ITEM 1. BUSINESS
GENERAL
Incorporated under the laws of South Dakota in 1941, the Company is an energy company primarily consisting of four principal businesses: electric, coal mining, oil and gas production, and energy marketing. The Company's mission statement is to position the Company nationally to build value for shareholders, offer competitive prices for customers and create opportunities for employees through quality energy products and services. The Company operates its public utility electric operations under the assumed name of Black Hills Power and Light Company, its coal mining operations through its subsidiary Wyodak Resources, its oil and gas exploration and production operations through Western Production, and its energy marketing operations through Black Hills Capital Group.
Black Hills Power is engaged in the generation, purchase, transmission, distribution and sale of electric power and energy to approximately 56,300 customers in 11 counties in western South Dakota, northeastern Wyoming and southeastern Montana, an area with a population estimated at 165,000. The largest community served is Rapid City, South Dakota, a major retail, wholesale and health care center, with a population, including environs, estimated at 75,000. Agriculture, tourism, small stakes gambling, mining, lumbering, small item manufacturing, service and support businesses and government support through Ellsworth Air Force Base are the primary influences on the economic well-being of the region.
Wyodak Resources, incorporated under the laws of Delaware in 1956, is engaged in the mining and sale of low sulfur sub-bituminous coal and is located approximately five miles east of Gillette, Wyoming, in the Powder River Basin.
Acquired by Wyodak Resources in 1986, Western Production is an oil and gas exploration and production company with interests located in the Rocky Mountain region, Texas, California and various other locations.
Black Hills Capital Group, incorporated under the laws of South Dakota in 1997, holds the Company's investments in Black Hills Energy Resources, Inc. (formerly Wickford Energy Marketing, Inc.), VariFuel, Inc., and a 50% interest in Enserco Energy, Inc. The energy marketing companies noted above market natural gas, crude oil, electricity, and related energy services to customers in the East Coast, Midwest, Rocky Mountain and West Coast regions. In addition to the energy marketing companies, Black Hills Capital Group will be a primary vehicle for future corporate development activities.
Information as to the continuing lines of business of the Company for the calendar years 1995-1997 is as follows:
For additional information relating to the Company's operations by business line see Note 11 of "Notes to Consolidated Financial Statements".
ELECTRIC POWER SUPPLY
GENERAL
Black Hills Power has been able to meet the needs of its customers for electric power and energy through its owned generating capacity and by contract purchases. Black Hills Power's peak load of 346 megawatts was reached in July 1997. Approximately 45 megawatts of additional load commenced January 1, 1997, when Black Hills Power began providing wholesale electricity to MDU for its Sheridan, Wyoming electric service territory. (See ITEM 1. BUSINESS-ELECTRIC SERVICE TERRITORY AND SALES - Wholesale to MDU.) Black Hills Power estimates its required reserves at 82 megawatts. Black Hills Power is not presently a member of a power pool, but in 1997 Black Hills Power signed a Letter of Intent to join a new power pool, Rocky Mountain Reserve Group. Rocky Mountain Reserve Group's formation is pending approval by FERC. Upon joining the FERC-approved power pool, Black Hills Power's reserve requirement is estimated to be 22 megawatts.
Black Hills Power owns coal-fired generating units having a summer capability rating of 214 megawatts and 77 megawatts of oil-fired diesel and natural gas combustion turbines for peaking and standby use. Black Hills purchases additional resources under three contracts with Pacific Power: the Power Sales Agreement, under which it purchases 75 megawatts of baseload power declining to 50 megawatts from 2000 to 2004; the Reserve Capacity Integration Agreement, under which 33 megawatts of additional reserve capacity are available; and the Capacity Contract, under which Black Hills Power has options to be exercised seasonally to purchase up to 60 megawatts of capacity.
PACIFIC POWER'S POWER SALES AGREEMENT
Pacific Power's Power Sales Agreement obligates Black Hills Power to purchase from Pacific Power 75 megawatts of electric power plus energy at a load factor varying from a minimum of 41 percent to a maximum of 80 percent as scheduled by Black Hills Power. In October 1997, Black Hills Power entered into a second Restated and Amended Power Sales Agreement with Pacific Power. The Amended Agreement reduces the contract capacity by 25 megawatts (5 megawatts per year beginning in 2000). The contract terminates December 31, 2023. The power and energy delivered is power from Pacific Power's system and does not depend on any one unit, but the price is generally based on Pacific Power's costs in Units 3 and 4 of the Colstrip coal-fired generating plant near Colstrip, Montana. Black Hills Power contracts for transmission service from Pacific Power under Pacific Power's FERC approved transmission rates. The Company has incurred capacity charges of $15,800 per megawatt month and an average energy charge of $12.26 per megawatt hour over the last three years of this agreement with a 55 percent load factor. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
PACIFIC POWER'S RESERVE CAPACITY INTEGRATION AGREEMENT
This agreement obligates Pacific Power until the end of the contract in 2012 to make available to Black Hills Power 100 megawatts of reserve capacity to be acquired by Black Hills Power only at such time under prudent utility practice Black Hills Power would have operated its combustion turbines. In return, Pacific Power has the right to utilize Black Hills Power's four 25 megawatt combustion turbines (with a summer rating of 67 megawatts), but Black Hills Power has a prior right to use said turbines to support the transmission system. The price for any energy Black Hills Power acquires under this agreement is based upon the lower of Pacific Power's incremental costs of generation of its highest price coal-fired plant or the cost of fuel to operate the combustion turbines. Pacific Power also pays certain operating and maintenance expenses of the combustion turbines, together with a $50,000 payment per month for the remaining life of the contract.
PACIFIC POWER'S CAPACITY CONTRACT
On September 1, 1995, Black Hills Power and Pacific Power entered into the Pacific Power Capacity Contract. Under the contract, Pacific Power granted Black Hills Power an option to be exercised for each six-month season for a period commencing October 1, 1996 and ending March 31, 2007 to purchase up to 60 megawatts of peaking capacity at established prices. Black Hills Power may schedule the energy at a rate up to 100 percent per hour at a load factor up to 15 percent per season. Other than to give preference to purchasing peaking capacity from Pacific Power, Black Hills Power is under no obligation to exercise any of the six-month seasonal options.
In addition to granting Black Hills Power options to purchase peaking capacity, the Pacific Power Capacity Contract also obligates Black Hills Power to sell to Pacific Power until December 31, 2000, all surplus energy which is defined as the difference in Black Hills' Resources (all energy from Black Hills Power's generating resources and energy entitlement under Pacific Power's Power Sales Agreement) and Black Hills' Loads (non-end user contracts of five months or longer and all retail customers as they exist from time to time). The selling prices are based upon economy energy spot price indices determined daily in the western part of the United States with a sharing between Pacific Power and Black Hills Power of prices above certain levels. Black Hills Power is not obligated to sell any energy below its marginal production cost. The contract also provides Black Hills Power an option to store energy with Pacific Power and to take that energy back for the purpose of replacing energy from a forced or scheduled outage of NS #2 or Black Hills Power's share of the Wyodak Plant.
To the extent of the excess capacity and energy available to Black Hills Power from its generating resources and the Pacific Power purchased power contracts, Black Hills Power at this time has the flexibility to serve the expected growth of its loads in its service territory and as opportunities arise in the meantime, to increase sales of its energy and capacity.
ELECTRIC SERVICE TERRITORY AND SALES
RETAIL 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 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)
As evidenced by a 1 percent increase in customers in both 1997 and 1996, the economy in and around Black Hills Power's service territory is believed by management to be stable. Small businesses and regional plant expansions are continually being attracted to the region along with retirees who have discovered the Black Hills region with its scenery, recreational activities and medical services to be an attractive place to live. Management anticipates that the economy will continue to experience modest growth but can give no assurances as many economic factors will greatly influence any economy. Ellsworth Air Force Base, a B-1 bomber military base near Rapid City, survived the fourth round of base closures in 1995. In January 1998, Homestake Mining Company (Homestake), the Company's third largest customer at 5.6 percent of electric revenues, announced a reorganization and restructuring plan at its gold mine in Lead, South Dakota. It is anticipated that the mine workforce will be reduced from 900 to approximately 400 workers. The Company believes that any load reductions at Homestake can be somewhat mitigated by additional off-system sales. Currently, the Company does not believe that this restructuring will have a material adverse effect on results of operations or financial position. Other major industries in and around Black Hills Power's service territory have been economically stable.
WHOLESALE TO CITY OF GILLETTE
Black Hills Power sells electric power and energy to the municipal electric system at Gillette, Wyoming. Service is rendered under a long-term contract, recently amended, and expiring July 1, 2012, wherein Black Hills Power sells to the City of Gillette its first 23 megawatts of capacity requirements and the associated energy. In 1997, as part of the contract amendment, the transmission service component was unbundled from the power supply agreement, and transmission service will be provided at FERC approved rates. In the amended contract, the City of Gillette has agreed not to apply to FERC for any rate change to be effective prior to January 1, 2003, unless and in the event that Black Hills Power files for a rate change with FERC, which rate filing cannot be effective prior to January 1, 2002, except under extraordinary events as defined in the contract. In addition, Black Hills Power agreed to phase in price reductions for the power purchased by the City of Gillette. The most recent average annual capacity factor for this 23 megawatt demand has been approximately 89 percent. Sales to Gillette represented 9.3 percent and 10.6 percent of total firm energy sales and 6.6 percent and 7.1 percent of revenue from total electric sales in 1997 and 1996, respectively.
WHOLESALE TO MDU
Black Hills Power and MDU entered into a Power Integration Agreement, dated as of September 9, 1994, providing for the sale to MDU of up to 55 megawatts of power and associated energy to serve MDU's Sheridan, Wyoming, electric service territory for a period of 10 years which commenced January 1, 1997. The MDU Sheridan service territory has experienced a 47 megawatt winter peak and operates at a 57 percent load factor.
The agreement provides for fixed rates for capacity and energy to be paid by MDU during the 10-year contract term. Black Hills Power and MDU have agreed not to apply to FERC for any rate changes in the contract for the entire 10- year term other than increases caused by governmental direct taxes on electric generation fired by hydrocarbons. The agreement further provides for Black Hills Power and MDU to equally share the costs of constructing a combustion turbine of approximately 70 megawatts at such time during the 10-year term that Black Hills Power determines in its sole discretion that such turbine is required.
ADDITIONAL OFF-SYSTEM SALES
Black Hills Power sold 279,600 and 249,100 megawatt hours of non-firm energy in 1997 and 1996, respectively. The selling price is based on spot market prices which have generated only a small profit margin on the sales. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
TRANSMISSION SERVICE SALES
Black Hills Power furnishes long-term transmission services under two contracts: (i) the transmission contract terminating December 31, 2020 (1986 Agreement), among Black Hills Power and Basin Electric and the other distribution cooperatives as it concerns the transmission contract (the Cooperatives) and (ii) the agreement with the City of Gillette terminating July 1, 2012 (described under Wholesale to City of Gillette above), under which Black Hills Power has agreed to deliver all of the City of Gillette's electric requirements. The rates charged under the transmission contract with the Cooperatives are fixed formula rates, and the transmission rates under the Gillette contract are established by FERC under Black Hills Power's open access transmission tariff. (See ITEM 3. LEGAL PROCEEDINGS - Transmission Rates - FERC Proceedings and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.)
