serve its customers, and desires to purchase such peaking capacity and associated energy; WHEREAS, SEPC and Western Area Power Administration ("WAPA") are entering into Contract No. 93-LAO-722 ("the SEPC-WAPA Contract") for firm transmission service to effect deliveries of peaking energy to BHP; WHEREAS, SEPC owns peaking capacity and associated energy that it desires to sell to BHP; and WHEREAS, the Parties desire to enter into this Agreement for the sale by SEPC and the purchase by BHP of firm peaking power and energy and the delivery of such power and energy to BHP as provided herein. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: ARTICLE I - DEFINITIONS As used herein: 1.1 "Contract Rate of Delivery" shall mean Contract Rate of Delivery as such is defined in Section 2.1 hereof. 1.2 "Contract Year" shall mean the period of twelve consecutive calendar months commencing at 12:01 a.m. on October 1, 1993, and at 12:01 a.m. on October 1 of each year thereafter during the term of this Agreement. 1.3 "Peaking Energy" shall mean energy provided by SEPC under the SEPC- WAPA Contract and delivered to BHP by WAPA. Such Peaking Energy shall not exceed a monthly load factor of 15%. 1.4 "Phase I" shall mean Phase I as defined in Title IV of the Clean Air Act Amendments of 1990, commencing January 1, 1995, and extending through December 31, 1999, and as applicable to power and energy generation facilities. 1.5 "Prudent Utility Practice" shall mean any of the practices, methods and acts at a particular time, which, in the exercise of reasonable judgment in the light of the facts, including but not limited to the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry prior thereto, known at the time the decision was made, would have been expected to accomplish the desired result at the lowest reasonable cost consistent with reliability, safety and expediency. In applying the standard of Prudent Utility Practice to any matter under this Agreement, equitable consideration should be given to the circumstances, requirements and obligations of each of the Parties. It is recognized that Prudent Utility Practice is not intended to be limited to a single best practice, method or act to the exclusion of all others, but rather can be within a spectrum of possible practices, methods or acts which could reasonably have been expected to accomplish the desired result. 1.6 "SEPC Peaking Resources" shall mean the SEPC-owned generating capacity associated with combustion turbine units No. 4 ("S4") and No. 5 ("S5") at SEPC's generation complex location in Garden City, Kansas. ARTICLE II - PEAKING CAPACITY SALE BY SEPC 2.1 Except as otherwise provided in this Agreement, SEPC shall supply from its system and BHP shall purchase and receive up to 50 MW of seasonal firm peaking capacity and associated energy, as such peaking capacity is more specifically set forth in the initial Exhibit A ("Contract Rate of Delivery") attached hereto and made a part hereof; provided, however, that SPEC shall not be obligated to supply capacity in excess of the seasonal amounts reserved by BHP in accordance with the provisions and limitations of this Agreement. Exhibit A may be modified on or before July 1 of each year in accordance with Section 2.4 below. SEPC's obligation to supply seasonal capacity and associated energy is from its system and is not conditioned on the operation of SEPC Peaking Resources. 2.2 BHP shall pay SEPC monthly for the Contract Rate of Delivery purchased hereunder pursuant to the capacity rates provided in Exhibit A. 2.3 BHP may submit written requests for changes to the amounts of peaking capacity purchased as deemed necessary or desirable by BHP. SEPC's authorized representative, as identified in Section 16.2 will act upon each such request and furnish a written determination within 90 days after receipt of such request of SEPC's ability to accommodate said changes. If the request is approved by SEPC, Exhibit A shall be amended to reflect the new amounts of peaking capacity purchased by BHP. 2.4 On or before July 1 of each year following the execution of this Agreement, BHP shall inform SEPC, in writing, of the estimated future winter season (October through March) and summer season (April through September) peaking requirements, in megawatts, at the point of delivery that BHP desires SEPC to provide as set forth in Exhibit A hereunder for the next four years (October 1 through September 30), beginning on October 1 following the aforesaid July 1 and ending on September 30, four years later. Within ninety days after receipt of said request, SEPC shall inform BHP, in writing, whether or not SPEC can provide such capacity at the designated point of delivery. If a request is denied, supporting documentation will be provided by SEPC upon receipt of a written request by BHP. If SEPC approves BHP's request, Exhibit A will be revised to reflect the new capacity reservations. Notwithstanding that the Parties may subsequently agree to a new Exhibit A under this Section 2.4 that may extend beyond September 30, 1996, each party reserves the right to terminate this Agreement at the times as provided in Section 9.1 unless the Parties agree otherwise in writing. ARTICLE III - PURCHASE OF ENERGY 3.1 BHP may purchase energy associated with firm peaking capacity up to such seasonal amounts identified in Exhibit A. Such energy shall be limited to a maximum of 15% load factor each month. 3.2 The price of energy purchased hereunder by BHP shall be determined by the application of the following energy pricing formula: E = (Fuel + VOM) * 1.2 Where: E = SEPC's energy price per MWH Fuel = SEPC Peaking Resources equivalent fuel cost VOM = SEPC's variable operation and maintenance cost per MWH shall be $1.00 per MWH beginning in 1993 and shall escalate annually on January 1 at the rate of 5%. ARTICLE IV - POINT OF DELIVERY 4.1 The point of delivery for power and energy sold to BHP under this Agreement shall be BHP's point of interconnection with WAPA at the western bus of the Stegall substation, or such other point as the Parties may agree upon and identified in Exhibit A. ARTICLE V - AVAILABILITY AND SCHEDULING 5.1 The firm peaking capacity supplied to BHP at the Contract Rate of Delivery as provided in Exhibit A shall be available for scheduling during each Contract Year. 5.2 BHP system operators shall communicate with WAPA's system operators to facilitate daily scheduling of energy from SEPC to BHP under this Agreement. BHP shall normally furnish WAPA with a schedule for such energy by the hour ending 1400 MST of the day prior to the beginning of such schedule. Schedules for Saturday, Sunday, and Monday shall be provided by the hour ending 1400 on the preceding Friday. ARTICLE VI - OPERATION AND MAINTENANCE 6.1 BHP and SEPC shall operate and maintain their electric systems in accordance with Prudent Utility Practice. Each Party shall perform such maintenance at such time as it deems necessary, in its sole discretion, but shall use its best efforts to schedule such maintenance in such a manner as to limit the overall inconvenience to the parties such that no Party is unduly penalized. ARTICLE VII - BOOKS AND RECORDS 7.1 The Parties shall maintain such books and records as are required for the administration of this Agreement and shall provide each other access to such books and records as well as reasonable access to each other's electric systems to permit audits or confirmation of compliance with the provisions of this Agreement. ARTICLE VIII - BILLING AND PAYMENTS 8.1 As soon as practicable after the end of each calendar month, SEPC shall determine and report to BHP the schedules of power and energy delivered to BHP under this Agreement during said month. For billing purposes, the amount of energy delivered by SEPC to BHP under this Agreement shall be the amount of energy scheduled by BHP during said month. 8.2 SEPC shall bill BHP monthly, in sufficient detail, for the preceding calendar month's services rendered hereunder. Bills for services provided hereunder shall be due within 15 days of the billing date. BHP shall submit payment to SEPC via wire transfer to an SEPC account, which account number shall be specified in writing to BHP prior to the commencement of each Contract Year. 8.3 Bills shall be rendered by facsimile transmission unless otherwise agreed to by the Parties in writing. Said bills shall be deemed rendered upon receipt by BHP, and BHP shall immediately confirm such receipt by return facsimile to SEPC. If the due date of any bill falls on Saturday, Sunday or a holiday observed by BHP, the bill shall be due on the next following BHP work date. Bills shall be deemed paid upon verification of receipt of funds by SEPC pursuant to Section 8.2 herein. Interest on any unpaid bill shall accrue from the date due and shall be compounded daily until the date payment is made. Such interest rate shall be established by the Federal Energy Regulatory Commission ("FERC") for refunds as set forth in 18 C.F.R. Section 35.19a or successor sections and shall be computed on the basis of actual days and a 365 day calendar year. 8.4 In the event BHP wishes to dispute all or any part of the charges submitted by SEPC, it shall nevertheless pay in full the amount of the charges when due and shall, within 60 days after the billing due date, give written notice stating the specific grounds on which the charges are disputed and the amount in dispute. This 60-day period shall not apply to any disputed amounts that could not, through reasonable diligence, have been identified during the 60-day period including any disputed amounts identified pursuant to an inspection of records under Section 7.1. BHP will not be entitled to any adjustment on account of any disputed charges which are not brought to the attention of SEPC within the time and in the manner herein specified. If settlement of the dispute results in a refund to BHP, interest shall accrue from the date of BHP's payment and be compounded daily until the date upon which the refund is made. Such interest rate shall be established by the FERC for refunds as set forth in 18 C.F.R. Section 35.19a or successor sections and shall be computed on the basis of actual days and a 365 day calendar year. ARTICLE IX - TERM OF AGREEMENT 9.1 The term of this Agreement shall be from the date of its execution, which date shall be inscribed in the first paragraph hereof, through September 30, 1996, and from year-to-year thereafter unless terminated by either Party giving at least 90 days written notice prior to the end of the then current Contract Year. Neither Party may give such notice of termination prior to July 1, 1996. ARTICLE X - TERMINATION 10.1 No termination of this Agreement shall release either Party from its obligation to pay for any charges incurred prior to the effective date of such termination, and for any sale or exchange of power and energy made pursuant to any Exhibit as may be signed by the Parties hereto and attached to this Agreement, or any legally binding arrangements related thereto, until the satisfaction and discharge of such obligations or as otherwise mutually agreed by the Parties hereto. 10.2 This Agreement is coterminous with the SEPC-WAPA Contract for transmission service. If the SEPC-WAPA Contract is terminated by WAPA, SEPC shall notify BHP within 30 days of receipt of notice of such termination and, unless the Parties mutually agree otherwise, this Agreement shall terminate on the same date of termination as the SEPC-WAPA Contract. SEPC shall use reasonable efforts to keep the SEPC-WAPA Contract in full force and effect. ARTICLE XI - TAXES, FEES, AND ALLOWANCES 11.1 Should any fee be charged to SEPC by any public authority having jurisdiction over the transaction hereunder, or any federal, state or local tax be levied upon the electric power or energy to be sold hereunder or upon SEPC measured by or directly related to the power or energy sold or the revenue therefrom, such tax or fee shall be added to the bill rendered to BHP as determined under the appropriate rates and billing procedures, unless said Parties agree otherwise. SEPC shall, within 30 days of receipt of notification concerning any tax or fee not imposed as of the date of execution of this Agreement, notify BHP of the conditions being imposed upon SEPC's sale of power and energy hereunder. 11.2 The Parties recognize that Congress has enacted the Clean Air Act Amendments of 1990, and that during the term of this Agreement, legislatures, regulatory bodies or courts may enact or issue other laws, regulations or orders relating to the environment that may affect the generation, sale, purchase or use of power and energy under this Agreement. 11.3 BHP represents and warrants that this Agreement and any capacity or energy purchased by BHP under this Agreement are not intended to be used, and will not be used, as part of a strategy or plan, by BHP or any other utility, to comply with Phase I emission limitations by compensating for the reduced generation or under-utilization of any such Phase I unit(s) owned or operated by BHP or any other utility. BHP shall defend and save harmless SEPC from any costs, penalties, losses and liabilities resulting in any manner or degree from BHP's breach of the representations and warranties covered in this Section 11.3. 11.4 If any tax, fee or requirement of allowances and costs referenced in this Article XI increases the price being paid for firm peaking capacity and associated energy hereunder by 30% or more, BHP may, prior to July 1 of each year, notify SEPC of its intent to terminate this Agreement on the following October 1. ARTICLE XII - FORCE MAJEURE 12.1 No Party shall be considered to be in default with respect to any obligation hereunder if prevented or delayed in whole or in part from fulfilling such obligation by reason of the occurrence of a Force Majeure, provided that the provisions of this Section shall not apply to the obligation to make payments when due for services actually rendered under this Agreement. The term "Force Majeure" shall mean storm, flood, lightning, earthquake, fire, explosion, failure of facilities not due to lack of proper care or maintenance, civil disturbance, labor disturbance, sabotage, war, national emergency, restraint by court or act of a Public Authority, or other causes beyond the control of the Party affected, which such Party could not reasonably have been expected to have avoided by exercise of due diligence and foresight and by provision of facilities in accordance with Prudent Utility Practice. Any Party unable to fulfill any of its obligations by reason of Force Majeure will exercise its best efforts to remove such disability with reasonable dispatch, provided that no Party shall be required to settle or resolve labor disturbances or strikes or to accept or agree to governmental or regulatory orders or conditions without objection or contest on any basis not acceptable to such Party in its sole discretion. Notice of the occurrence of a Force Majeure shall be given by the Party affected as soon as reasonably possible, but in no event later than 48 hours after learning of such Force Majeure. ARTICLE XIII - APPROVALS 13.1 This Agreement and any subsequent amendment(s) hereto shall be subject to the authority of any regulatory body or approving authority having jurisdiction hereof. ARTICLE XIV - ASSIGNMENT 14.1 This Agreement shall be binding upon and inure to the benefit of the permitted successors and assigns of the Parties hereto. 