COMPETITION IN THE ELECTRIC UTILITY BUSINESS
For information relating to competition in the electric utility business, see ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.
COAL SALES
SALES TO BLACK HILLS POWER'S PLANTS
Wyodak Resources sells coal to Black Hills Power for all its requirements under an agreement that limits earnings from all coal sales to Black Hills Power (including the 20 percent share on the Wyodak Plant and all sales to Black Hills Power's other plants) to a return on Wyodak Resources' original cost, depreciated investment base. The return is 4 percent (400 basis points) above A-rated utility bonds to be applied to Wyodak Resources' coal mining investment base as determined each year. Black Hills Power made a commitment to the SDPUC, the WPSC and the City of Gillette that coal would be furnished and priced as provided by this agreement for the life of NS #2. Earnings from the intercompany sales of coal at this time represent 5.3 percent of the Company's consolidated earnings.
Sales and production statistics for the last three calendar years comparing sales to Black Hills Power to others are as follows:
SALES TO THE WYODAK PLANT
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.) The price for unprocessed coal sold to Pacific Power for its 80 percent interest in the Wyodak Plant is determined by a coal supply agreement entered into by Black Hills Power, Pacific Power and Wyodak Resources in 1978 and terminating in the year 2013. This agreement was amended and restated in 1987. Revenue from coal sales to the Wyodak Plant totaled $22,688,000 in 1997 or 73 percent of revenue for all coal sold by Wyodak Resources. The quantity of coal sold in 1997 for the Wyodak Plant was 2,155,000 tons, as compared to 2,125,000 tons sold in 1996. 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 tons. The average consumption is expected to continue during the remaining 16 years of the coal agreement. However, from time to time, the plant's physical operating capabilities will affect the quantity of coal burned.
Of the 3,251,000 tons of coal sold by Wyodak Resources in 1997, 1,427,000 tons were sold to Black Hills Power, 1,725,000 tons were sold to Pacific Power and 99,000 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 total unaffiliated customers for the last three years was as follows:
(1) The first seven months of 1995 are not adjusted for the affiliate coal price adjustment.
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.
OTHER SALES
In addition to the coal sold to the Wyodak Plant and to Black Hills Power, Wyodak Resources sold 119,000 tons of coal to the South Dakota State Cement Plant in 1996. The Cement Plant canceled this contract in October 1996. Smaller amounts of coal are sold to various businesses. All substantial long- term contracts contain adjustment clauses based upon certain costs and government indices.
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. Currently, Wyodak Resources' coal sales are confined to sales for consumption at or near the mine. Wyodak Resources is a relatively small coal mine in relation to others in the area and its current production costs exceed the current spot market price for coal. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-BUSINESS OUTLOOK STATEMENTS-Future Coal Sales.)
OIL AND GAS 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 three years. The oil and gas industry is highly competitive. Western Production encounters strong competition from many oil and gas producers in acquiring drilling prospects and producing properties.
The Company's oil and gas production is sold at or near the wellhead, generally at prevailing posted prices. Western Production has been able to market all of its oil and gas production. Operating revenue by source for the last three years was as follows:
Western Production produced approximately 590,000 equivalent barrels of oil in 1997 comprised of 51 percent oil and 49 percent gas.
ENERGY MARKETING OPERATIONS
In July 1997, Black Hills Capital Group acquired the assets and hired the operational management of Jomax Partners, L.P. as successor and survivor of Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada Company. In March 1998, Wickford Energy Marketing, Inc. changed its name to Black Hills Energy Resources, Inc. Black Hills Energy Resources is headquartered in Houston, Texas with a natural gas sales office in Calgary, Alberta, Canada and crude oil sales offices in Tulsa, Oklahoma and Midland, Texas. Black Hills Energy Resources is a "niche" wholesale natural gas and crude oil marketing company with expertise in Gulf Coast and Canadian Supply, targeting natural gas markets in the East Coast and Midwest and crude oil markets primarily in the Southwest.
Since its acquisition in July 1997, Black Hills Energy Resources marketed 231,000 mmbtus (million British thermal units) of natural gas per day and 12,600 barrels of oil per day. Wholesale natural gas and crude oil businesses are high volume, lower margin operations. Operating revenues for natural gas and crude oil sales totaled $94,295,000 and $46,810,000, respectively, for the five month period since acquisition. With a full year of operations in 1998, the Company expects revenues to increase substantially from 1997 levels, but does not expect Black Hills Energy Resources' contribution to total Company operations to be significant.
In 1996, Wyodak Resources established Enserco Energy, Inc., a Lakewood, Colorado-based energy marketing company. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -RESULTS OF OPERATIONS - Energy Marketing Operations.)
ENVIRONMENTAL REGULATION
The Company is subject to extensive federal, state and local laws and regulations governing discharges to the air and water, as well as the handling and disposal of solid and hazardous wastes, including without limitation the federal Clean Air Act (as amended in 1990), the federal Water Pollution Control Act ("Clean Water Act"), the federal Toxic Substances Control Act and various state laws, including solid waste disposal laws (collectively "Environmental Regulatory Laws"). Governmental authorities have the power to enforce compliance with Environmental Regulatory Laws, and violators may be subject to civil or criminal penalties, injunctions or both. Third parties also may have the right to sue to enforce compliance.
AIR QUALITY
Under the federal Clean Air Act, the federal Environmental Protection Agency ("EPA") has promulgated national air quality standards for certain air pollutants, including sulfur oxides, particulate matter and nitrogen oxides. The Company was granted a prevention of significant deterioration ("PSD") construction permit by the DEQ for NS #2. The PSD permit set emission rate limitations on particulate, sulfur dioxide, nitrogen oxides and opacity. NS #2 is currently working with DEQ to obtain an air quality operating permit and expects to receive such permit in 1998. Black Hills Power has been in substantial compliance with its PSD permit in its operations of NS #2 since its completion in August of 1995. Black Hills Power is continuing to make final adjustments to NS #2's equipment and operating procedures and to work with the DEQ to obtain its operating permit and achieve complete compliance.
Amendments to the Clean Air Act in 1990 will require a significant reduction in nationwide sulfur oxide emissions by fossil fuel-fired generating units to a permanent total emissions cap in the year 2000. This reduction is to be achieved by the allotment of allowances to emit sulfur dioxide measured in tons per year to each owner of a unit and requiring the owner to hold sufficient allowances each year to cover the emissions of sulfur oxide from the unit during that year. Black Hills Power holds sufficient allowances credited to it as a result of sulfur removal equipment previously installed on the Wyodak Plant to apply to the operation of NS #2 and its interest in the Wyodak Plant in the year 2000 without requiring the purchase of any additional allowances. Current law does not require allowances for Black Hills Power's other plants.
All existing generating units of the Company are required to obtain operating source permits under the Clean Air Act amendments. The operating permit applications for the Osage and NS #1 generating units were submitted in 1995 and received in 1997. Air quality permits for the Ben French Station were renewed in 1995 by the Department of Environment and Natural Resources of South Dakota. Black Hills Power expects to renew this permit in 1998.
Because the 1990 amendments to the Clean Air Act are scheduled to be implemented and interpreted throughout the 1990s, compliance with yet-to-be promulgated and interpreted regulations may require additional capital and operational expenditures in the future, most likely from enhanced monitoring costs. Due to the political sensitivity and volatility of environmental issues and how they may be implemented, management can give no assurances that unexpected additional capital and operating costs may be required in the future that would have a material impact on financial results.
WATER QUALITY
The federal Clean Water Act requires permits for discharges of effluent and that all discharges of pollutants comply with federally approved state water quality standards. Black Hills Power currently has in place all required permits under the Clean Water Act for discharges from all of the power plants in which Black Hills Power has an interest. While management believes that it is in full compliance with all federal and state clean water laws and regulations, for all the same reasons as stated in the previous paragraph, no assurances can be given of the extent of costs to comply with clean water requirements in the future.
LAND QUALITY - SOLID WASTE DISPOSAL
Black Hills Power disposes all solid wastes collected as a result of burning coal at its power plants in approved solid waste disposal sites. Each disposal site has been permitted by the state of its location in compliance with law. Ash and wastes from flue gas and sulfur removal from the Wyodak Plant and NS #2 are deposited in disposal cells located in Wyodak Resources' mined areas. These disposal cells are located below some shallow water aquifers in the mine. Management believes that the disposal cells are sufficiently constructed and lined with clay so as to prevent any pollution of the underground water from these cells. None of the solid wastes from the burning of coal is classified as hazardous material, but the wastes do contain minute traces of metals that would be perceived as polluting if such metals were leached into underground water. While management does not believe that any substances from the solid waste disposal will pollute underground water, they can give no assurances that over a long period of time such could never happen. In such event, the Company could experience material costs in mitigating any damages from such pollution. Agreements in place require Pacific Power to be responsible for any such costs that would be related to the solid waste from its 80 percent interest in the Wyodak Plant.
Additional unexpected material costs could also result in the future from either the federal or state government determining that solid waste from the burning of coal does contain some hazardous material that requires some special treatment, including solid waste previously disposed of, and holding those entities who disposed of such waste responsible for such treatment. Such unexpected governmental requirements are beyond the control of the Company.
RECLAMATION
Under federal and state laws and regulations, Wyodak Resources is required to submit to and receive approval from the DEQ for a mining and reclamation plan which provides for orderly mining, reclaiming and restoring of all land in conformity with all laws and regulations. Wyodak Resources has an approved mining permit and is otherwise in compliance with other land quality permitting programs.
One condition that could result in substantial unexpected increases in costs of the reclamation permit relates to three depressions, the existing south depression, the Peerless depression and the North Pit depression, which have or will result from Wyodak Resources' 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, 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 areas than expected. The DEQ has allowed the depressions at the minimum acres specified and subject to maintenance of water quality at the sites. Exceedence of acreage limitations or degradation of water quality could result in material additional requirements placed upon Wyodak Resources, including the placement of additional quantities of overburden in the depressions and restoring water quality. Based on extensive reclamation studies, accruals are maintained to comply with all reclamation requirements. However, no assurances can be given that additional requirements in the future may be imposed that cause unexpected material increases in reclamation costs.
BEN FRENCH OIL SPILL
In 1990 and 1991, Black Hills Power discovered extensive underground fuel oil contamination at the Ben French Plant site. With the help of expert consultants, the Company engaged in assessment and remediation and has worked closely with the South Dakota Department of Environment and Natural Resources. Assessment and remediation efforts are continuing up to the present time. All underground oil-carrying facilities from which the contamination occurred are now above ground. There have been no significant recoveries of free fuel oil product since 1994. Black Hills Power continues to monitor the site. Soil borings and monitoring wells on the perimeters of Black Hills Power's Ben French Plant property are showing no indication of contamination beyond the property's limits. Management believes that the underground spill has been sufficiently remedied so as to prevent any oil from migrating off site. However, due to underground gypsum deposits in this area, the fuel oil has the potential of migrating to area waterways. In such event, cleanup costs could be greatly increased. Management believes that sufficient remediation efforts to prevent such a migration are currently in place, but due to the uncertainties of underground geology, no assurance can be given.
Cleanup costs recognized to date total approximately $434,000, of which amount $312,000 has been reimbursed from the South Dakota Petroleum Release Compensation Fund. To date, no penalties, claims or actions have been taken or threatened against the Company because of this oil spill.
PCBS
Under the federal Toxic Substances Control Act, the EPA has issued regulations that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had been widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the Toxic Substances Control Act prohibited any further manufacture of such PCB equipment. Black Hills Power removes and disposes of PCB-contaminated equipment in compliance with law as it is discovered.
Several years ago, Black Hills Power began a testing program of possible PCB- contaminated transformers, and in 1997 completed testing of all transformers and capacitators which are not located in Black Hills Power's electric substations. Black Hills Power has not completed the testing of sealed potential transformers and bushings located in its electric substations as the testing of such equipment will require the destruction of the equipment. While release of PCB-contaminated fluid, if present, from such equipment is unlikely and the volume of fluid in such equipment is generally less than one gallon, any release of such fluid would be confined to Black Hills Power's substation site.
Release of PCB-contaminated fluids, especially any involving a fire or a release into a waterway, could result in substantial cleanup costs. The Company has not received any notices of non-compliance relating to PCB regulations.
ELECTROMAGNETIC FIELDS
A number of studies have examined the possibility of adverse health effects such as cancer from electromagnetic fields (EMF) which are caused by electric transmission and distribution facilities. 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 and costly 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 the State of Florida so as to minimize the EMF effect. The Company is unable to predict the future costs to the electric utility industry, including the Company, if a determination is made in the future, either based on facts or perception, that EMF causes adverse health effects.
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, 1997, the number of employees of the Company (including Black Hills Power), Wyodak Resources, Western Production and Black Hills Capital Group were 324, 53, 35, and 34, respectively, for a total of 446 employees.
Approximately 44 percent of the employees of Black Hills Power are covered by union contracts with the International Brotherhood of Electrical Workers. In the Company's opinion employee relations are satisfactory.
ITEM 2.
ITEM 2. PROPERTIES
UTILITY PROPERTIES
The following table provides information on the generating plants of Black Hills Power. During 1997, 99 percent of the fuel used in electric generation, measured in Btus (British thermal units), was coal.
GENERATING UNITS
(a) These combustion turbines are those referenced by ITEM 1. BUSINESS - ELECTRIC POWER SUPPLY - Pacific Power's Reserve Capacity Integration Agreement.
(b) NS #2 was placed into commercial operation in August 1995. The plant's total production may, at times, exceed its name plate rating by 11 MWs.
(c) Black Hills Power's 20 percent interest. See Note 6 of "Notes to Consolidated Financial Statements". Black Hills Power owns transmission lines and distribution systems in and adjoining the communities served consisting of 447 miles of 230 kV, 530 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 others.
MINING PROPERTIES
Wyodak Resources is engaged in mining and processing sub-bituminous coal near Gillette in Campbell County, Wyoming, and owns or has user rights in the necessary mining, processing and delivery equipment to fulfill its sales contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal are based upon four federal leases and one state lease. The estimated recoverable coal from the leases as of December 31, 1997 is 284,175,000 tons, of which 24,132,000 tons are committed to be sold to the Wyodak Plant and approximately 26,130,000 tons to Black Hills Power's other plants.
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. The state lease provides for a royalty to be determined every five years. Currently, the royalty on the state lease, to be reviewed in 1998, is 7% of the selling price of the coal. Each federal lease and state 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 the state lease constitute one logical mining unit which 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 December 31, 1991, the date of the logical mining unit. Even if federal and state 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 state and 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. 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.
In September 1996, Wyodak Resources entered into an agreement to purchase the Clovis Point Mine properties from Kerr McGee Coal Corporation. Acquisition of the property increased Wyodak Resources' 1996 recoverable reserves to approximately 288 million tons and includes a train loadout facility, maintenance and processing facilities and a developed open pit. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES - Acquisition of Clovis Point Mine Properties.)
OIL AND GAS PROPERTIES
Western Production operates 310 wells as of December 31, 1997. The majority of these wells are in the Finn Shurley Field, located in Weston and Niobrara Counties, Wyoming. Western Production does not operate, but owns a working interest in 174 producing properties located in the western and southern United States. Western Production also owns a 44.7 percent non-operating interest in a natural gas processing plant also located at the Finn Shurley Field.
Western Production participated in the drilling of 37 exploratory and development wells in 1997. Western Production's average working interest in such wells was 19 percent, or 7 net 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. Twenty- two out of the 37 wells drilled in 1997 were completed as producing wells for an overall drilling success rate of 59 percent.
See the table in Note 10 of "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS" for Western Production's estimated quantities of proved developed and undeveloped oil and natural gas reserves at December 31, 1997, 1996 and 1995, and a reconciliation of the changes between these dates using constant product prices for the respective years.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
TRANSMISSION RATES - FERC PROCEEDINGS
In Black Hills' open access transmission tariff proceedings before the FERC under the provisions of Rule 888, Black Hills and the FERC Trial Staff have reached a settlement which has been forwarded to the FERC for their review and approval. This settlement allows Black Hills to use the revenues received under the long-term transmission agreement between the Company and the Cooperatives which terminates on December 31, 2020 (SEE ITEM 1. BUSINESS - ELECTRIC SERVICE TERRITORY AND SALES) as being equal to the cost of providing service to the Cooperatives. The settlement recognizes the benefits realized by Black Hills in working with the RECs relating to the construction of transmission facilities and, as a result of these joint efforts, applies the revenue credit method in determining Black Hills Power's open access transmission tariff rates by crediting the revenue received from the Cooperatives against Black Hills Power's revenue requirements necessary to earn a just and reasonable rate on its transmission facilities. The Cooperatives' transmission loads are not considered when calculating Black Hills' open access transmission tariff rates; and as such, the Cooperatives are paying less than their fully allocated cost for use of the transmission system. But as a result of allowing the revenue credit methodology, the open access transmission rates still allow Black Hills to earn a just and reasonable rate on its transmission facilities. The settlement with the FERC is consistent with past actions of the SDPUC and WPSC, which similarly have allowed Black Hills to use the revenue credit methodology in determining bundled rates for retail customers. The settlement with the FERC now applies the revenue credit methodology in determining wholesale transmission rates.
In the settlement with the FERC Trial Staff, Black Hills has agreed to file for new open access transmission tariff rates in the event that: (1) either the South Dakota or the Wyoming legislatures adopt retail access which would allow alternative electricity suppliers to have access to existing franchised retail service territories; (2) an entity other than Black Hills Power or the Cooperatives establishes generation tied to a Cooperative's transmission line as identified in the 1986 Black Hills Power-Basin Electric Transmission Agreement for service to that entity's existing retail customers within the joint transmission area; (3) an AC/DC/AC tie is established near Rapid City, South Dakota, to connect the western electric transmission and eastern electric transmission grids of the United States; or (4) the FERC revises the rates Black Hills Power charges the Cooperatives. Finally, to the extent that a transmission customer (other than Black Hills Power or the Cooperatives) arranges for transmission service on the Cooperatives' transmission facilities as defined in the 1986 Agreement for the purposes of serving the transmission customer's retail customers within the joint transmission area as defined within the 1986 Agreement, Black Hills Power shall provide a credit, not to exceed its tariff rate, against their rates for transmission service it charges to such transmission customer for its use of the Cooperatives' transmission facilities to serve the transmission customer's retail customers within the joint transmission area.
Because Rule 888 now gives the cooperatives the full use of the transmission system, in another FERC proceeding, Black Hills Power has filed a complaint against the Cooperatives asking the FERC to modify the transmission contract with the cooperatives so that the Cooperatives will in the future be obligated to pay a just and reasonable rate that would fairly allocate the capital costs of the transmission system to reflect the cooperative's use of that system. No further action has occurred in the complaint filed by Black Hills Power against the Cooperatives and Black Hills' request to require the Cooperatives to pay a just and reasonable rate for their use of the transmission system.
In view of the uncertainty as to how the FERC will administer the new Rule 888 in ordering open access transmission and the uncertainty of whether the FERC will interfere with existing transmission contracts, the Company can give no opinion as to the outcome of the FERC proceedings outlined above. However, Black Hills Power does not anticipate any material use of its transmission system by third-parties until such time that retail wheeling may be instituted. It is uncertain at this date as to what extent the FERC or the state regulatory jurisdictions will have jurisdiction over determining retail wheeling rates. (See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)
OTHER 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.
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 1997.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
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 6,539 common shareholders of record. All 50 states and the District of Columbia plus 8 foreign countries are represented.
The Company has declared Common Stock dividends payable in cash in each year since its incorporation in 1941. At its January 1998 meeting, the Board of Directors raised the quarterly dividend to 25.0 cents per share, equivalent to an annual increase of 5.3 cents per share. This regular quarterly dividend is payable March 1, 1998. Dividend payment dates are normally March 1, June 1, September 1, and December 1.
Quarterly dividends paid and the high and low Common Stock prices for the last two years adjusted for the 3-for-2 Common Stock split in March 1998 were as follows:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following data was derived from the Company's audited financial statements.
* The per share of common stock information has been restated to reflect the 3-for-2 Common Stock split in March 1998.
Quarterly financial data for the years indicated are summarized as follows:
*The earnings per share amounts have been restated to reflect the March 1998 stock split.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
The Company generated cash from operations sufficient to meet operating needs, pay dividends on common stock and finance a portion of capital requirements. Except for the construction of NS #2, a new power plant which began commercial operation in August 1995, property additions from 1995 through 1997 were primarily for the replacement of equipment, modernization of facilities, oil and gas investment and expansion of energy marketing operations. The primary capital requirements of the Company for the past three years were as follows:
Capital requirements for projected construction, capital improvements, oil and gas investments and corporate development activities for the next three years are estimated to be as follows:
The electric and coal mining operations' forecasted expenditures include the replacement of equipment and modernization of facilities. Forecasted expenditures for the oil and gas operations are dependent upon future cash flows and include an active development and exploratory drilling program and acquisition of existing producing properties. Forecasted investment in corporate development activities are dependent on market conditions at the time and the Company's ability to identify opportunities consistent with its corporate strategy. WYGEN, Inc., DAKSOFT, Inc., Black Hills Energy Resources, Inc. (formerly Wickford Energy Marketing, Inc.), VariFuel, Inc. and Enserco Energy, Inc., do not have any forecasted capital expenditures that are significant. WYGEN was formed as an exempt wholesale generator and will not incur substantial costs until and unless long-term power sale contracts are obtained. DAKSOFT was formed to develop and market internally generated computer software associated with the Company's business segments. Black Hills Energy Resources, Inc. and VariFuel, Inc. were acquired in 1997 and are energy marketing companies. Enserco was formed in 1996 as an energy marketing company. The energy marketing companies are generally not capital intensive businesses. If long term sales agreements are reached requiring capital expenditures, such expenditures will be evaluated at that time.