14.2 SEPC, without the approval of BHP, may assign, transfer, mortgage or pledge this Agreement to create a security interest for the benefit of the United States of America, acting through the Administrator of the Rural Electrification Administration (the "Administrator"). Thereafter, the Administrator, without the approval of BHP, may (a) cause this Agreement to be sold, assigned, transferred or otherwise disposed of to a third Party pursuant to the terms governing such security interest, or (b) if the Administrator first acquires this Agreement pursuant to 7 U.S.C. Section 907, sell, assign, transfer or otherwise dispose of this Agreement to a third Party; provided, however, that in either case (i) SEPC is in default of its obligations to the Administrator that are secured by such security interest and the Administrator has given BHP notice of such default; and (ii) the Administrator has given BHP thirty days' prior notice of its intention to sell, assign, transfer or otherwise dispose of this Agreement indicating the identify of the intended third-Party assignee or purchaser. No permitted sale, assignment, transfer or other disposition shall release or discharge SEPC from its obligations under this Agreement. 14.3 BHP may, without the approval of SEPC, assign, transfer, mortgage or pledge this Agreement, to create a security interest for the benefit of BHP's mortgage indenture trustee and the bondholders thereunder. 14.4 This Agreement shall inure to the benefit of and be binding upon the respective successors of the Parties by merger or sale of substantially all assets. 14.5 Except as provided in Section 14.1 through 14.4 above, neither Party shall assign its interest in this Agreement, in whole or in part, without the prior written consent of the other Party. Such consent shall not be unreasonably withheld. ARTICLE XV - INDEMNIFICATION 15.1 Each Party shall indemnify, hold harmless and defend the other Party, its agents, servants, employees, officers and directors from any and all costs and expenses, including but not limited to reasonable attorneys fees, court costs and other amounts which said other Party, its agents, servants, employees, officers and directors are or may become obligated to pay on account of any and all demands, claims, liabilities or losses arising or alleged to have arisen out of or in any way connected with the negligent acts or omissions or willful or wanton action of the indemnifying Party, its agents, servants, employees, officers or directors whether such demands, claims, liabilities or losses be for damages to property or injury or death of any person. ARTICLE XVI - GENERAL 16.1 In no event shall a Party to this Agreement be liable to the other Party hereto for any indirect, consequential, punitive, or similar damages arising from or in any way connected with this Agreement. 16.2 Notices to SEPC shall be sent to the Sr. Manager, Power Marketing, P.O. Box 980, Hays, KS 67601. Notices to BHP shall be sent to the Manager, Electric Operations, P.O. Box 1400, Rapid City, SD 57709. Either Party may change its address or the representative to which notices are to be sent by providing written notice of such change to the other Party. 16.3 Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed a waiver with respect to any other default or matter. 16.4 It is understood and agreed that all representations, understandings and prior negotiations are merged into this Agreement and that this Agreement constitutes the sole and entire Agreement between the Parties and no modification hereof shall be binding unless made a part hereof in writing executed by both Parties. IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed the day and the year first above written. SUNFLOWER ELECTRIC POWER CORPORATION /s/L. Christian Hauck L. Christian Hauck, President and Chief Executive Officer ATTEST: /s/L. Earl Watkins, Jr. L. Earl Watkins, Jr., Secretary BLACK HILLS POWER AND LIGHT COMPANY /s/Everett E. Hoyt Everett E. Hoyt President ATTEST: /s/Roxann Basham Roxann Basham Peaking Capacity Agreement Exhibit A Schedule of Firm Peaking Capacity Commitments 1. The specifications of this Exhibit A, agreed to on this 11th day of October, 1993, shall become effective on October 1, 1993, and shall remain in effect unless and until this Exhibit A is amended in writing by the Parties hereto; provided, however, this Exhibit A or any succeeding amendments to it shall terminate upon the expiration of the SEPC-WAPA Contract. 2. The Initial Point of Delivery will be the western bus of the Stegall Substation at a nominal voltage of 230 KV, or such other point as the Parties may agree. The annual firm seasonal peaking reservations in accordance with Article II of the Agreement are as follows: Year Summer Winter 1993 0 MW 15 MW 1994 40 MW 20 MW 1995 50 MW 30 MW 1996 20 MW 0 MW 3. The rates for firm peaking capacity are provided by year in the following chart. Year Rate Per KW-Month 1993 $3.20 1994 $3.78 1995 $4.41 1996 $4.63 EX-10.DD 3 AMENDMENT #1 TO PENSION EQUALIZATION PLAN EX-10.dd AMENDMENT #1 TO PENSION EQUALIZATION PLAN OF BLACK HILLS CORPORATION DATED APRIL 27, 1993 RESOLVED, that paragraph 3 of the Pension Equalization Plan of Black Hills Corporation and the Pension Equalization Plan of Wyodak Resources Development Corp. be amended effective April 27, 1993, to read as follows: Benefits payable to Participants shall consist of 180 equal monthly payments, each payment in the amount of one-twelfth of the product of (i) the Participant's Average Earnings as defined below as of the earlier of the date the Participant's employment with the Company was terminated, the date of the employee's participation in the Plan was terminated, or the date of the Participant's death ("Calculation Date"); times (ii) (a) 25 percent if the Participant's salary level is $50,000 or more and less than $100,000 or (b) 30 percent if the Participant's salary level is $100,000 or more; times (iii) the applicable vesting percentages provided in paragraph 5. Beginning January 1, 1991, the $50,000 salary level set forth in (ii) (a) shall be adjusted to be equal to the applicable contribution base as determined under Section 1402(k) (1) of the Internal Revenue Code (Social Security Wage Base) for 1991 and shall be similarly adjusted each and every year thereafter to equal the Social Security Wage Base for that year. Additionally, beginning January 1, 1991, the $100,000 salary level set forth in (ii) (b) shall equal two times the Social Security Wage Base for year 1991 and shall be similarly adjusted every year thereafter to equal two times the Social Security Wage Base for that year. "Earnings" shall mean the compensation paid to a Participant by the Company during a calendar year, including any amounts paid to the Participant as overtime, bonus, commission, or incentive compensation, any Earnings reduction under a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code, and any salary reduction under a flexible benefit program under Section 125 of the Internal Revenue Code, but excluding reimbursements and expense allowances, fringe benefits, moving expenses, nonqualified deferred compensation and welfare benefits. "Average Earnings" shall mean whichever of the following results in the highest average: (i) a Participant's average Earnings for the five (5) consecutive full calendar years of employment during the ten (10) full calendar years of employment immediately preceding the Calculation Date, which results in the highest such average; or (ii) a Participant's average Earnings determined by dividing the sum of the following by five (5): (a) the Participant's Earnings for the four full calendar years preceding the year containing his Calculation Date; (b) the Participant's Earnings for the year containing his Calculation Date as of the Calculation Date; and (c) a portion of the Participant's Earnings for the fifth full calendar year preceding the year containing his Calculation Date determined by multiplying his Earnings for said fifth preceding full calendar year by a ratio, the numerator of which shall be 365 minus the number of days in the year containing his Calculation Date measured from the first day of said year to his Calculation Date, and the denominator of which ratio shall be 365. If the Participant has less than five (5) full calendar years of employment, the average shall be taken over his total full calendar years of employment. EX-10.EE 4 BHC 1994 EXECUTIVE GAINSHARING PROGRAM EX-10.ee 1994 EXECUTIVE GAINSHARING PROGARM 1994 EXECUTIVE GAINSHARING PROGRAM The Executive Gainsharing Program is one of three sections of a Company- wide gainsharing program. Other work units participating in the Company- wide program are the Bargaining Unit and a program for the Management/Support Staff work unit. Each of the three work units have goals established in which participants can directly influence the results. The maximum award that any participant may receive is three percent. This program is designed for the officers in the following positions: Chairman, President and CEO; President and COO; Sr. Vice President, Finance; Vice President, Public Affairs and District Administration; Secretary/Treasurer, and Controller. BLACK HILLS CORPORATION 1994 Executive Gainsharing Program Goals I. Safety Goal (1%) This category has a total award value of 1%. The category is comprised of two (2) pre-qualification goals each independent of the other and worth a 1/2% each. The goals are: A. Motor Vehicle Accidents B. OSHA Recordable Occurrences. To receive a 1/2% award for each of the two goals, the Company average must be less than the NCEA average at year-end in each respective area. II. O&M Expense Reduction Goal (1%) This category has a total award value of 1%. For an award to be paid in this category, a reduction in the O&M budget must occur. A payout to the participants will be equal to one-third of the average company- wide participant gainshare payout. Example: The average 1994 gainshare award payout per participant is 2.5%. Each participant (officer) in this specific program would receive a payout equal to .825%. III. Neil Simpson II Goals (1%) The goal has a total award value of 1%. Each participant will develop a goal representing their respective area of responsibility in relation to Neil Simpson II. At year-end, the CEO will determine to what degree the goal has been achieved. Awards for each participant can be made in 1/4% increments not to exceed 1%. GUIDELINES The program will be comprised of a one year period starting January 1, 1994, through December 31, 1994. The gainshare program calculations and payout checks, if awarded, will be issued in the first quarter of the following year. An individual employee's gainsharing bonus, if any, will be paid on gross pay as it appears on the employee's W-2. This includes regular, paid time off, and other forms of compensation. An employee who transfers between one of the three gainshare programs as defined in the 1949 Gainsharing Program will have their gainshare bonus, if awarded, based upon where the greatest amount of time worked occurred. The maximum gainsharing award an employee may receive is 3%. Anyone terminated from employment with Black Hills Corporation before the completion of the program will not be eligible for any gainsharing bonus. Exceptions would be death, permanent disability or retirement. Board of Directors Retain Discretion This Plan is not at any time a contract of employment. The Company reserves the right to change this Plan whenever and in any manner it deems appropriate. Irrespective of changes in the Plan, no rights are vested. All awards are earned only when and if finally approved by the Board of Directors notwithstanding anything contained in the Plan that may be construed to be to the contrary. The Board of Directors, in its sole and absolute discretion, may decline to approve any award, though the participant may have achieved or exceeded threshold and target levels of performance. Setting a threshold or target of performance for any participant does not constitute a promise to pay an award even if the participant meets the threshold or target of performance. In determining whether to make an award and the amount of the award, the Board of Directors may consider criteria other than or in addition to the threshold and target performance determined under this Plan. Nothing in this Plan is a promise by the Company or any of its subsidiaries to continue to employ any participant for any period of time. EX-10.FF 5 BHC 1994 RESULTS COMPENSATION PROGRAM EX-10.ff 1994 RESULTS COMPENSATION PROGRAM Black Hills Power and Light Company Wyodak Resources Development Corp. Western Production Company RESULTS COMPENSATION PROGRAM Beginning January 1, 1994, a new program will be implemented into the current pay program. The program called "Results Compensation" will offer a significant enhancement to the Corporation's compensation philosophy and practice. The new Results Compensation program is designed to recognize and reward the contribution that group performance makes to corporate success. Results Compensation can pay financial rewards up to 8 percent of your earnings. GROUP PERFORMANCE There are several elements that go into determining the success of the Corporation. Some of these elements include: the market, general economic conditions, quality of management, strategic plans, regulatory agencies and the contributions employees make to achieving the goals; both on an individual basis and as part of a work unit. In general, the current merit/base pay system provides