Electric operations is the only segment of the Company's business with long- term debt. Long-term debt sinking fund requirements are: $1,331,000 in 1998, $1,330,000 in 1999 and $1,330,000 in 2000.
Under its mining permit, Wyodak Resources is required to reclaim all land where it has mined coal reserves. The cost of reclaiming the land is accrued as the coal is mined. While the reclamation process takes place on a continual basis, much of the reclamation occurs over an extended period after the area is mined. Approximately $700,000 is charged to operations as reclamation expense annually. As of December 31, 1997, accrued reclamation costs were approximately $16,700,000 which includes $7,957,000 for the 1996 Clovis Point Mine Acquisition. (See Acquisition of Clovis Point Mine Properties following this section.)
The Company has a 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 percent of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. The Company used the open market purchase option for all of 1997, 1996 and 1995.
Under a 1994 shelf registration, the Company issued bonds in the amount of $30,000,000 on February 3, 1995 and $15,000,000 on July 14, 1995. The $30,000,000 bond issue has a 15-year life with an 8.06 percent rate of interest; and the $15,000,000 bond issue has a 7-year life with a 6.5 percent rate of interest. The $30,000,000 bond issue is redeemable at the option of the holders in integral multiples of $1,000 on February 1, 2002. The debt component of the Company's capital structure at December 31, 1997 and 1996, was 44 percent and 46 percent, respectively. The Company does not anticipate any additional long-term debt financings in the next three years and would expect the debt ratio to decrease to approximately 40 percent over the next 3 to 5 year period unless the WYGEN project is constructed or significant other development opportunities are consummated. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS- RESULTS OF OPERATIONS-Independent Power Business.)
The Company had $12,000,000 of unsecured short-term lines of credit at December 31, 1997 and 1996, which provide for interim borrowings and the opportunity for timing of permanent financing. There were no borrowings outstanding under these lines of credit as of December 31, 1997. Borrowings outstanding under these lines of credit were $120,000 as of December 31, 1996 at a weighted average interest rate of 8.0 percent. There are no compensating balance requirements associated with these lines of credit.
In addition to the above lines of credit, Black Hills Energy Resources has a $65,000,000 uncommitted line of credit with a national bank ($50,000,000 for letters of credit and $15,000,000 for working capital) to provide credit support for purchases and sales of natural gas and crude oil. The Company does not provide credit support for this agreement. At December 31, 1997, there were outstanding letters of credit totaling $29,000,000 which reduced the available credit to $36,000,000.
In addition to the above lines of credit, Black Hills Energy Resources has guaranteed a $15,000,000 line of credit for Enserco to use to guarantee letters of credit. Enserco pays a 0.125 percent facility fee on this line of credit. At December 31, 1997, there were no balances outstanding on this line of credit.
In the past, the Company has relied upon internally generated funds, issuance of short and long-term debt and sales of common stock to finance its activities.
Credit ratings for the Company's First Mortgage Bonds are at an A1 level at Moody's Investors Service, Inc. and at an A+ at Standard & Poor's. These ratings reflect the respective agencies' opinions of the credit quality of the Company's first mortgage bonds.
ACQUISITION OF CLOVIS POINT MINE PROPERTIES
In September 1996, Wyodak Resources entered into an agreement to purchase the Clovis Point Mine properties from Kerr-McGee Coal Corporation. The Clovis Point Mine properties are located adjacent to Wyodak Resource's current reserves in Campbell County, Wyoming, and consist of State of Wyoming and federal leased coal reserves.
Acquisition of the property increased the Company's 1996 recoverable reserves from 170 million tons to approximately 288 million tons and included a train loadout facility, maintenance and processing facilities and a developed open pit.
The purchase price consisted of the assumption of the responsibility to reclaim the existing Clovis Point open pit and the payment of overriding royalties to Kerr McGee if and when coal is produced from the acquired properties. Wyodak Resources is not obligated to mine the coal. (See NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 7.) The acquisition was subject to the approval of the Bureau of Land Management(BLM) of the United States of a logical mining unit (LMU) including the newly acquired Clovis Point Mine. The Company received the BLM approvalin 1997. The Board of Land Commissioners of the State of Wyoming approved the transfer of the state lease in 1996. The modified LMU meets all requirements of the laws and regulations for an LMU.
RATE REGULATION
COMMERCIAL OPERATION OF NS #2 AND THE RELATED RATE RECOVERY
NS #2, an 80 megawatt coal-fired electric generating plant located adjacent to the Company's coal mine, began commercial operation in August 1995. The cost of the plant was approximately $122,000,000 which was $2,900,000 under the initial project budget. A portion of the generation from the plant replaced power Black Hills Power was purchasing from other sources.
Black Hills Power was authorized a 6.76 percent increase in electric rates charged its South Dakota customers (representing approximately 81 percent of 1995 sales) effective August 1, 1995, an 8.97 percent increase for its Wyoming retail customers (representing approximately 8 percent of 1995 sales) effective August 16, 1995, and a 12.3 percent increase for its only wholesale customer in 1995, the City of Gillette (representing approximately 10 percent of 1995 sales), effective September 6, 1995. The increase for the City of Gillette was reduced to an 8.8 percent increase commencing January 1, 1997, when Black Hills Power began to receive additional revenue from wholesale sales to MDU for its Sheridan, Wyoming, service territory. (See ITEM 1. BUSINESS - ELECTRIC SERVICE TERRITORY AND SALES - Wholesale to City of Gillette; Wholesale to MDU.)
The South Dakota and Wyoming settlements further provide that unless an extraordinary event occurs, Black Hills Power will not file for any increase in rates or invoke any fuel and purchased power automatic adjustment tariff to take effect during a freeze period ending January 1, 2000. The specified extraordinary events are: new governmental impositions increasing annual costs in South Dakota above $1,000,000 or $325,000 in Wyoming, forced outages of both the Wyodak Plant and NS #2 projected to continue at least 60 days in South Dakota and three months in Wyoming, forced outages occurring to either plant which are continued for a period of three months or projected to last at least nine months and an increase in the Consumer Price Index at a monthly rate for six consecutive months which would result in a 10 percent or more annual inflation rate.
During the freeze period, Black Hills Power is undertaking the risks of machinery failure, load loss caused by either an economic downturn or changes in regulation, increased costs under existing power purchase contracts over which the Company has no control, government interferences, acts of nature and other unexpected events that could cause material losses of income or increases in costs of doing business. However, the settlement anticipates that Black Hills Power will retain during that period of time earnings realized from more efficient operations, sales from load growth, and off-system sales of power and energy, including the sale to MDU. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
LONG-TERM CONTRACTS
As a result of rate negotiations, Black Hills Power was successful in entering into long-term contracts with most of its industrial and large commercial customers. The all requirements electric service agreement with Homestake Mining Company expires September 9, 2002, and the other contracts have terms of five years that begin to expire in 2000. However, each of the contracts provides options for the customer to keep the term of the contract extended for at least three years, with the proviso that if the customer allows the term to reduce to less than two years, Black Hills Power will be able to invoke a planning surcharge on that customer. If deregulation in retail electric sales occurs, the contracts give Black Hills Power notice to allow for planning to make the transition to full competition, guard against stranded investment and protect other customers from rate impacts of unexpected load loss. However, management cannot predict if the notice period would be sufficient to fully adapt for competition. These industrial and large commercial customers, together with the wholesale power sales agreements to the City of Gillette and MDU, result in approximately 40 percent of Black Hills Power's firm load under these term contracts.
BUSINESS DEVELOPMENT RATES
Both the SDPUC and the WPSC authorized Black Hills Power to negotiate rates above its marginal costs but below full cost with any customer with a load of over 250 KVA if that customer has a legal choice of its electric supplier. Black Hills Power expects to utilize this tariff in those instances where a new business would have a choice of locating in the service territory of either Black Hills Power or a competing REC or enticing a new business to locate or relocate in Black Hills Power's service territory. Black Hills Power has available resources to compete for new large load customers through this new tariff.
COMPETITION IN ELECTRIC UTILITY BUSINESS
CURRENT STATUS OF COMPETITION FOR 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. Black Hills Power's transmission system is interconnected to Pacific Power's transmission system near Gillette, Wyoming, and to WAPA's system near Scottsbluff, Nebraska. Pacific Power provides electric service at retail to large portions of Wyoming. 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 customers 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. 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 a municipality. 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 originally assigned based on 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.
Every 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 customers within its city. As a wholesaler of electric power and energy, such municipality would have the power to demand and receive transmission access over Black Hills Power's transmission system consistent with its open access transmission tariff. The FERC has recognized the principle that a city, which establishes a municipal electric system and buys power from a supplier other than its former electric utility, should compensate the former supplier for any stranded costs caused by the change in the power supplier. However, the Company can give no assurances to what extent the stranded cost provisions will be administered or how they would be applied to Black Hills Power. Black Hills Power is not aware of any movement by any municipality in its service territory which does not already have a municipally owned electric system to establish one.
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
The business of electric generation is no longer reserved exclusively for the traditional public utility such as Black Hills Power. The Energy Policy Act of 1992 exempted independent power producers engaged exclusively in the sale of power at wholesale from the onerous restrictions of the Public Utility Holding Company Act. The Public Utility Regulatory Policies Act of 1978 (PURPA) authorizes entities generating electricity from waste fuel and renewable fuel or utilizing steam for both generation and other purposes to force a public utility to purchase the energy at an avoided cost. These laws, together with the FERC mandating all public utilities under its jurisdiction to file tariffs providing transmission access for sales of energy at wholesale, have caused electric generation and the marketing of electric energy at wholesale to become extremely competitive. While independent power producers, other than qualifying facilities under PURPA, are regulated by the FERC, the FERC is allowing rates for the sale of generation to be determined by the market rather than by costs if the producer or marketer can demonstrate no market power.
As a result of these changes in the law and regulations, the traditional public utility, such as Black Hills Power, is more likely to purchase energy required for its franchised service territories through competitive bidding and either not expand its rate base generating capabilities or engage in the electric generation business through independent power producers by selling to other utilities. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -RESULTS OF OPERATIONS - Independent Power Business.)
Future generation, whether constructed by a public utility or an independent power producer, is likely to be justified strictly on the basis of the marketability of the capacity and energy from the new source in a competitive market.
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 and management does not believe that such sources are cost effective, but no assurances can be given that material competition from these sources will not occur.
TRANSMISSION ACCESS
In 1996, the FERC adopted Rule 888 that requires each public utility under its jurisdiction to file open access transmission tariffs that provide rates which are comparable to the same transmission costs of the public utility to transmit power over its system. The rates provide for various transmission services to be provided for any competitor but apply to the transmission of electric power for wholesale purposes only. Black Hills Power filed an application with the FERC in 1996 to approve its open access transmission tariffs. The regulations further require the public utility to keep posted for public access, on an electronic bulletin board, all current information concerning the availability and rates for these transmission services. Black Hills Power was granted an extension by FERC to delay establishing an electronic bulletin board until WAPA, which operates the control area in which Black Hills Power is located, establishes or participates in an electronic bulletin board. The public utilities are further required by FERC to adopt standards of conduct which require the functional separation of those persons who operate and market the transmission system from those persons who buy and sell power for the same utility; however, the FERC granted a waiver to Black Hills Power from the requirement to adopt the standards of conduct in view of Black Hills Power's small transmission system and lack of significant market control. The regulations are designed to attempt to eliminate any market advantage of the utility owning transmission over others engaged in the sale of electric power at wholesale.
The new FERC regulations requiring the filing of open access tariffs does not apply to the nonjurisdictional utilities such as the RECs and publicly owned electric utilities. However, these nonjurisdictional utilities are subject to the law that allows the FERC to force them to provide transmission services upon application, and the FERC has adopted reciprocity regulations that would authorize a jurisdictional utility to deny transmission access to a nonjurisdictional utility which has denied access.
Black Hills Power currently furnishes transmission service for competing RECs through contract. As long as the states in which Black Hills Power operates continue to grant exclusive service territories, the federal government does not preempt this state jurisdiction and municipalities in Black Hills Power's service territory do not establish municipal electric systems, the increase in transmission access for wholesale purposes through Black Hills Power's transmission system is not likely to have any material adverse effect upon Black Hills Power. Such open access may have a beneficial effect by opening opportunities for the Company to further the marketing of coal-fired energy outside of its service territory.
RETAIL WHEELING
Legislative proposals requiring a public utility to allow its competitors to utilize the utility's electric distribution system to serve end-use customers who are located in service areas assigned to that public utility, commonly referred to as retail wheeling, are getting serious consideration in Congress and in many states. Since the duplication of electric transmission and distribution systems would neither be efficient nor tolerable by the public, the transmission and distribution portion of the business is likely to continue to be regulated with rates based on costs. The Company cannot predict when and if mandated retail wheeling will come to the areas where it now provides exclusive retail electric service. Major problems should be resolved first, such as the preservation of reliable service, compensation to a utility for investment incurred to fulfill its duty to serve but stranded because of competition, fairness of market pricing between large industrial users and small business and residential users and assurances that all utilities, including the RECs, are bound to operate under the same rules. At this time, South Dakota does not have any legislative activity regarding retail wheeling. A committee of the Wyoming legislature considered an electric deregulation bill for the 1998 session. The bill did not get out of committee, however, it or an alternative bill could be introduced to the full Wyoming legislature for consideration. The regulatory commissions in both states are considering the potential impacts of electric utility industry restructuring. The Company is unable to predict whether Congress or the states may in the future require electric retail competition and, if they do, whether the ground rules for competition will be fair to all participants.
Management is unable to predict the effect of full electric retail competition on the Company's earnings. Management does anticipate that a transition period of at least five years will be required to achieve a fully competitive electric energy retail market. During that five years, Black Hills Power will endeavor to increase its earnings through additional sales and cost containment. Based upon the FERC's expressed positions concerning open access transmission regulations, electric utilities which will lose revenues due to competition should be allowed recovery of stranded costs. The market price of electric energy in a fully competitive market is expected to be based upon a much wider geographical area than just Black Hills Power's service territory. Because energy providers are likely to seek the markets where the highest profit margins can be realized, today's rates designed to serve exclusive service territories may be substantially different for service to a fully competitive market. Lower rates today are partially caused by excess generation capacity which allows providers to sell energy above their marginal costs but below full costs.
However, the Company is unable to predict future markets and economic conditions and government actions or inaction that could have a materially adverse affect on Black Hills Power's ability to compete in a fully competitive electric power market and to maintain its equity return on investment. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
REGULATORY ACCOUNTING
Black Hills Power follows Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating Black Hills Power. As a result of Black Hills Power's recent regulatory activity, a 50-year depreciable life for NS #2 is used for financial reporting purposes. If Black Hills Power were not following SFAS 71, a 35 to 40 year life would probably be more appropriate which would increase depreciation expense by approximately $600,000 per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to Black Hills Power's generation operations. In the event Black Hills Power determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would be an extraordinary noncash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict Black Hills Power's ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate.
RESULTS OF OPERATIONS
CONSOLIDATED RESULTS
The Company reported record earnings for 1997 due to strong sales growth in electric operations, record coal production and stable oil and gas results. Consolidated net income for 1997 was $32,359,000 compared to $30,252,000 in 1996 and $25,590,000 in 1995 or $1.49 per average common share in 1997, $1.40 per average common share in 1996 and $1.19 per average common share in 1995. This equates to a 15.8 percent return on year-end common equity in 1997, 15.7 percent in 1996 and 14.0 percent in 1995. Consolidated net income includes noncash earnings of $3,645,000 for allowance for equity funds used during NS #2 construction in 1995.
Consolidated revenue and net income (loss) provided by the four business segments as a percentage of the total were as follows:
Dividends paid on common stock totaled $0.95 per share in 1997. This reflected increases approved by the Board of Directors from $0.92 per share in 1996 and $0.89 per share in 1995. All dividends were paid out of current earnings. The Company's dividend objective is to increase the dividend at or above the electric utility average and reduce the Company's payout ratio to the low 60's. Management believes this objective is attainable through earnings growth. The Company's three year dividend growth rate was 2.6 percent and the payout ratio for 1997 was 63 percent.
In January 1998 the Board of Directors increased the quarterly dividend 5.6 percent to 25 cents per share. If this dividend is maintained during 1998, it will be equivalent to $1.00 per share, an annual increase of 5 cents per share.
The Board of Directors, at its January 1998 meeting, declared a 3-for-2 Common Stock split effected in the form of a stock dividend. The stock distribution is payable March 10, 1998 to shareholders of record on February 13, 1998 and is reflected in this report.
ELECTRIC OPERATIONS
Electric revenue increased 6.6 percent in 1997 compared to a 9.1 percent increase in 1996 and a 3.8 percent increase in 1995. Firm kilowatthour sales increased 13.0 percent in 1997 compared to a 3.9 percent increase in 1996 and a 0.5 percent increase in 1995 and have averaged an annual 5.7 percent growth rate over the last three years.
The increase in electric revenue and firm kilowatthour sales in 1997 was primarily due to the additional load to serve MDU's energy requirements for its customers in the Sheridan, Wyoming area. Partially offsetting the increase, residential sales declined 3 percent primarily due to milder weather. Degree days, a measure of weather trends, were 15 percent below last year and 2 percent below normal.
The increase in electric revenue in 1996 was due to strong sales growth in all sectors of the Company's electric business, including the industrial sector which had a decrease in sales in 1995, and the inclusion of NS #2 in the Company's rate base (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - RATE REGULATION - Commercial Operation of NS #2 and the Related Rate Recovery).
The increase in revenue in 1995 was primarily due to the increase in electric rates and strong growth in the residential and commercial sectors of the Company's electric business. While the residential and commercial sectors which provide Black Hills Power with the highest margin sales showed strong growth, the impact of this growth was partially offset by a 5.2 percent decrease in kilowatthour sales to the industrial customers.
Revenue per kilowatthour sold was 5.5 cents in 1997 compared to 5.8 cents in 1996 and 6.1 cents in 1995. The number of customers in the service area increased to 56,269 in 1997 from 55,601 in 1996 and 55,018 in 1995. The revenue per kilowatthour sold in 1997 reflects the increased wholesale sales to MDU's Sheridan, Wyoming customers and 279,600 megawatthours of wholesale non- firm sales. The revenue per kilowatthour sold in 1996 and 1995 reflects the increase in electric rates and the strong growth in the higher margin sectors of Black Hills Power's business offset by the impact of 249,100 megawatt hours of wholesale non-firm sales in 1996 and 60,575 megawatt hours in 1995. Excluding Sheridan, Wyoming's sales and non-firm sales, the rate per kilowatthour sold was 6.5 cents in 1997 and 1996 and 6.3 cents in 1995.
Operating expenses have remained fairly stable over the last three years. The increase in operating expenses in 1997 are primarily due to the increased load requirements to serve MDU's Sheridan, Wyoming energy needs. The increase in operating expenses and depreciation associated with the commercial operation of NS #2 were offset by a decrease in fuel and purchased power costs. Coinciding with the commercial operation of NS #2, in 1995, the electric operations realized a decrease in the cost of coal per ton charged by Wyodak Resources. Over the past several years Black Hills Power was not allowed to include in rates charged to its South Dakota customers any cost of coal which allowed Wyodak Resources to earn a return on equity on sales of coal to Black Hills Power in excess of a percentage equal to the rate on long-term "A" rated utility bonds plus 400 basis points (4 percent). Any excess amount that was charged was refunded to Black Hills Power's South Dakota customers through the fuel and purchased power adjustment clause. Beginning with the commercial operation of NS #2, Wyodak Resources changed its coal pricing methodology to Black Hills Power making the price of coal equal to the above limitation thereby eliminating the need for any further adjustment to the electric operations revenue. The impact of this change reduced fuel expense for the electric operations, reduced revenue for the coal mining operations and had no material impact on the consolidated financial statements. ` Depreciation expense decreased 9 percent in 1997 as a result of the 1996 accelerated depreciation of the Kirk Power Plant. Depreciation expense increased 35 percent in 1996 related to a full year of depreciation on NS #2 and accelerated depreciation related to the Kirk Power Plant. The Kirk Power Plant was placed in cold reserve in August 1995 and was fully depreciated at December 31, 1996.
Firm energy sales are forecasted to increase over the next 10 years at an annual compound growth rate of approximately 2 percent with the system demand forecasted to increase 2.1 percent in the summer and 2.4 percent in the winter. The Company currently has a winter peak of 327 MWs established in January 1997 and a summer peak of 346 MWs established in July 1997. These forecasts are from studies conducted by the Company with the help of outside consultants whereby Black Hills Power's service territory is 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 as was experienced with the industrial sales growth in 1995. However, in the past the forecasts tracked actual sales within a band of reasonableness over a period of several years. Weather deviations can adversely effect energy sales when compared to forecasts based on normal weather.
COAL MINING OPERATIONS
Revenue decreased 1 percent in 1997 due to a decrease in the price charged to the utility's operations. (See explanation of the change in coal pricing methodology under Electric Operations). Wyodak Resources had record coal production of 3,251,000 tons in 1997.