individual pay opportunities that are competitive in our respective industry and geographic location coupled with each company's ability to pay. The emphasis of the Results Compensation program is on rewarding group or business unit performance. RESULTS COMPENSATION PROGRAM OBJECTIVES The Results Compensation program is designed to meet the following objectives: - Enhance and broaden the current compensation philosophy and pay practice. - Share the results of the Corporation and the business unit with the people who contribute to that success. - Motivate work performance and behavior that supports the Corporate and business unit financial goals. - Increase the employee's understanding of the business. RESULTS COMPENSATION GUIDELINES - The program will encompass a one-year period; January 1, 1994, through December 31, 1994. Results Compensation awards, if approved, will be paid out in the first quarter of the following year. - Regular full-time and regular part-time employees are eligible to participate in this program. - An individual employee's Results Compensation award, if any, will be paid on gross pay as it appears on the employee's W-2 form. This includes regular, overtime, paid time off and other forms of premium pay. - An employee who transfers between one of the three participating companies, BHP, WRDC and WPC, during the program year will have the Results Compensation award, if approved, based upon where the greatest amount of time worked occurred. - The local union IBEW, 1250, elected not to participate in the Results Compensation program. Therefore, bargaining unit employees will not be eligible to receive a Results Compensation award. - An employee who transfers to or from a bargaining unit position will receive a pro-rated Results Compensation award, if approved, relative to the amount of time worked in the non-bargaining unit position and gross pay earned in the non-bargaining unit position. - The maximum Results Compensation bonus and award an employee may receive is 8 percent. - In determining the bonus percentage to be paid, calculations will be rounded to two decimal places (e.g., 1.43%) not rounded to the nearest whole percentage amount. - Any participating employee whose employment relationship with the Corporation is terminated voluntarily or involuntarily prior to the end of the program year will not be eligible for any Results Compensation award. Exceptions would be death, permanent disability or retirement. DETERMINING RESULTS COMPENSATION AWARDS The Results Compensation program has two key financial goals. The financial goals consist of a business unit goal and a corporate goal. Whether a program award is paid and how much any award will be depends on how well and to what degree the goals were obtained as evaluated by the Board of Directors. GOAL 1. FINANCIAL PERFORMANCE OF THE INDIVIDUAL BUSINESS UNIT (BHP, WRDC AND WPC) BASED ON OPERATING INCOME. Operating income is all unit revenue, less operating expense, before corporate income taxes and interest charges. This measures the financial results of operations. Participants can receive up to four percent of their total Results Compensation award from this goal; specifics are attached. Specific goals will be determined and communicated to each employee of the respective business unit upon finalization of the budget process. GOAL 2. CORPORATE CONSOLIDATED EARNINGS PER SHARE (EPS) GOAL. Earnings per share are equal to the total profit divided by the number of shares of Black Hills Corporation common stock owned by shareholders. Participants can receive up to four percent of their total Results Compensation award from the goal. Since this is a consolidated Corporate goal, all employees in the different business units will have the same goal; specifics are attached. The specific goal will be determined and communicated to each employee upon finalization of the budget process. BOARD OF DIRECTORS RETAIN DISCRETION This program is not at any time a contract of employment. The Company reserves the right to change this program whenever and in any manner it deems appropriate. Irrespective of changes in the program, no rights are vested. All awards are earned only when and if finally approved by the Board of Directors notwithstanding anything contained in the program that may be construed to be to the contrary. The Board of Directors, in its sole and absolute discretion, may decline to approve any award, though the participant may have achieved or exceeded threshold and target levels of performance. Setting a threshold or target of performance for any participants does not constitute a promise to pay an award even if the participant meets the threshold or target of performance. In determining whether to make an award and the amount of the award, the Board of Directors may consider criteria other than or in addition to the threshold and target performance determined under this program. Nothing in this program is a promise by the Corporation to continue to employ any participant for any period of time. EX-13 6 1993 ANNUAL REPORT TO SHAREHOLDERS FINANCIAL DIRECTORY Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . .12 Report of Management . . . . . . . . . . . .19 Report of Independent Public Accountants . .19 Consolidated Statements of Income . . . . .20 Consolidated Statements of Retained Earnings . . . . . . . . . . . . . . . . .20 Consolidated Statements of Cash Flows. . . .21 Consolidated Balance Sheets . . . . . . . .22 Consolidated Statements of Capitalization .23 Notes to Consolidated Financial Statements .24 Financial Statistics . . . . . . . . . . . .30 Electric Operation Statistics . . . . . . .31 Investor Information . . . . . . . . . . . .32 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Black Hills Corporation (the Company) is an energy services company consisting of three principal businesses: electric, coal mining, and oil and gas production. Under the assumed name of Black Hills Power and Light Company, the Company provides electric service to customers in the states of South Dakota, Wyoming, and Montana; Wyodak Resources Development Corp. (WRDC) mines and sells coal via long-term contracts; and Western Production Company (WPC) explores and produces oil and gas. FINANCIAL CONDITION An important analysis of the Company's financial condition is its overall ability to generate cash to fund its operations and to pay dividends. Of particular importance in the management of liquidity are: funds generated by operations, changes in working capital, fixed asset additions, and the financial flexibility to attract short and long-term financing on competitive terms. Net cash provided from operating and investing activities for the years ended December 31, 1993, 1992, and 1991, was $6,496,000, $15,359,000, and $(4,666,000), respectively. Except for the Company's current construction of Neil Simpson Unit #2 (NSS #2), a new power plant, and acquisition of a 20% interest in the Wyodak Plant in 1991, property additions from 1991 through 1993 were primarily for replacement of equipment and modernization of facilities. Cash used for property additions in 1993 totaled $39,957,000 compared to $27,821,000 in 1992 and $25,587,000 in 1991. Major property additions in 1993 included $12,675,000 for NSS #2 (see Construction of Neil Simpson Unit #2), $6,000,000 for distribution projects, $2,000,000 for transmission projects, $2,000,000 for a computer conversion, $4,800,000 for a new coal conveying system, $2,200,000 for coal mining equipment, and $6,933,000 for oil and gas investments. Property additions in 1992 included $2,227,000 for NSS #2, $1,300,000 for the dual fuel conversion of two combustion turbines, $6,700,000 for distribution projects, $2,600,000 for coal haulers, $2,000,000 for an electric shovel, and $5,000,000 for oil and gas investments. Property additions in 1991 included $1,300,000 for remodeling the General Office, $1,500,000 for transmission lines, $2,500,000 for a 230/69 KV substation, $6,700,000 for distribution projects, $1,500,000 for new information services technology, $1,000,000 for the purchase of surface rights over the Fortin Draw Tract coal lease, and $6,000,000 for oil and gas investments. On April 8, 1991, the Company purchased a 20% interest and PacifiCorp an 80% interest in the Wyodak Plant, a 330 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Wyodak Plant. The total acquisition cost of the Company's 20% interest was approximately $42,022,000. The Company financed its 20% interest with the issuance of first mortgage bonds, therefore, the acquisition is not included above in the amount of cash used for property additions. In 1990 the Company received a rate order from the South Dakota Public Utilities Commission that allows the capitalization of the full cost of the Wyodak Plant for rate making purposes in South Dakota. Electric sales to South Dakota customers represent approximately 82% of total electric sales. The Company and PacifiCorp had leased the Wyodak Plant since 1978 under a leveraged lease agreement. The capital asset and associated debt were previously amortized over the original term of the lease. The net effect of terminating the lease and purchasing the Wyodak Plant was approximately an $11,300,000 increase in debt. The Company purchased the 20% interest in the Wyodak Plant in order to provide its customers a reasonable cost of power from the plant after the term of the original lease. The purchase of the Wyodak Plant also gives the Company more control over the use of common facilities in the operation of any new plants which may be constructed at the site. Other financial requirements during the period included dividends of $17,720,000, $16,977,000, and $16,045,000 and retirement of long-term debt totaling $4,166,000, $3,725,000, and $1,921,000 for the years 1993, 1992, and 1991, respectively. Capital requirements for projected construction, capital improvements, and oil and gas production are estimated to be as follows:
1994 1995 1996 (in thousands) NSS #2 $65,113 $45,035 $ - Other electric 14,470 9,793 18,605 Coal mining 2,129 853 2,042 Oil and gas production 5,000 6,000 6,000 $86,712 $61,681 $26,647
Major capital expenditures forecasted for the electric operations in the 1994-1996 time frame include approximately $110,148,000 for additional capacity (See Construction of Neil Simpson Unit #2). The coal mining operations forecasted expenditures include the replacement of mining equipment. Forecasted expenditures for the oil and gas operations include an active development and exploratory drilling program and acquisition of existing producing properties. Long-term debt and sinking fund requirements are as follows:
1994 1995 1996 (in thousands) Electric $2,028 $2,136 $2,255 Coal mining 1,514 8 - $3,542 $2,144 $2,255
Under its mining permit, WRDC 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 $650,000 is charged to operations as reclamation expense annually. As of December 31, 1993, accrued reclamation costs were $7,290,000. The Company's capitalization for the three years ended December 31 was as follows:
1993 1992 1991 Long-term debt 34% 37% 40% Common equity 66 63 60 100% 100% 100%
The Company sold 525,000 shares of Common Stock, $1 par value, at a price of $25-3/8 per share in 1993 through a public stock offering. Proceeds from the sale were used to finance NSS #2. Net proceeds from the sale were approximately $12,700,000. During 1993 the Company also revised its Dividend Reinvestment and Stock Purchase Plan, under which shareholders may purchase additional shares of Common Stock through dividend reinvestment or optional cash payments at 100% of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. Proceeds from the sale of new shares will be used to finance capital expenditures. The Company issued $12,300,000 Pollution Control Revenue Refunding Bonds in 1992 to redeem $12,300,000 Pollution Control and Industrial Revenue Bonds which were collateralized as first mortgage bonds. The refunding bonds have no sinking fund requirements and are longer term than the redeemed bonds maturing in 2010, thereby preserving the lower tax exempt interest rate for a longer period of time. The redeemed bonds had sinking fund provisions which were to begin in 1993 and would have retired the principal in approximately equal amounts until their final due date in 2007. The refunding bonds are not secured under the Company's Indenture of Mortgage, therefore this refunding transaction increased the Company's ability to issue first mortgage bonds. During 1992, the Company also entered into a refunding agreement to refund the existing August 1, 1984, $12,200,000, 10.5% Pollution Control Revenue Bonds in July 1994 with 7.5% Pollution Control Revenue Bonds. The refunding agreement obligates the Company to call and satisfy in full the existing bonds as of August 1, 1994, including a redemption premium of 2% or $240,000 on the existing bonds. Because of the forward nature of this transaction it will not be reflected in the Company's financial statements until 1994. ______________________________________________________________________ (TABLE IN ANNUAL REPORT) COMMON STOCK DATA 1993 1992 1991 Net Income $22,946,000 $23,638,000 $22,681,000 Earnings Per Average Share $1.66 $1.73 $1.66 Weighted Average Shares Outstanding 13,810,912 13,689,105 13,674,983 Dividends Paid Per Share $1.28 $1.24 $1.17 Five Year Dividend Growth Rage 6.6% 8.4% 9.1% Payout Ratio 77.1% 71.7% 70.7% Book Value $11.78 $10.89 $10.38 Year-end Stock Price $22-3/4 $27-1/2 $27-1/2 Dividend Yield on Market Value 5.6% 4.5% 4.3% Price Earning Ratio 14 16 17 Return on Common Equity at Year-End 13.7% 15.8% 16.0% _____________________________________________________________________ During 1991, the Company issued $48,806,000 of first mortgage bonds. The bonds were issued in two series, $35,000,000 at 9.35% due 2021 and $13,806,000 at 9.00% due 2003. The funds were primarily used for the purchase of the Company's 20% interest in the Wyodak Plant. At December 31, 1993, the Company had $40,000,000 of unsecured short- term lines of credit which provides for interim borrowings and the opportunity for timing of permanent financing, with borrowings outstanding of $11,700,000. Average borrowings during 1993, 1992, and 1991 were $11,059,000, $5,616,000, and $4,552,000, respectively. The average interest rate on these borrowings was 5.2%, 6.0%, and 8.3% in 1993, 1992, and 1991, respectively. The Company anticipates that the average borrowings in 1994 and 1995 will increase significantly directly related to the