Revenue increased 4.8 percent in 1996 and 4.5 percent in 1995, due to a 10.5 percent and a 5.0 percent increase in tons of coal sold in 1996 and 1995, respectively.
Operating expenses decreased 1 percent in 1997 due to lower revenue based taxes other than income taxes and increased 8.1 percent in 1996 and 5.7 percent in 1995 reflecting the increase in tons of coal sold.
Non-operating income was $1,066,000 in 1997 compared to $2,725,000 in 1996 and $2,279,000 in 1995. Non-operating income includes gains or losses on sale or disposal of property and equipment and interest income from investments. Non- operating income increased in 1996 due to a $700,000 gain realized on the disposal of equipment and an increase in cash available for investment. Non- operating income increased in 1995 due to a $700,000 gain realized on the disposal of equipment offset by a decrease in interest rates.
Wyodak Resources expects relatively stable sales in 1998 absent unplanned outages at the Wyodak Plant or Black Hills Power's plants. OIL AND GAS 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 three years.
Western Production's product sales and product prices for the last three years were as follows:
In 1997 and 1996, Western Production sold certain interest in natural gas properties for $165,000 and $380,000, respectively. Such sales are not expected to materially impact future production.
During 1995, Western Production sold its interest in several wells with estimated net remaining reserves of 208,000 barrels of oil equivalent for approximately $2,175,000. The impact of this sale reduced 1995 production by approximately 100,000 equivalent barrels.
Western Production's production expenses increased 8.5 percent in 1997, 1.1 percent in 1996, and decreased 7.1 percent in 1995. Production expenses increased in 1997 due to increased depletion as a result of increased oil and gas production and lower crude oil prices. Production expenses decreased in 1995 reflecting lower depletion expense associated with higher oil prices and a successful drilling program. Western Production recognized $3,920,000, $3,434,000 and $3,730,000 of depletion expense in 1997, 1996 and 1995, respectively. Low oil and gas prices reduce the cash flow and value of the Company's oil and gas assets and will cause the Company to increase its depletion expense.
Western Production's proved reserves and the revenues generated from production decline as production occurs, except to the extent successful exploration, development, and production enhancement activities are conducted or additional proved reserves are acquired. Western Production has been active in exploration and development drilling during the past three years.
Western Production's drilling results were as follows:
In 1997, Western Production acquired approximately 121,000 barrels of oil and 0.2 bcf of natural gas in the Finn Shurley Field for $455,000.
Western Production intends to increase its net proved reserves by selectively increasing its oil and gas exploration and development activities and by acquiring producing properties primarily with the use of internally generated funds.
Western Production's reserves are based on reports prepared by Ralph E. Davis Associates, Inc. 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. Western Production's unaudited reserves, principally proved developed and proved undeveloped properties, were estimated to be 2.5, 2.4, and 1.6 million barrels of oil and 9.1, 11.0 and 7.7 billion cubic feet of natural gas as of December 31, 1997, 1996 and 1995, respectively. The decrease in reserves at December 31, 1997 was due to lower oil and gas prices and reductions in engineering estimates of recoverable reserves for certain natural gas properties. The increase in reserves at December 31, 1996 was due to a successful drilling program and higher oil and gas prices. The decrease in reserves at December 31, 1995 was due to the sale of properties described above and low gas prices.
ENERGY MARKETING OPERATIONS
Within the context of this report, an energy marketing company is a company that sells and buys natural gas and electric power at market prices and ordinarily does not participate in the production of energy. A marketing company is not a traditional public utility servicing a franchised service territory at rates that are just and reasonable based upon a rate of return on an investment rate base as permitted by regulatory commissions.
Black Hills Capital Group, Inc. was incorporated by the Company to hold the Company's equity and debt investments in Black Hills Energy Resources, Inc. (formerly Wickford Energy Marketing, Inc.), VariFuel, Inc. and Enserco Energy, Inc. (the energy marketing companies are described in more detail below). In addition to the energy marketing companies, Black Hills Capital Group will be the primary vehicle for future corporate development activities outside of the internal company specific activities.
In 1997, Black Hills Capital Group incurred a net loss of $746,900 primarily due to mild weather conditions in its target markets, start-up expenses and additional administrative expenses to expand its energy marketing operations.
In July 1997, Black Hills Capital Group acquired the assets and hired the operational management of Jomax Partners, L.P. as successor and survivor of Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada Company. Black Hills Energy Resources, Inc. (formerly Wickford Energy Marketing, Inc.) is headquartered in Houston, Texas with a natural gas sales office in Calgary, Alberta, Canada and crude oil sales offices in Tulsa, Oklahoma, and Midland, Texas. Black Hills Energy Resources is a "niche" wholesale natural gas and crude oil marketing company with expertise in Gulf Coast and Canadian supply, targeting natural gas markets in the East Coast and Midwest and crude oil markets primarily in the Southwest.
Since its acquisition in July 1997, Black Hills Energy Resources marketed 231,000 mmbtus of natural gas per day and 12,600 barrels of oil per day. Wholesale natural gas and crude oil businesses are high volume, lower margin operations. Operating revenues for natural gas and crude oil sales totaled $94,295,000 and $46,810,000, respectively, for the five-month period since acquisition. Cost of natural gas and crude oil sold (included in Fuel and Purchased Power in the CONSOLIDATED STATEMENTS OF INCOME) relating to the above revenues totaled $140,151,000 in 1997. With a full year of operations in 1998, the Company expects revenues and related expenses to increase substantially from 1997 levels, but does not expect Black Hills Energy Resources' contribution to total Company operations to be significant.
Black Hills Energy Resources has a $65,000,000 uncommitted line of credit with a national bank ($50,000,000 for letters of credit and $15,000,000 for working capital) to provide credit support for purchases and sales of natural gas and crude oil. The Company does not provide credit support for this agreement.
In November 1997, Black Hills Capital Group, Inc. acquired the assets and hired the operational management of VariFuel, Inc. (VariFuel). VariFuel targets commercial and industrial natural gas customers located primarily in the Chicago, Illinois and northern Indiana area. VariFuel is headquartered in Houston, Texas with a sales office in Chicago, Illinois. VariFuel's retail marketing operations complement Black Hills Energy Resources' wholesale marketing operations in the Midwest. The financial position and results of operations of VariFuel are not significant to the Company at this time.
In 1996, Wyodak Resources, with the participation of three individuals, formed an energy marketing startup company under the name of Enserco Energy, Inc. (Enserco), headquartered in Lakewood, Colorado. Wyodak Resources acquired 50 percent of the capital stock of Enserco, and the other 50 percent was acquired by three of the full-time officers of Enserco. However, to fund the startup operations, Wyodak Resources acquired a convertible debenture from Enserco, that Wyodak Resources has the right to convert to additional capital stock of Enserco, which would increase Wyodak
Resources' ownership interest to 70 percent of the issued and outstanding capital stock of Enserco.
To provide Enserco with the financial backing to participate in the purchase and sale of natural gas and electric power, Wyodak Resources has agreed to guarantee up to $15,000,000 of letters of credit to be issued by banks to guarantee purchases and sales of natural gas and electric power.
Enserco has acquired the approval from the FERC of a tariff which allows Enserco to sell electric power at market prices. Enserco is also qualified to purchase and sell natural gas at market prices. Enserco is a startup company and has not as yet realized a profit. Its operations are not material to the Company at this time.
Although the energy marketing business is highly competitive, management is of the opinion that due to the increasing competition in the energy business, it is essential for many reasons to be active with the energy marketing business, including the knowledge the Company gains in the marketing of energy, which is required for the Company to effectively compete in all aspects of its energy business.
The energy marketing companies anticipate generating large amounts of revenue and corresponding expense related to buying and selling energy products. Associated with the purchase and sale of energy products, the energy marketing companies will use derivatives (exchange traded and over-the-counter energy financial instruments) to manage risk associated with the buying and selling of energy products whose prices can be extremely volatile. The use of derivatives helps mitigate risk in the trading of energy products but does not eliminate the risk. Wyodak Resources and the energy marketing companies have adopted risk management policies and established risk management committees to further mitigate risk associated with the sale and purchase of energy products. Some purchasers and sellers with whom the energy marketing companies transact business require the utilization of letters of credit to assure the underlying performance of the obligations between the parties. The failure of a party to perform may result in a significant risk of loss to the energy marketing companies and corresponding loss to Wyodak Resources as it concerns the outstanding letters of credit to Enserco. INDEPENDENT POWER BUSINESS
In 1994, Wyodak Resources formed a wholly owned subsidiary named WYGEN, Inc. WYGEN applied for and received from the FERC a determination that WYGEN has exempt wholesale generator status under Section 32 of the Public Utility Holding Company Act. WYGEN was formed for the sole purpose of engaging in the generating and selling of electric power and energy at wholesale. At this time WYGEN is proposing to build an 80 megawatt coal-fired electric generating plant to be known as the WYGEN Plant adjacent to NS #2. In 1996, WYGEN received a prevention of significant deterioration air quality construction permit from the DEQ. Construction must commence within two years of the granting of the permit or WYGEN will be required to reapply. As an independent power project, the air quality permit is the only major permit required. WYGEN plans to renew this permit in 1998. Viable markets for the electric power and energy from the WYGEN Plant will depend partially upon the cost of transmission rights to deliver the electric power and energy to higher priced energy markets. While the FERC's open access transmission regulations should make such transmission legally available, physical transmission constraints or the perception of such constraints may require WYGEN's participation in transmission improvements which, together with transmission rates for access across transmission systems, could make the WYGEN Plant less economical. The economics of delivering power over multiple-owned transmission systems will depend upon how successful the FERC is in bringing about regional transmission systems operated independently of the interest of any one provider, with mechanisms to pool costs and cause transmission system improvements to be constructed, on a timely basis, with broad participation.
In addition, to the WYGEN Project, the Company is exploring opportunities for participating in the acquisition of existing or new independent power projects fueled by coal or natural gas and located at Wyodak Resources' mine or at other locations in the United States.
OTHER SEGMENTS OF BUSINESS
DAKSOFT, Inc. was incorporated by the Company in 1994, to develop and market internally generated computer software associated with the Company's business segments. Additionally, DAKSOFT has developed internet/intranet products which are currently being used internally and marketed to third parties. No significant revenues have been received to date. DAKSOFT entered into a multiyear enhancement and sales contract in 1995. The revenue from this contract is earned as the product enhancement occurs. Approximately $219,000, $370,000 and $290,000 of revenue was recognized in 1997, 1996, and 1995, respectively. Also, in 1997, DAKSOFT entered into an implementation and enhancement agreement for the customized installation of its Customer Information System (CIS) product. Revenue from such installation and enhancement agreement totaled $457,000 in 1997.
Landrica was incorporated by the Company in March 1984, and holds minor interests in real estate.
The financial position and results of operations of WYGEN, DAKSOFT and Landrica are not material to the Company.
YEAR 2000 ISSUES
The Company uses technologies throughout its operations that will be affected by year 2000 issues. During 1997, the Company implemented remediation steps to make the core business systems which are part of the Company's mid-range computer systems year 2000 compliant. The Company also has initiated a company-wide project, to be completed in 1998, to identify and assess year 2000 compliance for all other Company systems and the compliance status of its critical suppliers. The expenses relating to year 2000 compliance incurred in 1997 were not material, and the Company believes the amounts that are expected to be expensed in the future for such compliance will not have a material impact on its results of operations.
NEW ACCOUNTING PRONOUNCEMENT
In March 1997, the Financial Accounting Standards Board released Statement of Financial Accounting Standards No. 128, Earnings per Share, (SFAS 128) which requires the disclosure of basic earnings per share and diluted earnings per share. The diluted earnings per share recognizes the impact of the Company's stock option plans (See NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 2 Common Stock) as if fully vested at the grant date. Adoption of this statement did not have a material affect on the results of operations or financial position of the Company.
BUSINESS OUTLOOK STATEMENTS
The following statements are based on current expectations. These statements under this Business Outlook Statements section are forward-looking, and actual results may differ materially.
PACIFIC POWER'S POWER SALES AGREEMENT
Pacific Power's Power Sales Agreement represents Black Hills Power's highest- cost electric power resource. Black Hills Power expects to reduce these costs in the future through better utilization of the resource and as a result of the Second Restated and Amended Power Sales Agreement executed between Pacific Power and Black Hills Power. This Second Restated and Amended Power Sales Agreement, effective August 1, 1997, and terminating December 31, 2023, supersedes the Restated Agreement, which was intended to be effective January 1, 2000.
Black Hills Power has been able to utilize the 75 MW resource from Pacific Power's Power Sales Agreement at a load factor of only 55 percent. Black Hills Power anticipates higher utilization of this resource in the future and lowering the average cost per megawatt hour through an active marketing program to sell the power and energy. This marketing program will include the use of the Pacific Power's Power Sales Agreement contract under which Black Hills Power has the right to cause the power and energy to be delivered at any point on Pacific Power's transmission system (defined as both Pacific Power's owned and contracted transmission paths) where capacity is available.
The Second Restated Agreement provides (i) that 25 megawatts of the contract capacity amount and the charges thereof will be deleted, 5 megawatts each year commencing in the year 2000, (ii) Black Hills Power shall pay no levelized annual charges for Colstrip Plants' additions and replacements which are completed after January 1, 1997, (iii) that commencing January 1, 1997, all fixed cost components of the Variable Costs to be paid by the company shall be based on an assumption that the Colstrip Plants operated at an 80 percent load factor, (iv) beginning August 1, 1997 and continuing until December 31, 1999, Black Hills Power shall pay Pacific Power annual fixed cost of $164.59 per kW- yr multiplied by the capacity purchased, (v) commencing January 2000 and continuing until December 2018, Black Hills Power shall pay Pacific Power's initial investment in Colstrip Units 3 and 4 using Pacific Power's then most current applicable cost of capital consisting of Pacific Power's then current FERC approved capital structure, Pacific Power's then current weighted average cost of long-term debt and preferred stock using FERC approved methods and Pacific Power's then current FERC approved cost of common equity, (vi) that for the invoices the fixed amount calculated above shall be reduced by $95,564 each month for the years 2000 through 2009, and (vii) unbundling of the transmission charge in the contract to Pacific Power's FERC-filed rates. Future cost reductions or increases related to these amendments will depend on Pacific Power's future capital structure and cost of capital and the cost of replacement power starting in the year 2000. However, the Company believes the reduction of the 25 MWs of capacity which begins in the year 2000 at a rate of 5 MW a year is positive as the Company enters a deregulated electricity market and believes Pacific Power's future cost of capital under the FERC approved capital structure will be lower than the cost of capital formulas embedded in the existing contract.
FUTURE ELECTRIC SALES
Future earnings from all power sales are dependent on many economic and political factors, including the move toward competition at the retail level, the market price of electricity, the ability of Black Hills Power to generate and deliver electric power at a cost that will allow a profit margin and the regulatory treatment of electric utilities during the transition period toward competition.
In order to realize a higher margin of profit than from sales on the spot market, Black Hills Power continues to look for opportunities to sell power off-system over a term of six months or longer. The highly competitive wholesale electric power market, the lack of an open retail market at this time, the cost of transmission to deliver the power to markets where prices are higher, the current low natural gas prices and the availability of surplus capacity and energy are the current competitive conditions that make it difficult to find new markets. However, management believes that Black Hills Power's marginal production costs are low enough and the quantity of power Black Hills Power has available high enough that new opportunities for off- system sales are feasible.
FUTURE RETAIL WHEELING
Management is unable to predict the effect of full electric retail competition (if it comes about) on the Company's earnings. Management does anticipate that a transition period of at least five years will be required to achieve a fully competitive electric energy retail market. Black Hills Power continues to endeavor to increase its earnings through additional sales and cost containment. Based upon the FERC's expressed positions concerning open access transmission regulations, electric utilities which will lose revenue due to competition should be allowed to recover stranded costs. The market price of electric energy in a fully competitive market is expected to be based upon a much wider geographical area than just Black Hills Power's service territory. Because the energy providers are likely to seek the markets where the highest profit margin can be realized, today's rates designed to serve exclusive service territories may be substantially different for service to a fully competitive market. Based upon industry predictions, management believes that the industry's excess capacity will be more fully utilized in the future. Management believes that coal-fired plants will become more competitive with natural gas-fired plants in the future as natural gas prices increase.
However, the Company is unable to predict future markets and economic conditions and government actions or inactions that could have a materially adverse effect on Black Hills Power's ability to compete in a fully competitive electric power market and to maintain its equity return on investment.
RATE REGULATION
Management's expectation is that the rate settlements made with the South Dakota and Wyoming Commissions are beneficial in that (i) management has confidence in the operational capability of Black Hills Power's power plants; (ii) management does not anticipate purchasing any substantial amount of capacity and energy during the freeze period except for its existing purchase power agreements; and (iii) Wyodak Resources' mining costs are not expected to materially increase.
FUTURE COAL SALES
Because of an acquisition of unit train load-out facilities with the Clovis Point Mine Properties, Wyodak Resources expects to increase its market opportunities. However, the heating value (approximately 8,000 Btu per pound) of the coal at Wyodak Resources' mine and the Clovis Point Mine Properties is approximately 400 to 800 Btus less than Powder River Basin coal available at other locations. This difference makes Wyodak Resources' coal noncompetitive in the current market for coal to be shipped by rail over long distances because of higher freight rates per Btu. Notwithstanding this limitation, the acquisition of a unit train loadout facility has led management to investigate opportunities for Wyodak Resources to ship coal by rail at closer distances where the Btu difference would not be a major factor, and to ship coal that is enhanced at the coal mine site by various processes, one of the results of which would remove some of the moisture content of the coal and thereby increase the Btu per pound content. Processes for the enhancement of Powder River Basin coal are being developed and seriously considered for commercial operations by the coal industry. Management can give no assurances at this time that any coal enhancement process is commercially practical in view of the current low spot market price of Powder River Basin coal, that a market for enhanced coal can be developed or that a coal enhancement project at Wyodak Resources' mine would be feasible.
Freight rates to ship coal by rail are also a material factor in determining the economic feasibility of selling either raw run-of-the-mine coal or enhanced coal products. At this time only one rail carrier, the Burlington Northern, is available to Wyodak Resources for such sales. Reasonable freight rates are a requirement for any rail transported sales from Wyodak Resources' mine.
FUTURE ENERGY MARKETING SALES
The profitability of the Company's energy marketing operations depends in large part on management's ability to assess and respond to changing market conditions. Such conditions include, but are not limited to, availability of supply, availability of transportation capacity from supply area to markets served and market demand. In addition, such operations are highly sensitive to weather conditions in the markets served. The Company is unable to predict future markets and economic conditions that could effect the profitability of the energy marketing operations.
FUTURE CORPORATE DEVELOPMENT ACTIVITIES
The Company created a new subsidiary named Black Hills Capital Group, Inc. to spearhead its corporate development activities. Black Hills Capital Group, Inc.'s focus is to increase the Company's earnings and assets through energy related investments that position the Company to earn multiple revenue streams in the energy value chain. Potential investment could comprise of independent power projects, coal reserves, oil and gas reserves, energy transportation assets, energy marketing assets or other related assets. The success of the Black Hills Capital Group acquiring such assets will depend on future market conditions. The market for such assets is very competitive. The Company is unable to predict future markets and economic conditions that could effect the profitability and probability of the success of corporate development activities.
RISKS AND UNCERTAINTIES
The forward looking statements contained in the Management's Discussion and Analysis of Financial Condition and Results of Operations involve a number of risks and uncertainties. In addition to factors discussed above, other factors that could cause actual results to differ materially are the following: the extent to which the federal government or the state governments, or both, institute competition in the electric utility business; the market value of electric power at the time full competition comes about, including any competitor's delivery costs to Black Hills Power's current markets and Black Hills Power's ability to produce and deliver power at those market prices; the extent to which the surplus electric generation continues; the extent that any electric generating surplus is exhausted and customers are again entering into longer-term purchased power contracts with prices relating more to the full cost of generating and delivering electric power; the future market prices of crude oil, natural gas and coal; government regulations of the environment, especially to the extent to which further financial burdens may be placed upon coal versus natural gas and additional governmental burdens that may be placed upon the burning of all fossil fuels; the extent to which competition will be fairly administered for participants in the electric utility business and whether it will be applied equally to investor-owned companies, rural electric cooperatives, public power agencies and municipalities; technological advances in the generation and delivery of electric power; the general economy as it affects the use of electric power; the market price of competing fuels to electricity, such as natural gas; the extent to which coal beneficiation programs are efficiently developed and the extent to which the new coal products will be accepted by the market; the general economy of Black Hills Power's retail service territory; and other risk factors which are referenced in this report and other SEC reports filed prior hereto.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants 32
Consolidated Statements of Income and Retained Earnings for the three years ended December 31, 1997 33
Consolidated Statements of Cash Flows for the three years ended December 31, 1997 34
Consolidated Balance Sheets as of December 31, 1997 and 1996 35
Consolidated Statements of Capitalization as of December 31, 1997 and 1996 36
Notes to Consolidated Financial Statements 37
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, 1997 and 1996, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota, January 28, 1998
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1997, 1996 AND 1995
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BUSINESS DESCRIPTION
Black Hills Corporation and its subsidiaries operate in four primary business segments: electric, coal mining, oil and gas production, and energy marketing. 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 18 percent of the Company's electric revenue in 1997, 17 percent in 1996 and 18 percent in 1995. 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 discussed in Note 6, approximately 73 percent of the coal mining operation's sales are to the Wyodak Plant. Sales of coal to the Company and to PacifiCorp, herein referred to as Pacific Power, represent 98 percent of total coal sales in 1997. The Company's oil and gas exploration and production business operates and has working interests in properties located in the western and southern United States. The Company's energy marketing businesses market natural gas, crude oil and electricity and provide related energy services to customers in the West Coast, Rocky Mountain region, Southwest, Midwest and East Coast markets.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation except for revenues and expenses associated with intercompany coal sales in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Total intercompany coal sales not eliminated were $11,089,000, $10,384,000 and $10,498,000 in 1997, 1996 and 1995, respectively.