financing of the construction of NSS #2. There are no compensating balance requirements associated with these lines of credit. The Company pays a 0.125% facility fee on $10,000,000 of the existing lines. ______________________________________________________________________ (CHART IN ANNUAL REPORT) CONSOLIDATED DEBT RATIOS (in percent) 1993 33.7 1992 37.3 1991 39.6 1990 36.9 1989 38.3 ______________________________________________________________________ Credit ratings for the Company's First Mortgage Bonds remained at an A1 level at Moody's Investors Service, Inc., a 5 (High Single A) at Duff & Phelps, Inc., and at an A+ level with a negative outlook at Standard & Poor's Corporation in 1993. These ratings reflect the opinion of the respective agencies as to the credit quality of the Company's bonds. Standard & Poor's stated that the negative outlook was issued reflecting a burdensome future construction program which will pressure financials and will require supportive rate treatment to maintain current credit worthiness. In the past the Company has depended upon internally generated funds, issuance of short and long-term debt, and sales of preferred and common stock to finance its activities. Additional long-term financing will be necessary in the 1994-1995 time period to finance NSS #2 (See Construction of Neil Simpson Unit #2). CONSTRUCTION OF NEIL SIMPSON UNIT #2 Construction of NSS #2, an 80 MW coal fired generating plant located adjacent to WRDC's coal mine, commenced in August 1993. The plant construction is scheduled to be completed by the end of 1995. Purchased power will be utilized by the Company in the interim to meet load growth not satisfied by existing resources. The construction costs of the plant are estimated at $124,889,000 which will increase net utility plant by approximately 58%. As of December 31, 1993, the Company has incurred approximately $15,000,000 of costs related to the plant. NSS #2 will be air cooled, and will meet all Clean Air Act requirements. NSS #2 will be fueled by coal from WRDC's mine and will increase the amount of tons sold annually by approximately 10%. The coal pricing methodology will continue to restrict WRDC's earnings on all coal sales to the Company to a return on its investment base and to further reduce the price for coal to be used in any of the Company's power plants during a period of time that under prudent dispatch that power plant would not have been operated if it were not for the discounted price of coal. Additional long-term financing will be needed in the 1994-1995 time period to finance NSS #2. The Company estimates that approximately $87,000,000 of debt and $4,000,000 of additional equity will need to be issued. The Company plans to raise the additional equity through the Company's Employee Stock Purchase Plan and Dividend Reinvestment Plan. These additional financings are expected to increase the debt component of the Company's capital structure from 34% at December 31, 1993 to approximately 45% to 48% by 1996. The Company has guaranteed to the South Dakota Public Utilities Commission (SDPUC) and the Wyoming Public Service Commission that the Company will never include in rate base for the determination of electric rates those costs of NSS #2 which exceed $124,889,000 including allowance for funds used during construction. Due to the guarantee, the Company would likely be forced to write off against earnings any construction costs of NSS #2 in excess of the guaranteed costs except to the extent that those costs could be recovered through performance guarantees and damage provisions in the contracts with the vendors and contractors. The Company estimates that over 85% of the completion costs of the project has been contracted. The $124,889,000 estimated cost of the plant currently includes a $4,800,000 unallocated contingency. During 1993, the Company withdrew its application to the SDPUC for a rate stability plan that had requested rate increases to be phased in during construction of NSS #2. The Company reassessed the probable rate impact of NSS #2 and determined that a phased-in plan would not be necessary. The Company estimates that due to lower capital costs, coal cost concessions, and cost containment, an overall rate increase of approximately 10% in 1996, along with adjustments during construction as a result of the purchased power and automatic fuel adjustment tariff, should be sufficient to incorporate NSS #2 into the Company's electrical rates. ROSEBUD QUALIFYING FACILITY CHALLENGE DISMISSED In May 1993, the SDPUC issued an order denying a request by Rosebud Enterprises, Inc. (Rosebud) that the SDPUC determine the Company's resource needs, the avoided costs of the needed resource, and to force the Company to purchase power from Rosebud. Rosebud had proposed to sell the Company power generated from a waste fuel facility that would be qualified under the Public Utility Regulatory Policies Act. The SDPUC further denied Rosebud's request to issue an order finding that the Company may be imprudent to proceed with construction of NSS #2. The SDPUC did find that the Company had in good faith planned and permitted NSS #2 in order to fulfill the Company's duty to serve its customers. The SDPUC's bench ruling stated that in order to be able to defer or cancel the construction of new generation, a utility must obtain a sufficient commitment from a qualifying facility ahead of the lead time for the construction of its own new capacity. By its late qualifying facility proposal to the Company and its failure to move its project forward, Rosebud had not enabled the Company to avoid NSS #2. The SDPUC further ruled that the risk of building NSS #2 was on the Company, and the Commission would not rule on the prudency and need for the plant until the Company applied for a rate increase that included NSS #2 in rate base. ______________________________________________________________________ (CHART IN ANNUAL REPORT) FIRM ELECTRIC SALES (Millions of KWH) 1993 1,594 1992 1,540 1991 1,532 1990 1,479 1989 1,433 ______________________________________________________________________ RESULTS OF OPERATIONS: CONSOLIDATED RESULTS Consolidated net income for 1993 was $22,946,000 compared to $23,638,000 in 1992 and $22,681,000 in 1991 or $1.66, $1.73, and $1.66 per average common share, respectively. This equates to a 13.7% return on year-end common equity in 1993, 15.8% in 1992, and 16.0% in 1991. The Company recognized a non-recurring $940,000 after-tax non-cash gain in 1992 related to the PacifiCorp Settlement (see PacifiCorp Settlement) which was equivalent to $0.07 per share. Without this gain, earnings per share would have been flat for the three year period with 1% more average common shares outstanding in 1993. Consolidated revenue and income provided by the three businesses as a percentage of the total were as follows:
Revenue 1993 1992 1991 Electric 71% 72% 73% Coal mining 21 21 20 Oil and gas production 8 7 7 100% 100% 100% Net Income Electric 49% 47% 54% Coal mining 46 49 42 Oil and gas production 5 4 4 100% 100% 100%
Dividends paid on Common Stock totaled $1.28 per share in 1993. This reflected increases approved by the Board of Directors from $1.24 per share in 1992 and $1.17 per share in 1991. Dividends have increased at a 5.5% average annual compound growth rate over the last three years. All dividends were paid out of current earnings. In January 1994 the Board of Directors increased the quarterly dividend 3.1% to 33 cents per share. If this dividend is maintained during 1994, the increase is equivalent to an annual increase of 4 cents per share. In January 1992 the Board of Directors declared a three-for-two common stock split in the form of a 50% stock dividend, payable March 2, 1992. All per share information included herein gives retroactive effect for the stock split for all periods presented. WYODAK PLANT MAINTENANCE SCHEDULE The Wyodak Plant was out of operation for six weeks in 1991 for scheduled maintenance and is scheduled for maintenance again in the spring of 1994. Fiscal 1992 and 1993 represent whole years of operations from the Wyodak Plant. When the Wyodak Plant is out of service, replacement power is provided from purchased power and increased generation from the Company's other generating plants. Additional purchased power costs are recovered by the utility through the fuel adjustment clauses. The loss of coal sales to the Wyodak Plant is partially mitigated through greater coal sales to the Company's other generating plants and reduced operating costs. PACIFICORP SETTLEMENT In 1987 WRDC and the Company entered into settlement agreements with PacifiCorp canceling PacifiCorp's obligation to purchase coal commencing in 1990 for a second plant scheduled to be constructed adjacent to the Wyodak Plant but which had been canceled, and settling a dispute over the quantity of coal PacifiCorp was required to purchase to operate the Wyodak Plant. These settlements resulted in an increase in the Company's net income in 1993, 1992, and 1991 of approximately $1,500,000, $2,800,000, and $2,600,000 or $0.11, $0.20, and $0.19 per share of common stock, respectively. The settlements provided for, among other things, payments to WRDC of $2,000,000 each on January 2, 1988 through 1991 for an option to purchase 50,000,000 tons of coal if PacifiCorp should construct a second Wyodak power plant and require PacifiCorp to pay up to $15,000,000, such amount to be adjusted for inflation and deflation, for the cost of new coal handling facilities. Construction of the coal handling facilities occurred in 1992 and 1993. As a result of a definitive agreement entered into with PacifiCorp in 1992 regarding the construction of these facilities, the Company recognized a nonrecurring $940,000 after-tax non-cash gain in 1992. The gain was due to the assumption by PacifiCorp of certain liabilities related to the existing coal handling facilities that were replaced by the construction of the new facilities. Other benefits from the PacifiCorp Settlement will continue to have a positive effect on earnings for the life of the agreements. The exact amount of earnings each year will depend largely upon the continued successful operation of the Wyodak Plant. ______________________________________________________________________ (CHART IN ANNUAL REPORT) TONS OF COAL SOLD (thousands of tons) 1993 3,027 1992 2,958 1991 2,742 1990 2,908 1989 2,349 ______________________________________________________________________
Electric Operations 1993 1992 1991 (in thousands) Revenue $98,155 $97,448 $98,158 Operating expenses 74,173 74,056 73,522 Operating income $23,982 $23,392 $24,636 Net income $11,171 $11,041 $12,156
Electric revenue increased 0.7% in 1993 compared to a 0.7% decrease in 1992 and a 6.4% increase in 1991. Firm kilowatthour sales increased 3.5% in 1993 compared to a 0.5% increase in 1992 and a 3.6% increase in 1991 and have averaged an annual 2.5% growth rate over the last three years. Homestake Mining Company, the Company's largest customer, reduced its energy usage by 22,000 megawatt hours in 1993 by concentrating on more efficient production areas in a depressed gold market. Sales growth in 1992 was reduced by mild weather conditions. The revenue increase in 1993 from additional electric sales was offset by a decrease in the fuel and purchased power adjustment passed on to electric customers. The decrease in purchased power was due to a $2,000,000 refund received from PacifiCorp on the 40-year power purchase agreement. Revenue decreased in 1992 due to a decrease in the fuel and purchased power adjustment passed on to electric customers. This decrease was a result of a $600,000 increase in the refund accrued for the limitation on the return allowed on WRDC coal sales to the Company's power plants and a $600,000 decrease in fuel and purchased power expense. Purchased power decreased in 1992 compared to 1991 due to a full year of operations at the Wyodak Plant. In South Dakota, the Company may not include in rates any cost of coal which allows WRDC to earn a return on equity on sales of coal to the Company's utility operations in excess of a percentage equal to the rate on long-term "A" rated utility bonds plus 400 basis points (4%). The investment base on which the return is calculated includes all of WRDC's investment base except for investments in subsidiary companies and other non-mining interests. The maximum return on equity to be applied in 1994 for the 1993 adjustment will be approximately 11.6%. The returns applied in 1992 and 1991 were 12.7% and 13.4%, respectively. The Company has recorded an accrual for the 1994 refund for sales in 1993 of approximately $1,060,000. The 1993 and 1992 refunds were approximately $1,538,000 and $940,000, respectively. Tons of WRDC's coal sold to Black Hills represent approximately 35% of its total coal sales. The refund increased in 1994 and 1993 compared to 1992 primarily due to the decrease in long-term "A" rated utility bond interest rates. The decrease in the allowed return in 1993 was offset by an increase in WRDC's investment base primarily due to its investment in an electric shovel and new coal conveying facilities. Revenue per kilowatt sold was 6.0 cents in 1993 down from 6.2 cents in 1992 and 6.1 cents in 1991. The number of customers in the service area increased to 53,330 in 1993 from 52,535 in 1992 and 51,775 in 1991. Operating expenses were relatively flat in 1993 compared to 1992 as a result of the $2,000,000 purchased power refund. Operating expenses increased 0.7% in 1992, and decreased slightly in 1991. The decrease in 1991 reflects the effect of buying out the Wyodak Plant Lease and a decrease in administrative and general expenses and property taxes. The Wyodak Plant Lease payment was recorded as an operating expense in the past. Since the purchase of the Plant in April 1991, the cost of ownership is now reflected in depreciation and interest expense. The Company went through a corporate reorganization during the first quarter of 1991 resulting in a $600,000 reduction in administrative and general expenses. Eleven existing positions and several vacant positions were eliminated. During 1991 the South Dakota Department of Revenue instituted the unit valuation method in determining property values for those entities whose property is centrally assessed for tax purposes resulting in a decrease in property taxes of approximately $1,050,000 from 1990 levels. Property taxes increased $540,000 in 1993 and $600,000 in 1992 as a result of increased valuations.
COAL MINING OPERATIONS 1993 1992 1991 (in thousands) Revenue $29,822 $28,296 $26,138 Operating expenses 17,462 16,724 16,667 Operating income $12,360 $11,572 $ 9,471 Net income $10,648 $11,695 $ 9,623
Revenue increased 5.4% in 1993 and 8.3% in 1992 due to a 2.3% and 7.9% increase, respectively in tons of coal sold. The increase in tons of coal sold reflects two whole years of operations at the Wyodak Plant. Operating expense increased 4.4% in 1993 reflecting an increase in depreciation expense as a result of an increase in capital investments and higher taxes associated with increased revenues. Operating expenses remained relatively flat in 1992 caused by a decrease in administrative and general expenses offset by an increase in coal production. Operating income increased 6.8% in 1993 and 22.2% in 1992 reflecting the increase in coal revenue. ______________________________________________________________________ (CHART IN ANNUAL REPORT) EQUIVALENT BARRELS OF OIL SOLD (thousands of barrels) 1993 465 1992 315 1991 262 1990 205 1989 207 ______________________________________________________________________ Revenue decreased 1.5% in 1991 due to a 5.7% decrease in tons of coal sold offset by a 4.5% increase in the average price per ton sold. The decrease in tons of coal sold was primarily due to the Wyodak Plant's scheduled six week maintenance period during the year. The increase in the average price was due to increases in the government indices used in the coal contract price calculations and 1990 coal audit adjustments. Operating expenses decreased 4.1% in 1991 due to the decrease in coal production and a decrease in ad valorem taxes and administrative expenses. Administrative expenses decreased due to the corporate reorganization that occurred during the year. Operating income increased 3.4% primarily due to the decrease in administrative expenses. Non-operating income was $2,226,000 in 1993 compared to $3,894,000 in 1992 and $3,677,000 in 1991. Non-operating income includes the PacifiCorp Settlement, a coal contract settlement from Grand Island, Nebraska, and interest income from investments. Non-operating income decreased in 1993 due to a decrease in interest income attributable to lower interest rates and a non-recurring $940,000 after-tax non-cash gain recognized in 1992 related to the PacifiCorp Settlement. In late 1987 WRDC agreed to the termination of a long-term coal supply agreement with the City of Grand Island, Nebraska. Grand Island was granted a 14 year option to purchase coal and in return WRDC receives payments of approximately $155,000 each year. WRDC has reserved sufficient coal in the eventuality the City of Grand Island exercises its option.
Oil and Gas Production 1993 1992 1991 (in thousands) Revenue $11,396 $9,599 $9,077 Operating expenses 9,952 8,214 7,717 Operating income $ 1,444 $1,385 $1,360 Net income $ 1,127 $ 902 $ 902
The oil and gas operations have not been a significant percent of the Company's total operations. Net income and assets related to oil and gas operations have been 7% or less of the Company's consolidated amounts over the last three years. Revenue, primarily comprised of oil and gas sales, is supplemented by field services in the Finn-Shurley oil field in eastern Wyoming. Equivalent barrels of oil sold increased approximately 48% to 465,000 barrels in 1993 from 315,000 barrels in 1992 and 262,000 barrels in 1991. The average sales price of oil per barrel was $16.69 in 1993 compared to $19.10 in 1992 and $20.03 in 1991. WPC's operating expenses increased 21% in 1993 compared to 6.4% in 1992 and 9.6% in 1991. Operating expenses increased primarily due to increased depletion expense as a result of increased oil and gas production and lower oil prices. WPC recognized $3,725,000, $2,291,000, and $1,350,000 of depletion expense in 1993, 1992, and 1991, respectively. Low commodity prices reduce the value of the Company's oil and gas assets and will cause the Company to increase its depletion expense. Management estimates that oil prices must average $14 to $15 per barrel for its oil and gas operations to remain profitable. WPC's proved reserves, and the revenues generated from production, will decline as production occurs, except to the extent WPC conducts successful exploration and development activities or acquires additional proved reserves. WPC has been in an active exploration and development drilling program during 1991, 1992, and 1993. Much of WPC's production growth in 1993 was the result of its horizontal drilling program in the Austin Chalk formation in Texas. WPC intends to increase its net proved reserves by selectively increasing its oil and gas exploration and development activities and by acquiring additional interests in the Finn- Shurley oil field and Rocky Mountain region primarily with the use of internally generated funds. WPC's reserves are based on reports prepared by Ralph E. Davis Associates, Inc. in 1993 and 1992 and Huddleston & Co., Inc. in 1991, independent engineering companies, selected by the Company. 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. WPC's unaudited reserves, principally proved developed and undeveloped properties, were estimated to be 1.1, 2.2, and 2.5 million barrels of oil and 2.8, 3.2, and 4.8 billion cubic feet of natural gas as of December 31, 1993, 1992, and 1991, respectively. The decrease in the reserves was caused by price decreases, production increases, and engineering revisions. WPC has interests in 386 oil and gas properties in seven states. WPC operates a total of 347 wells in Wyoming, Colorado, and South Dakota. WPC's non-operated properties are located in Wyoming, Colorado, North Dakota, Montana, Kansas, and Texas. EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS On January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. This new standard requires that the expected cost of these benefits must be accrued for during the years employees render service. The Company prospectively adopted the new standard effective January 1, 1993, and is amortizing the discounted present value of the accumulated postretirement benefit obligation of $2,996,000 to expense over a 20 year period. The net periodic postretirement cost charged to expense in 1993 was $527,000 (pre-tax). For measurement purposes, an 11.5% annual rate of increase in healthcare benefits was assumed for 1994; the rate was assumed to decrease gradually to 6% in 2005 and remain at that level thereafter. The healthcare cost trend rate assumption has a significant effect on the amount reported. A 1% increase in the health care cost trend assumption would increase the net periodic postretirement benefit cost by approximately $140,000 annually or 20.8%. ACCOUNTING FOR INCOME TAXES Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, which requires the use of 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 reporting and tax basis of assets and liabilities. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. The new standard required adjustments to existing balances of accumulated deferred income taxes to reflect changes in income tax rates. To the extent such income taxes are recoverable or payable through future rates, a $6,912,000 net regulatory liability has been recorded in the accompanying consolidated balance sheets. Initial application of the statement had no material impact on the Company's results of operations. INFLATION Inflation may have a significant impact on replacement of property and capital improvements in the future due to the capital intensive nature of the utility business. The rate making process gives no recognition to the fair value of existing plant; however, in the past, the Company has been allowed to recover and earn on the increased cost of its net investment when the addition to or replacement of facilities occurred. The majority of the mining operations' coal contracts provide for the adjustment over time of components of the sales price through indexes, formulas, or direct pass-through of costs. REPORT OF MANAGEMENT Management of Black Hills Corporation is responsible for the preparation, integrity, and objectivity of the consolidated financial statements of the Company and its subsidiaries. The consolidated financial statements are prepared in conformity with generally accepted accounting principles and reflect management's informed judgments and best estimates with due consideration given to materiality. Information contained elsewhere in the Annual Report is consistent with the consolidated financial statements. The Company's system of internal controls is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management's authorization, and the consolidated financial statements are prepared in accordance with generally accepted accounting principles. The internal controls are continually reviewed and evaluated for effectiveness. No internal control system can prevent the occurrence of errors and irregularities with absolute assurance due to the inherent limitations of any system. Management's objective is to maintain a system that meets its goals in a cost effective manner. The Audit Committee, composed exclusively of outside directors, is responsible for overseeing the Company's financial reporting process and reporting the results of its activities to the Board of Directors. This committee, management, and the internal auditor periodically review matters associated with financial reporting, audit activities, and internal controls. As part of their audit of the Company's 1993 consolidated financial statements, the Company's independent auditors, Arthur Andersen & Co., considered the Company's system of internal controls to the extent they deemed necessary to determine the nature, timing, and extent of their audit tests. The independent and internal auditors have free access to the Audit Committee to discuss the results of their audits without the presence of management. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Black Hills Corporation: We have audited the accompanying consolidated balance sheets and statements of capitalization of BLACK HILLS CORPORATION AND SUBSIDIARIES as of December 31, 1993 and 1992, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Black Hills Corporation and Subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. As discussed in Notes 8 and 9 to the consolidated financial statements, effective January 1, 1993, the Company changed its method of accounting for post retirement benefits other than pensions and its method of accounting for income taxes. ARTHUR ANDERSEN & CO. Minneapolis, Minnesota, January 28, 1994 BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31 1993 1992 1991 (in thousands) Operating revenues: Electric . . . . . . . . . . .$ 98,155 $ 97,448 $ 98,158 Coal mining. . . . . . . . . . 29,822 28,296 26,138 Oil and gas production . . . . 11,396 9,599 9,077 139,373 135,343 133,373 Operating expenses: Fuel and purchased power . . . 36,946 38,209 38,851 Operations . . . . . . . . . . 23,368 23,337 23,825 Maintenance . . . . . . . . . 6,869 6,513 6,729 Administrative and general . . 8,144 7,811 7,910 Depreciation, depletion, and amortization . . . . . . . . 16,051 13,860 12,012 Taxes, other than income taxes (Note 12) . . . . . . . 10,209 9,264 8,579 101,587 98,994 97,906 Operating income: Electric . . . . . . . . . . . 23,982 23,392 24,636 Coal mining . . . . . . . . . 12,360 11,572 9,471 Oil and gas production . . . . 1,444 1,385 1,360 37,786 36,349 35,467 Other income (expense): Interest expense . . . . . . . (8,817) (8,965) (8,001) Investment income . . . . . . 1,739 3,149 2,956 Allowance for funds used during construction . . . . 729 378 177 Other, net (Note 12) . . . . . 474 1,233 631 (5,875) (4,205) (4,237) Income before income taxes . . . 31,911 32,144 31,230 Income taxes (Note 9). . . . . . (8,965) (8,506) (8,549) Net income . . . . . . . .$ 22,946 $ 23,638 $ 22,681 Weighted average common shares outstanding (Note 2) . . . . . 13,811 13,689 13,675 Earnings per share of common stock (Note 2) . . . . . . . .$ 1.66 $ 1.73 $ 1.66 The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31 1993 1992 1991 (in thousands) Balance, beginning of year . . . . . . $105,173 $ 98,512 $91,876 Net income . . . . . . . . . . . . . . 22,946 23,638 22,681 Cash dividends on common stock ($1.28, $1.24, and $1.17 per share, respectively) . . . . . . . . (17,720) (16,977) (16,045) Balance, end of year . . . . . . . . . $110,399 $105,173 $98,512
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31 1993 1992 1991 (in thousands) Cash flows provided from (used for) operating activities: Net income . . . . . . . . . . . . . $ 22,946 $23,638 $22,681 Principal non-cash items- Depreciation, depletion, and amortization . . . . . . . . . . 16,051 13,860 12,012 Deferred income taxes and investment tax credits. . . . . . 1,042 761 (801) Gain on coal settlement . . . . . . - (940) - Allowance for other funds used during construction . . . . . . . . . . (333) (94) (65) (Increase) decrease in receivables, inventories, and other current assets (1,556) 1,378 488 Increase (decrease) in current liabilities . . . . . . . . . . . . (2,562) 4,814 1,847 Other, net . . . . . . . . . . . . . . 4,259 1,091 (470) 39,847 44,508 35,692 Cash flows provided from (used for) investing activities: Neil Simpson Unit #2 construction costs, excluding allowance for other funds used during construction (Note 7) . . (12,675) (2,227) - Other property additions, excluding allowance for other funds used during construction . . . . . . . . . (27,282) (25,594) (25,587) Short-term investments purchased . . . (33,622) (33,938) (14,771) Short-term investments sold . . . . . . .25,504 32,610 - Proceeds from sale of long-term investments . . . . . . . . . . . . . 14,724 - - (33,351) (29,149) (40,358) Cash flows provided from (used for) financing activities: Dividends paid . . . . . . . . . . . . (17,720) (16,977) (16,045) Common stock issued . . . . . . . . . . 13,705 534 - Net short-term borrowings . . . . . . . 3,784 900 (500) Long-term debt issued . . . . . . . . . - - 8,768 Long-term debt retired . . . . . . . . (4,166) (3,725) (1,921) (4,397) (19,268) (9,698) Increase (decrease) in cash and cash equivalents. . . . . . . . . . 2,099 (3,909) (14,364) Cash and cash equivalents: Beginning of year . . . . . . . . . . . 5,767 9,676 24,040 End of year . . . . . . . . . . . . . .$ 7,866 $ 5,767 $ 9,676 Supplemental disclosure of cash flow information: Cash paid during the period for - Interest . . . . . . . . . . . . . .$ 9,283 $ 9,296 $ 6,837 Income taxes. . . . . . . . . . . . .$ 8,000 $ 7,440 $ 8,700 Non-cash investing and financing activities (Notes 3 and 6) The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
December 31 1993 1992 (in thousands) ASSETS Current assets: Cash and cash equivalents . . . . .$ 7,866 $ 5,767 Short-term investments . . . . . . . 24,217 16,099 Receivables, net Customers . . . . . . . . . . . . 12,415 10,246 Other . . . . . . . . . . . . . . 901 1,807 Materials, supplies, and fuel. . . . 6,765 6,448 Prepaid expenses . . . . . . . . . . 1,638 1,662 Total current assets . . . . . 53,802 42,029 Property and investments: Electric . . . . . . . . . . . . . . 341,852 318,270 Coal mining. . . . . . . . . . . . . 51,670 44,483 Oil and gas production . . . . . . . 32,371 28,465 Investments . . . . . . . . . . . . 7,250 21,974 433,143 413,192 Less accumulated depreciation and depletion. . . . . . . . . . .(144,492) (132,890) Net property and investments. . 288,651 280,302 Deferred charges: Federal income taxes . . . . . . . . 7,271 2,153 Other . . . . . . . . . . . . . . . 3,129 5,718 10,400 7,871 $352,853 $330,202 LIABILITIES AND CAPITALIZATION Current liabilities: Current maturities of long-term debt. . . . . . . . . . .$ 3,542 $ 4,166 Notes payable (Note 4) . . . . . . . 11,768 7,984 Accounts payable . . . . . . . . . . 9,535 8,939 Accrued liabilities- Taxes. . . . . . . . . . . . . . . 5,583 5,544 Fuel and purchased power refunds 1,375 4,120 Interest . . . . . . . . . . . . . 1,700 2,167 Other. . . . . . . . . . . . . . . 6,023 6,008 Total current liabilities . . . 39,526 38,928 Deferred credits: Federal income taxes . . . . . . . . 36,705 37,687 Investment tax credits . . . . . . . 6,027 6,532 Reclamation costs. . . . . . . . . . 7,290 6,651 Regulatory liability . . . . . . . . 6,912 - Other. . . . . . . . . . . . . . . . 3,030 2,430 Total deferred credits. . . . . 59,964 53,300 Commitments and contingent liabilities (Notes 7 and 8). . . . . . . . . . . Capitalization, per accompanying statements: Common stock equity. . . . . . . . . 168,089 149,158 Long-term debt . . . . . . . . . . . 85,274 88,816 Total capitalization. . . . . . 253,363 237,974 $352,853 $330,202 The accompanying notes to consolidated financial statements are an integral part of these consolidated balance sheets.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 1993 1992 (in thousands) Common stock equity (Note 2): Common stock, $1 par value; 50,000,000 shares authorized; 14,269,580 and 13,701,287 shares outstanding, respectively . . . . . . . . . . . . . .$ 14,270 $ 13,701 Additional paid-in capital . . . . . . . . 43,420 30,284 Retained earnings . . . . . . . . . . . . . 110,399 105,173 Total common stock equity . . . . . . 168,089 149,158 Cumulative preferred stock: No par value; 400,000 shares authorized; no shares outstanding . . . . . . . . . . - - $100 par value; 270,000 shares authorized; no shares outstanding . . . . - - Long-term debt (Note 3): First mortgage bonds- 4.75% due 1993. . . . . . . . . . . . . . - 854 8.375% due 1998 . . . . . . . . . . . . . 3,340 4,005 8.05% due 1999. . . . . . . . . . . . . . 4,875 4,900 6.625% and 6.85% pollution control and industrial development revenue bonds, collateralized with first mortgage bonds, due 2007 . . . . . . . 1,840 2,000 9.00% due 2003. . . . . . . . . . . . . . 11,739 12,818 9.49% due 2018. . . . . . . . . . . . . . 6,000 6,000 9.35% due 2021 . . . . . . . . . . . . . 35,000 35,000 62,794 65,577 Other- 6.7% pollution control revenue bonds, due 2010. . . . . . . . . . . . . . . . 12,300 12,300 10.50% pollution control revenue bonds, due 2014 . . . . . . . . . . . . 12,200 12,200 Other long-term obligations . . . . . . . 1,522 2,905 26,022 27,405 Total long-term debt 88,816 92,982 Current maturities . . . . . . . . . . . . (3,542) (4,166) Net long-term debt . . . . . . . . . . 85,274 88,816 Total capitalization . . . . . . . . .$253,363 $237,974 The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1993, 1992, AND 1991 (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BUSINESS DESCRIPTION Black Hills Corporation and its Subsidiaries (the Company) operate in three primary business segments: electric, coal mining, and oil and gas production. The Company's electric utility operation is engaged in the generation, purchase, transmission, distribution, and sale of electric power and energy in western South Dakota, northeastern Wyoming, and southeastern Montana. Sales of electric power to the three largest electric customers represented 20% of the Company's electric revenue in 1993, 22% in 1992, and 21% in 1991. The coal mining operation of the Company, located in northeastern Wyoming, mines and sells sub-bituminous coal primarily under long-term coal supply agreements. As described in Note 6, a substantial portion of the coal mining operation's sales are to the Wyodak Plant. Sales of coal to the Company and to PacifiCorp represent 89% of total coal sales. The Company's oil and gas exploration and production business operates and has working interests in oil wells principally located in the Rocky Mountain region and Texas. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of Black Hills Corporation and its wholly owned subsidiaries. All significant inter- company balances and transactions have been eliminated in consolidation except for revenues and expenses associated with intercompany coal sales in accordance with the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." Total intercompany coal sales not eliminated were $10,047,000, $9,811,000, and $9,220,000 in 1993, 1992, and 1991, respectively. PROPERTY AND INVESTMENTS Property is recorded at cost which includes an allowance for funds used during construction where applicable. The cost of electric property retired, together with removal cost less salvage, is charged to accumulated depreciation. Repairs and maintenance of property are charged to operations as incurred. Investments, consisting principally of tax exempt municipal bonds held for corporate development purposes, are carried at cost which approximates market. DEPRECIATION AND DEPLETION Depreciation is computed using the straight-line method over the estimated useful lives of the related assets. Depreciation provisions for the electric property were equivalent to annual composite rates of 3.2% in 1993 and 1992, and 3.3% in 1991. Composite depreciation rates for other property were 9.6%, 7.5%, and 8.2% in 1993, 1992, and 1991, respectively. Depletion of coal and oil and gas properties is computed using the cost method for financial reporting and the gross income method or cost method, whichever is applicable, for federal income tax reporting. CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS Cash of the Company is invested in money market investments such as municipal put bonds, money market preferreds, commercial paper, Euro-dollars, and certificates of deposit. The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash equivalents and short-term investments are stated at cost which approximates market. REVENUE RECOGNITION Revenue from sales of electric energy is based on rates filed with applicable regulatory authorities. Electric revenue includes an accrual for estimated unbilled revenue for services provided through year-end. Revenue from other business segments is recognized at the time the products are delivered or the services are rendered. OIL AND GAS EXPLORATION The Company accounts for its oil and gas exploration activities under the full cost method. Capitalized costs associated with unsuccessful wells are amortized over future periods as the reserves from successful wells are produced. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION Allowance for funds used during construction (AFDC) represents the approximate composite cost of borrowed funds and a return on capital used to finance construction expenditures and is capitalized as a component of the electric property. The AFDC was computed at an annual composite rate of 7.7% in 1993, 10.5% in 1992, and 12% in 1991. INCOME TAXES Deferred taxes are provided on all significant temporary differences, principally depreciation. 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. (2) CAPITAL STOCK Common Stock Common shares issued at $1.00 par value during the years indicated were:
1993 1992 Public offering 525,000 - Employee Stock Purchase Plan 16,402 24,332 Dividend Reinvestment and Stock Purchase Plan 26,891 - 568,293 24,332
There were no shares issued in 1991. At December 31, 1993, 74,209 shares of unissued common stock were available for future offerings under the Employee Stock Purchase Plan. During 1993, the Board of Directors adopted a new Dividend Reinvestment and Stock Purchase Plan, under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. At December 31, 1993, 973,109 shares of unissued common stock were available for future offerings under the Plan. On January 30, 1992, the Board of Directors declared a three-for-two common stock split in the form of a 50% stock dividend, payable March 2, 1992, to shareholders of record on February 10, 1992. The common stock and per share information in the accompanying consolidated financial statements and notes have been restated to reflect the stock distribution. ADDITIONAL PAID-IN CAPITAL Changes in additional paid-in capital for the years indicated were:
1993 1992 1991 (in thousands) Balance, beginning of year $30,284 $29,776 $34,336 Premium, net of expenses, received from sales of common stock 13,136 508 - Three-for-two stock split - - (4,560) Balance, end of year $43,420 $30,284 $29,776
(3) LONG-TERM DEBT 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. In 1992, the Company issued $12,300,000, 6.7% Unsecured Pollution Control Refunding Revenue Bonds, due 2010. The proceeds were used to redeem $12,300,000 of 6.625% and 6.85%, Pollution Control Revenue Bonds, due 2007. The Company entered into a refunding agreement in 1992 to refund the existing $12,200,000, 10.5% Pollution Control Revenue Bonds in 1994 with 7.5% Pollution Control Revenue Bonds. The refunding agreement obligates the Company to call and satisfy in full the existing bonds in 1994, including a redemption premium of 2% or $240,000 on the existing bonds. Because of the forward nature of this transaction, the refunding will not be reflected in the Company's consolidated financial statements or capital structure until 1994. In 1991 the Company issued two series of first mortgage bonds, $35,000,000 at 9.35% due 2021 and $13,806,000 at 9.00% due 2003. The funds were primarily used for the purchase of the Wyodak Plant as described in Note 6. Scheduled maturities of long-term debt for the next five years are: $3,542,000 in 1994, $2,144,000 in 1995, $2,255,000 in 1996, $2,384,000 in 1997, and $2,196,000 in 1998. (4) NOTES PAYABLE TO BANKS At December 31, 1993, the Company had $40,000,000 of unsecured short-term lines of credit. Borrowings outstanding under these lines of credit were $11,700,000 and $6,000,000 as of December 31, 1993 and 1992, respectively. Average borrowings during 1993, 1992, and 1991 were $11,059,000, $5,616,000, and $4,552,000, respectively. The average interest rate on these borrowings was 5.2%, 6.0%, and 8.3% in 1993, 1992, and 1991, respectively. The Company has no compensating balance requirements associated with these lines of credit. The Company pays a 0.125% facility fee on $10,000,000 of the existing lines. The lines of credit are subject to periodic review and renewal during the year by the banks. (5) FAIR VALUE OF FINANCIAL INSTRUMENTS 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 those instruments. Short-Term and Other Investments The fair value of the Company's short-term and other investments equals the quoted market price, if available. If a quoted market price is not available, fair value is estimated using quoted market prices for similar securities. 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, with an exception for debt associated with the federal coal lease modifications. The fair value of the bonus payments for the federal coal lease modifications equals the discounted future cash flows using the prime rate as the discount rate. The final federal bonus payment is due February 1, 1994. The estimated fair values of the Company's financial instruments are as follows:
1993 (in thousands) Carrying Fair Amount Value Cash and cash equivalents $ 7,866 $ 7,866 Short-term investments 24,217 24,217 Other investments 7,250 7,257 Long-term debt 88,816 105,639
1992 (in thousands) Carrying Fair Amount Value Cash and cash equivalents $ 5,767 $ 5,767 Short-term investments 16,099 16,177 Other investments 21,974 22,023 Long-term debt 92,982 101,885
The majority of the Company's outstanding bonds are currently subject to make-whole provisions which would eliminate any economic benefits for the Company to call and refinance the bonds. (6) WYODAK PLANT On April 8, 1991, the Company purchased a 20% interest and PacifiCorp an 80% interest in the Wyodak Plant (the Plant), a 330 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. The total acquisition cost of the Company's 20% interest was approximately $42,022,000. The Company financed its 20% interest through the issuance of first mortgage bonds. The Company and PacifiCorp had leased the Plant since 1978 under a leveraged lease agreement. The lease was recorded by the Company as a capital asset with corresponding debt at the present value of the lease payments. Non-cash investing and financing activities associated with the acquisition were as follows: Acquisition of interest in Wyodak Plant through debt issuance and assumption $42,022,000 Elimination of capital lease asset and obligation relating to the Wyodak Plant 30,694,000 The Company received a rate order from the South Dakota Public Utilities Commission that allows the capitalization of the full cost of the Plant for rate making purposes in South Dakota. Electric sales to South Dakota customers represent approximately 82% of total electric sales. The Company receives 20% of the Plant's capacity and is committed to pay 20% of its additions, replacements, and operating and maintenance expenses. As of December 31, 1993, the Company's investment in the Plant included $71,207,000 in electric plant and $18,844,000 in accumulated depreciation. The Company's share of direct expenses of the Plant is included in the corresponding categories of operating expenses in the accompanying consolidated statements of income. Wyodak Resources Development Corp. (WRDC) supplies coal to the Plant under an agreement expiring in 2013 with a 10 year renewal option. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC's coal reserves. At December 31, 1993, approximately 32,250,000 tons were covered under this agreement. WRDC's sales to the Plant were $21,438,000, $20,317,000, and $17,775,000 for the years ended December 31, 1993, 1992, and 1991, respectively. (7) COMMITMENTS AND CONTINGENT LIABILITIES NEW POWER PLANT Construction of Neil Simpson Unit #2 (NSS #2), an 80 MW coal fired generating plant located adjacent to the Wyodak coal mine, commenced in August 1993. The Company has committed to the South Dakota Public Utilities Commission and the Wyoming Public Service Commission to construct NSS #2 at a capital cost not to exceed $124,889,000 including AFDC and to not include in rate base any capital costs in excess thereof. The construction of the plant is scheduled to be completed by the end of 1995. The Company has incurred approximately $15,000,000 of costs related to the plant as of December 31, 1993. WRDC has committed to supply all of the coal requirements for the life of the plant. The coal pricing methodology would restrict WRDC's earnings on all coal sales to the Company to a return on its investment base. WRDC has committed to further reduce the price for coal to be used in any of the Company's power plants during a period of time that under prudent dispatch that power plant would not have been operated if it were not for the discounted price of coal. COAL OBLIGATIONS In addition to the 32,250,000 tons of coal reserved under the agreement with the Wyodak Plant, WRDC has reserved 30,000,000 tons of coal under existing contracts and 52,000,000 tons of coal under future purchase options. None of the purchase options are expected to be exercised because the option price is substantially higher than the market price. An option for 50,000,000 tons can be exercised only if WRDC has not committed the coal reserves to other buyers prior to the exercise of the option. POWER PURCHASE AGREEMENT In 1983, the Company entered into a 40 year power agreement with PacifiCorp providing for the purchase of 75 megawatts of electric capacity and energy. Although the price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants, the power can come from anywhere in PacifiCorp's system. Costs incurred under this agreement were $21,106,000, $21,507,000, and $22,280,000 in 1993, 1992, and 1991, respectively. RECLAMATION Under its mining permit, WRDC 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 $650,000 is charged to operations as reclamation expense annually. As of December 31, 1993, accrued reclamation costs were approximately $7,290,000. OTHER The Company is subject to various legal proceedings and claims which arise in the ordinary course of operations and in the sales of formerly owned companies. 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. (8) EMPLOYEE BENEFIT PLANS The Company has a defined benefit pension plan (the Plan) covering substantially all employees. 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 consist primarily of equity and debt securities and cash equivalents. Net pension expense (income) for the Plan was as follows:
1993 1992 1991 (in thousands) Service cost $ 651 $ 535 $ 499 Interest cost 1,899 1,687 1,510 Return on assets: Actual (2,852) (2,224) (5,210) Deferred 333 (215) 3,203 Net pension expense (income) $ 31 $ (217) $ 2
Funding information for the Plan as of October 1 of each year was as follows:
1993 1992 (in thousands) Fair value of plan assets $25,186 $23,602 Projected benefit obligation 28,367 22,969 (3,181) 633 Unrecognized: Net loss (gain) 3,779 (13) Prior service cost 1,105 1,204 Transition asset (631) (721) Prepaid pension cost $ 1,072 $ 1,103 Accumulated benefit obligation $22,464 $18,885 Vested benefit obligation $21,507 $18,123 Actuarial assumptions: Discount rate 7.5% 8.5% Expected long-term rate of return on assets 11% 11% Rate of increase in compensation levels 5% 5%
The change in the assumed discount rate from 8.5% in 1992 to 7.5% in 1993 resulted in an increase in the accumulated benefit obligation and projected benefit obligation of $2,260,000 and $3,403,000, respectively. The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. Costs incurred under the plans were $633,000, $735,000, and $570,000 in 1993, 1992, and 1991, respectively. On January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The new standard requires that the expected cost of these benefits must be charged to expense during the years that the employees render service. Prior to adopting the standard the Company expensed these benefits as they were paid. The Company is amortizing the transition obligation of $2,996,000 over a 20 year period. Employees retiring from the Company on or after attaining age 55 who have rendered 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 for the Company was as follows:
1993 (in thousands) Service cost $127 Interest cost 250 Amortization of transition obligation 150 Net periodic postretirement benefit cost $527
Funding information as of October 1 was as follows:
1993 (in thousands) Accumulated postretirement benefit obligation: Retirees $1,316 Fully eligible active participants 865 Other active participants 1,921 Unfunded accumulated postretirement benefit obligation 4,102 Unrecognized net loss (892) Unrecognized transition obligation (2,846) Accrued postretirement benefit cost $ 364
For measurement purposes, an 11.5% annual rate of increase in healthcare benefits was assumed for 1994; the rate was assumed to decrease gradually to 6% in 2005 and remain at that level thereafter. The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1% increase in the healthcare cost trend assumption would increase the net periodic postretirement cost by approximately $140,000 annually or 20.8%. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7.5%. (9) INCOME TAXES Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, which requires the use of 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 reporting 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 implement the statement, certain adjustments were made to accumulated deferred income taxes. 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. Initial application of the statement had no material impact on the Company's results of operations. Income tax expense for the years indicated was:
1993 1992 1991 (in thousands) Current $7,923 $7,745 $9,350 Deferred 1,547 1,273 (289) Investment tax credits, net (505) (512) (512) $8,965 $8,506 $8,549
The sources of temporary differences and the tax effect of each are summarized as follows:
1993 1992 1991 (in thousands) Tax in excess of book depreciation $ 662 $ 566 $ 257 Inventory accounting method (184) (179) (308) Mining development and oil exploration costs 1,315 848 61 Other (246) 38 (299) $1,547 $1,273 $ (289)
The temporary differences which gave rise to the net deferred tax liability at December 31, 1993 were as follows:
Net Deferred Income Tax Asset Assets Liabilities (Liability) (in thousands) Accelerated depreciation and other plant-related differences $ - $32,507 $(32,507) AFUDC-equity - 461 (461) Regulatory asset 2,350 - 2,350 Unamortized investment tax credits 2,109 - 2,109 Mining development and oil exploration 746 2,383 (1,637) Employee benefits 1,227 455 772 Other 839 899 (60) $7,271 $36,705 $(29,434)
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
1993 1992 1991 Federal statutory rate 35.0% 34.0% 34.0% Percentage depletion in excess of cost (2.8) (2.3) (2.3) Amortization of investment tax credits (1.6) (1.5) (1.6) Tax exempt interest income (1.7) (2.3) (2.8) Other (0.8) (1.4) 0.1 28.1% 26.5% 27.4%
(10) OIL AND GAS RESERVES (Unaudited) The following table summarizes Western Production Company's (WPC) estimated quantities of proved developed and undeveloped oil and natural gas reserves at December 31, 1993 and 1992, and a reconciliation of the changes between these dates using constant product prices for the respective years. These estimates are based on reserve reports by 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.
1993 1992 Oil Gas Oil Gas (in thousands of barrels of oil and MCF of gas) Proved developed and undeveloped reserves: Balance at beginning of year 2,199 3,243 2,524 4,799 Production (327) (777) (247) (379) Additions 259 1,847 193 272 Revisions to previous estimates due to changed economic conditions (1,015) (1,554) (271) (1,449) Balance at end of year 1,116 2,759 2,199 3,243 Proved developed reserves at end of year included above 1,116 2,759 1,630 2,633 Year end prices $13.00 $ 2.35 $18.75 $ 1.65
WPC has interests in 386 oil and gas properties in seven states. WPC operates a total of 347 wells in Wyoming, Colorado, and South Dakota. WPC's non-operated properties are located in Wyoming, Colorado, North Dakota, Montana, Kansas, and Texas. WPC also holds leases on approximately 74,000 gross and 50,000 net undeveloped acres. (11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS The three primary segments of the Company's business are its electric, coal mining, and oil and gas production operations. The following table summarizes certain information specifically identifiable with each segment as of or for the years ended December 31.
1993 1992 1991 (in thousands) Assets at year end: Electric $259,680 $238,378 $228,788 Coal mining 72,328 71,194 71,873 Oil and gas 20,845 20,630 19,234 $352,853 $330,202 $319,895 Depreciation, depletion, and amortization: Electric $ 9,952 $ 9,614 $ 8,644 Coal mining 1,953 1,482 1,572 Oil and gas 4,146 2,764 1,796 $ 16,051 $ 13,860 $ 12,012 Capital expenditures: NSS #2 (includes AFDC) $12,792 $ 2,227 $ - Other electric 13,140 15,507 29,865* Coal mining 7,425 5,001 1,129 Oil and gas 6,933 5,180 5,987 $ 40,290 $ 27,915 $ 36,981 * Includes the acquisition of the Wyodak Plant (See Note 6).
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION PACIFICORP COAL SETTLEMENT In 1987, WRDC entered into an agreement with PacifiCorp which (a) settled PacifiCorp's obligation to purchase coal commencing in 1990 for a second plant to be located at Wyodak, the construction of which had been canceled, (b) provided for, among other things, increases in the coal price and minimum coal purchase obligations by PacifiCorp for the Wyodak Plant, and (c) provided for payments to WRDC of $2,000,000 each on January 2, 1988 through 1991 for an option to purchase additional coal. These settlements resulted in an increase in the Company's net income in 1993, 1992, and 1991 of approximately $1,500,000, $2,800,000, and $2,600,000 or $0.11, $0.20, and $0.19 per share of common stock, respectively. OTHER COAL SETTLEMENTS In late 1987, WRDC agreed to the termination of a long-term coal supply agreement with the city of Grand Island, Nebraska. Grand Island was granted a 14 year option to purchase coal and in return WRDC will receive payments of approximately $155,000 each year. TAXES OTHER THAN INCOME TAXES
1993 1992 1991 (in thousands) Property $ 3,549 $2,996 $2,366 Production and severance 2,982 2,622 2,820 Payroll 1,195 1,225 1,164 Black lung 1,256 1,191 1,099 Federal reclamation 1,060 1,035 960 Other 167 195 170 $10,209 $9,264 $8,579
COMPONENTS OF OTHER INCOME (EXPENSE):
1993 1992 1991 (in thousands) Coal settlements PacifiCorp $ - $ 940 $ 802 Grand Island 155 155 125 Other 319 138 (296) $ 474 $1,233 $ 631
(13) QUARTERLY FINANCIAL DATA (UNAUDITED) Quarterly financial data for the years indicated are summarized as follows:
First Second Third Fourth (in thousands, except per share amounts) YEAR ENDED DECEMBER 31, 1993 Operating revenues $34,375 $32,924 $36,304 $35,770 Operating income 9,980 7,793 10,087 9,926 Net income 6,103 4,575 6,011 6,257 Earnings per share of common stock 0.45 0.33 0.44 0.44 Common stock prices High $28-1/4 $27-1/4 $27-1/8 $26-1/8 Low $24-7/8 $24-5/8 $25-1/8 $21-7/8 Dividends paid per share of common stock $ 0.32 $ 0.32 $ 0.32 $ 0.32 YEAR ENDED DECEMBER 31, 1992 Operating revenues $32,463 $32,175 $35,359 $35,346 Operating income 8,826 7,608 10,050 9,865 Net income 5,588 5,581 6,276 6,193 Earnings per share of common stock 0.41 0.41 0.46 0.45 Common stock prices High $29-1/2 $32-1/4 $29-5/8 $29-1/4 Low $25-3/8 $25-1/2 $27-1/2 $23-3/4 Dividends paid per share of common stock $ 0.31 $ 0.31 $ 0.31 $ 0.31
SELECTED FINANCIAL DATA (unaudited)
Years ended December 31 1993 1992 1991 1990 1989 (in thousands, except per share amounts) Operating revenues $139,373 $135,343 $133,373 $127,498 $120,004 Net income from continuing operations 22,946 23,638 22,681 22,938 21,957 Per share of common stock: Earnings from continuing operations 1.66 1.73 1.66 1.68 1.60 Dividends paid 1.28 1.24 1.17 1.09 1.01 Total assets 352,853 330,202 319,895 294,929 272,523 Total long-term obligations 85,274 88,816 92,982 78,978 78,939
FINANCIAL STATISTICS
Years ended December 31 1993 1992 1991 TOTAL ASSETS (in thousands) $352,853 $330,202 $319,895 PROPERTY AND INVESTMENTS (in thousands) Total property and investments . . .$433,143 $413,192 $390,766 Accumulated depreciation and depletion. . . . . . . . . . . . 144,492 132,890 122,574 Capital expenditures (includes AFDC) . . . . . . . . . . 40,290 27,915 36,981 CAPITALIZATION (in thousands) Long-term debt . . . . . . . . . . .$ 85,274 $ 88,816 $ 92,982 Common stock equity . . . . . . . . . 168,089 149,158 141,963 Total . . . . . . . . . . . . .$253,363 $237,974 $234,945 CAPITALIZATION RATIOS Long-term debt . . . . . . . . . . . 33.7% 37.3% 39.6% Common stock equity . . . . . . . . . 66.3 62.7 60.4 Total . . . . . . . . . . . . . . 100.0% 100.0% 100.0% AVERAGE INTEREST RATE ON LONG-TERM DEBT 9.0% 8.9% 8.9% NET INCOME AVAILABLE FOR COMMON STOCK (in thousands) . . . . $ 22,946 $ 23,638 $ 22,681 DIVIDENDS PAID ON COMMON STOCK (in thousands) . . . . . . . . . . . $ 17,720 $ 16,977 $ 16,045 COMMON STOCK DATA (in thousands)* Shares outstanding, average. . . . . . 13,811 13,689 13,675 Shares outstanding, end of year. . . . 14,270 13,701 13,675 Earnings per average share, in dollars. . . . . . . . . . . . . $ 1.66 $ 1.73 $ 1.66 Dividends paid per share, in dollars $ 1.28 $ 1.24 $ 1.17 Book value per share, end of year, in dollars. . . . . . . . . . $ 11.78 $ 10.89 $ 10.38 RETURN ON COMMON STOCK EQUITY. . . . . 13.7% 15.8% 16.0% ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION AS PERCENT OF NET INCOME. . . . . . . . . . . . . . . . 3.2% 1.6% 0.8% (continued) Years ended December 31 1990 1989 1988 TOTAL ASSETS (in thousands) $294,929 $272,523 $270,258 PROPERTY AND INVESTMENTS (in thousands) Total property and investments. . . .$355,276 $331,310 $304,445 Accumulated depreciation and depletion. . . . . . . . . . . . 111,111 101,591 92,661 Capital expenditures (includes AFDC) . . . . . . . . . . 22,336 10,176 12,950 CAPITALIZATION (in thousands) Long-term debt . . . . . . . . . . .$ 78,978 $ 78,939 $ 82,709 Common stock equity . . . . . . . . . 135,329 127,338 120,100 Total . . . . . . . . . . . . .$214,307 $206,277 $202,809 CAPITALIZATION RATIOS Long-term debt . . . . . . . . . . . 36.9% 38.3% 40.8% Common stock equity . . . . . . . . . 63.1 61.7 59.2 Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% AVERAGE INTEREST RATE ON LONG-TERM DEBT 8.6% 8.5% 8.5% NET INCOME AVAILABLE FOR COMMON STOCK (in thousands) . . . . $ 22,938 $ 21,096 $ 22,191 DIVIDENDS PAID ON COMMON STOCK (in thousands) . . . . . . . . . . . $ 14,947 $ 13,858 $ 12,756 COMMON STOCK DATA (in thousands)* Shares outstanding, average. . . . . . 13,675 13,675 13,665 Shares outstanding, end of year. . . . 13,675 13,675 13,675 Earnings per average share, in dollars. . . . . . . . . . . . . $ 1.68 $ 1.54 $ 1.62 Dividends paid per share, in dollars.$ 1.09 $ 1.01 $ 0.93 Book value per share, end of year, in dollars . . . . . . . . . $ 9.90 $ 9.31 $ 8.78 RETURN ON COMMON STOCK EQUITY . . . . 16.9% 16.6% 18.5% ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION AS PERCENT OF NET INCOME . . . . . . . . . . . . 1.2% 0.5% 0.7% * Common stock data have been adjusted retroactively to reflect the three- for-two stock split in March 1992.
ELECTRIC OPERATION STATISTICS
Years ended December 31 1993 1992 1991 ELECTRIC ENERGY GENERATED AND PURCHASED (megawatt hours) Generated, net station output . . . 1,227,084 1,226,153 1,148,259 Purchased and net interchange . . . 435,990 397,478 444,848 Total generated and purchased . 1,663,074 1,623,631 1,593,107 Non-firm sales . . . . . . . . . . . (7,780) (10,405) (1,040) Company use and losses . . . . . . . (61,336) (73,627) (59,896) Total electric energy sales . . 1,593,958 1,539,599 1,532,171 ELECTRIC ENERGY SALES (megawatt hours) Residential . . . . . . . . . . . . 370,736 339,341 355,691 General and commercial . . . . . . . 469,496 446,036 440,043 Industrial . . . . . . . . . . . . . 568,316 572,244 550,999 Public authorities . . . . . . . . . 22,621 21,798 21,347 Sales for resale . . . . . . . . . . 162,789 160,180 164,091 Total electric energy sales . . 1,593,958 1,539,599 1,532,171 ELECTRIC REVENUE (in thousands) Residential . . . . . . . . . . . . $ 27,064 $ 25,366 $ 27,053 General and commercial . . . . . . . 32,295 30,742 31,227 Industrial . . . . . . . . . . . . . 25,901 27,106 26,812 Public authorities . . . . . . . . . 1,537 1,586 1,593 Sales for resale . . . . . . . . . . 7,122 7,002 7,223 Total electric revenue . . . . 93,919 91,802 93,908 Other revenue. . . . . . . . . . . . 4,236 5,646 4,250 Total revenue $ 98,155 $ 97,448 $ 98,158 ELECTRIC CUSTOMERS (end of year) Residential . . . . . . . . . . . . 44,657 44,100 43,539 General and commercial . . . . . . . 8,507 8,279 8,083 Industrial . . . . . . . . . . . . . 41 38 40 Public authorities . . . . . . . . . 124 117 112 Other electric utilities . . . . . . 1 1 1 Total . . . . . . . . . . . . . 53,330 52,535 51,775 RESIDENTIAL STATISTICS Average annual KWH usage: With electric heating. . . . . . . 17,601 15,380 16,773 Without electric heating . . . . . 6,428 6,172 6,502 All residential. . . . . . . . . . 8,351 7,743 8,218 Average price per KWH, in cents . . 7.2 7.6 7.6 AVERAGE PRICE PER KWH, ALL CUSTOMERS (in cents) . . . . . . . . . . . . . . 6.0 6.2 6.1 (continued) Years ended December 31 1990 1989 1988 ELECTRIC ENERGY GENERATED AND PURCHASED (megawatt hours) Generated, net station output . . . 1,169,054 1,046,971 1,119,073 Purchased and net interchange . . . 379,268 468,768 388,394 Total generated and purchased . 1,548,322 1,515,739 1,507,467 Non-firm sales . . . . . . . . . . . (5,576) (29,087) (45,943) Company use and losses . . . . . . . (64,031) (53,282) (56,869) Total electric energy sales . . 1,478,715 1,433,370 1,404,655 ELECTRIC ENERGY SALES (megawatt hours) Residential . . . . . . . . . . . . 338,391 343,645 337,375 General and commercial . . . . . . . 415,635 395,712 396,366 Industrial . . . . . . . . . . . . . 542,312 529,703 509,036 Public authorities . . . . . . . . . 20,819 20,980 24,574 Sales for resale . . . . . . . . . . 161,558 143,330 137,304 Total electric energy sales . . 1,478,715 1,433,370 1,404,655 ELECTRIC REVENUE (in thousands) Residential . . . . . . . . . . . . $ 25,498 $ 25,456 $ 24,768 General and commercial . . . . . . . 29,027 27,815 26,884 Industrial . . . . . . . . . . . . . 25,917 25,153 23,359 Public authorities . . . . . . . . . 1,540 1,563 1,656 Sales for resale . . . . . . . . . . 6,532 5,745 5,740 Total electric revenue . . . . 88,514 85,732 82,407 Other revenue . . . . . . . 3,762 4,650 3,838 Total revenue $ 92,276 $ 90,382 $ 86,245 ELECTRIC CUSTOMERS (end of year) Residential . . . . . . . . . . . . 43,020 42,505 41,880 General and commercial . . . . . . . 7,866 7,703 7,512 Industrial . . . . . . . . . . . . . 44 40 37 Public authorities . . . . . . . . . 114 111 105 Other electric utilities . . . . . . 1 1 1 Total . . . . . . . . . . . . . 51,045 50,360 49,535 RESIDENTIAL STATISTICS Average annual KWH usage: With electric heating. . . . . . . 15,978 16,881 16,218 Without electric heating . . . . . 6,288 6,421 6,461 All residential. . . . . . . . . . 7,897 8,171 8,056 Average price per KWH, in cents . . 7.5 7.4 7.3 AVERAGE PRICE PER KWH, ALL CUSTOMERS (in cents) . . . . . . . . . . . . . . 6.0 6.0 5.9
DIRECTORY COMMON STOCK Transfer Agent, Registrar, and Dividend Disbursing Agent Chemical Bank 450 West 33rd Street New York, New York 10001 FIRST MORTGAGE BONDS Trustee and Paying Agent Chemical Bank 450 West 33rd Street New York, New York 10001 POLLUTION CONTROL AND INDUSTRIAL DEVELOPMENT REVENUE BONDS Trustee and Paying Agent Norwest Bank Minnesota, N.A. Eighth Street and Marquette Avenue Minneapolis, Minnesota 55479 GENERAL COUNSEL Morrill Brown & Thomas P.O. Box 8108 Rapid City, South Dakota 57709 CORPORATE OFFICES Black Hills Corporation P.O. Box 1400 Rapid City, South Dakota 57709 (605) 348-1700 The Company's common stock ($1 par value) is traded on The New York Stock Exchange. Quotations for the common stock are reported under the symbol BKH. At year-end the Company had 7,243 common stockholders of record. All fifty states and the District of Columbia plus twelve foreign countries are represented. The continued interest and support of equity owners is appreciated. The Company has declared common stock dividends payable in cash in each year since its incorporation in 1941. At its January 1994 meeting, the Board of Directors raised the quarterly dividend to 33 cents per share, equivalent to an annual increase of 4 cents per share. This regular quarterly dividend is payable March 1, 1994. All dividends are reportable for federal income tax purposes as ordinary dividend income. The Annual Report is mailed to each shareholder in accordance with government rules. Dividend payments and interim reports of the Company are mailed quarterly. Dividend payment dates are March 1, June 1, September 1, and December 1. You may receive more than one copy of the Annual Report if there are variations in your name or address in which your stock is registered. Duplicate mailings of annual and interim reports can be eliminated upon written request of the shareholder. A copy of the Company's Annual Report on Form 10-K, filed with the Securities and Exchange Commission, is available to shareholders without charge upon written request to Roxann R. Basham, Secretary, P.O. Box 1400, Rapid City, South Dakota 57709. 1994 ANNUAL MEETING The Annual Meeting of Stockholders will be held at the Holiday Inn - Rushmore Plaza Hotel, 505 North Fifth Street, Rapid City, South Dakota, at 9:30 A.M., on May 24, 1994. Prior to the meeting, formal notice, proxy statement, and proxy will be mailed to shareholders. DIRECT DEPOSIT OF DIVIDENDS The Company encourages you to consider the direct deposit of your dividends. With direct deposit, your quarterly dividend payment can be automatically transferred on the dividend payment date to the bank, savings and loan, or credit union of your choice. Direct deposit assures payments are credited to shareholders' accounts without delay. A form is attached to your dividend check where you can request information about this method of payment. Questions regarding direct deposit should be directed to Chemical Bank, Security Holder Relations, P. O. Box 24935, Church Street Station, New York, New York 10249. DIVIDEND REINVESTMENT PLAN A Dividend Reinvestment and Stock Purchase Plan (the Plan) is available to common shareholders. The Company revised its plan in November 1993. The new Plan provides a method of investing common stock dividends and optional cash payments in additional shares of common stock of the Company at 100 percent of the recent average market price. The participant may elect to continue to receive cash dividends on shares registered in their names and invest by making optional cash payments only. Questions regarding the Plan should be directed to the Secretary of the Company or Chemical Bank, Dividend Reinvestment Department, J.A.F. Building, P.O. Box 3069, New York, New York 10116-3069 or by calling the Bank toll free at 1-800-279-1246. EX-22 7 SUBSIDIARIES OF THE REGISTRANT Exhibit 22 BLACK HILLS CORPORATION SUBSIDIARY OF REGISTRANT Wyodak Resources Development Corp., a Delaware corporation. SUBSIDIARIES OF WYODAK RESOURCES DEVELOPMENT CORP. Landrica Development Company, a South Dakota corporation. Western Production Company, a Wyoming corporation. EX-23 8 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included or incorporated by reference in this Form 10-K, into the Company's previously filed Registration Statements, File Numbers 33-71130 and 33-15868. ARTHUR ANDERSEN & CO. Minneapolis, Minnesota March 14, 1994 -----END PRIVACY-ENHANCED MESSAGE-----