Investments in and advances to Enserco, in which the Company has a 50 percent ownership interest, are accounted for on the equity method of accounting.
The Company uses the proportionate consolidation method to account for its working interests in oil and gas properties.
REGULATORY ACCOUNTING
Black Hills Power follows the provisions of SFAS No. 71, and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating Black Hills Power. As a result of Black Hills Power's 1995 rate case settlement, a 50-year depreciable life for NS #2 is used for financial reporting purposes. If Black Hills Power were not following SFAS 71, a 35 to 40 year life would be more appropriate which would increase depreciation expense by approximately $600,000 per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to Black Hills Power's generation operations. In the event Black Hills Power determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would be an extraordinary noncash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict Black Hills Power's ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate.
PROPERTY
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.
The Company periodically evaluates assets under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of," which imposes a stricter criterion for assets by requiring that such assets be probable of future recovery at each balance sheet date.
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 3.0 percent in 1997, 3.4 percent in 1996 and 3.0 percent in 1995. Composite depreciation rates for other property were 8.1 percent, 7.7 percent and 8.9 percent in 1997, 1996 and 1995, respectively. Depletion of coal and oil and gas properties is computed using the cost method for financial reporting.
AVAILABLE FOR SALE SECURITIES
The Company has investments in marketable securities which are classified as available-for-sale securities and are carried at fair value. The difference between the securities' fair value and cost basis and the realized gains and losses on sales of the securities were not significant for the periods presented.
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.
FUEL AND PURCHASED POWER ADJUSTMENT TARIFFS
The Company's Montana Retail Tariffs contain a clause that allow recovery of certain fuel and purchased power costs in excess of the level of such costs included in base rates. The cost adjustment tariff is revised periodically for any difference between the total amount collected under the clause and the recoverable costs incurred. The adjustments are recognized as current assets or current liabilities until adjusted through future billings to customers. The Company's South Dakota, Wyoming and wholesale tariffs do not include an automatic fuel and purchased power adjustment tariff.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Ultimate results could differ from those estimates.
OIL AND GAS OPERATIONS
The Company accounts for its oil and gas drilling activities under the full cost method. Under the full cost method, all productive and nonproductive costs related to acquisition, exploration and development activities are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Under the full cost method, net capitalized costs may not exceed the present value of proved reserves.
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 10.0 percent in 1997 and 1996 and 10.2 percent in 1995.
INCOME TAXES
The Company follows the provisions of SFAS 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 and tax bases of assets and liabilities. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. To the extent such income taxes are recoverable or payable through future rates, regulatory assets and liabilities have been recorded in the accompanying consolidated balance sheets.
Deferred taxes are provided on all significant temporary differences, principally depreciation and depletion. Investment tax credits have been deferred in the electric operation and the accumulated balance is amortized as a reduction of income tax expense over the useful lives of the related electric property which gave rise to the credits.
ENVIRONMENTAL REMEDIATION
In October 1996 the American Institute of Certified Public Accountants issued Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities" which provides authoritative guidance on specific accounting issues that are present in the recognition, measurement, display and disclosure of environmental remediation liabilities. The provisions of the SOP are effective for the Company for fiscal year 1997 but did not have a material impact on the Company's financial position or results of operations.
(2) CAPITAL STOCK
In January, 1998, the Board of Directors declared a 3-for-2 Common Stock Split effected in the form of a stock dividend. The stock dividend is payable March 10, 1998 to shareholders of record on February 13, 1998. The common stock share and per share information in the accompanying consolidated financial statements and notes have been restated to reflect the stock distribution.
NET INCOME PER SHARE
The Company adopted the SFAS No. 128 "Earnings Per Share" in 1997. As a result, all prior periods presented have been restated to conform to the provisions of SFAS No. 128, which requires the presentation of basic and diluted earnings per share. Basic earnings per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed under the treasury stock method and is calculated to compute the dilutive effect of outstanding stock options. A reconciliation of these amounts is as follows (in thousands, except per share data):
COMMON STOCK
The Company has a stock option plan ("the 1996 Stock Option Plan") which allows for the granting of stock options with exercise prices equal to the stocks' market value on the date of grant and an employee stock purchase plan ("the ESPP Plan"). The Company accounts for under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized.
Had compensation cost been determined consistent with SFAS No. 123, the Company's net income and earnings per share would have been reduced to the following proforma amounts:
The Company may grant options for up to 300,000 shares of common stock under the Stock Option Plans The Company has granted options on 182,700 shares and 83,700 shares through December 31, 1997 and 1996, respectively. The option exercise price equals the fair market value of the stock on the day of the grant. The options granted have an exercise price range of $16.67 to $22.50. The options granted vest one-third a year for three years and all expire after ten years from the grant date. At December 31, 1997, 27,900 options were available for exercise at an exercise price of $16.67. There were no options available for exercise at December 31, 1996.
The fair value of each option grant is estimated on the date of grant using the Black Scholes option pricing model with the following weighted-average assumptions used for the grants:
The Company issued 29,294 and 37,871 shares of common stock under the ESPP Plan in 1997 and 1996, respectively. At December 31, 1997, 279,959 shares are reserved and available for issuance under the ESPP Plan. The Company sells the shares to employees at 90 percent of the stock's market price on the offering date. The fair value per share of shares sold in 1997 was $15.50.
The Company has a Dividend Reinvestment and Stock Purchase Plan under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100 percent of the recent average market price. The Company has the option of issuing new shares or purchasing the shares on the open market. The Company purchased shares on the open market in 1997, 1996 and 1995. At December 31, 1997, 1,290,797 shares of unissued common stock were available for future offerings under the Plan.
ADDITIONAL PAID-IN CAPITAL
Changes in additional paid-in capital for the years indicated were:
(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. Scheduled maturities of long-term debt for the next five years are: $1,331,000 in 1998, $1,330,000 in 1999, $1,330,000 in 2000, $3,029,000 in 2001 and $18,018,000 in 2002.
In 1994 the Company filed a Form S-3, shelf registration for $100,000,000 first mortgage bonds. Under the filing, the Company issued bonds in the amount of $45,000,000 on September 1, 1994, $30,000,000 on February 3, 1995 and $15,000,000 on July 14, 1995. The $30,000,000 bond issue is redeemable at the option of the holders in integral multiples of $1,000 on February 1, 2002. These bond issues were used to finance NS #2.
(4) NOTES PAYABLE TO BANKS
The Company had $12,000,000 of unsecured short-term lines of credit at December 31, 1997 and 1996. There were no outstanding borrowings under these lines of credit at December 31, 1997. Borrowings outstanding under these lines of credit were $120,000 as of December 31, 1996, at a weighted average interest rate of 8.0 percent. The Company has no compensating balance requirements associated with these lines of credit. The lines of credit are subject to periodic review and renewal during the year by the banks.
In addition to the above lines of credit, Black Hills Energy Resources, Inc. (formerly Wickford Energy Marketing, Inc.), has a $65,000,000, uncommitted, discretionary credit facility consisting of a $50,000,000 transactional line of credit and a $15,000,000 overdraft line of credit. The transactional line of credit provides credit support for the purchases of natural gas and crude oil of Black Hills Energy Resources. The Company and its subsidiaries provide no guarantee to the Lender. At December 31, 1997, Black Hills Energy Resources had letters of credit outstanding of $29,000,000 and no balance outstanding on the overdraft line of credit.
In addition to the above lines of credit, Wyodak Resources has guaranteed a $15,000,000 line of credit for Enserco to use to guarantee letters of credit. Enserco pays a 0.125 percent facility fee on this line of credit. At December 31, 1997 and 1996, there were no balances outstanding on this line of credit.
(5) FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash of the Company is invested in money market investments such as municipal put bonds, money market preferreds, commercial paper, Eurodollars and certificates of deposit. The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
The following methods and assumptions were used to estimate the fair value of each class of the Company's financial instruments.
CASH AND CASH EQUIVALENTS
The carrying amount approximates fair value due to the short maturity of these instruments.
AVAILABLE FOR SALE SECURITIES
The fair value of the Company's investments equals the quoted market price when available and a quoted market price for similar securities if a quoted market price is not available. The Company has classified all of its marketable securities as available-for-sale as of December 31, 1997 and 1996, and the fair value approximates cost.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on quoted market rates for utility debt instruments having similar maturities and similar debt ratings. The Company's outstanding bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for the Company to call and refinance the bonds.
The estimated fair values of the Company's financial instruments are as follows:
(6) WYODAK PLANT
The Company owns a 20 percent interest and Pacific Power an 80 percent interest in the Wyodak Plant (the Plant), a 330 megawatt coal-fired electric generating station located in Campbell County, Wyoming. Pacific Power is the operator of the Plant. The Company receives 20 percent of the Plant's capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 1997, the Company's investment in the Plant included $72,171,000 in electric plant and $25,961,000 in accumulated depreciation. The Company's share of direct expenses of the Plant was $5,934,000, $6,458,000 and $6,503,000 for the years ended December 31, 1997, 1996 and 1995, respectively, and is included in the corresponding categories of operating expenses in the accompanying consolidated statements of income. Wyodak Resources supplies coal to the Plant under an agreement expiring in 2013 with a Pacific Power option to renew for 10 years. This coal supply agreement is collateralized by a mortgage on and a security interest in some of Wyodak Resources' coal reserves. At December 31, 1997, approximately 24,132,000 tons were covered under this agreement. Wyodak Resources' sales to the Plant were $22,688,000, $22,643,000 and $20,224,000 for the years ended December 31, 1997, 1996 and 1995, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
MDU POWER SALE
On January 1, 1997, the Company began serving a ten year contract to supply up to 55 megawatts of electric power and associated energy required by MDU for its Sheridan, Wyoming, service territory. In 1997, MDU's Sheridan service area experienced a 47 megawatt peak and had a load factor of approximately 57 percent.
COAL OBLIGATIONS
In addition to the 24,132,000 tons of coal reserved under the agreement to supply coal to the Wyodak Plant, Wyodak Resources has reserved 26,130,000 tons of coal under existing contracts.
COAL LEASES
Wyodak Resources' mining rights to its coal are based upon four federal leases and one state lease. The federal leases provide for a royalty of 12.5 percent of the selling price of the coal. The state lease provides for a royalty, to be reviewed every five years, currently at 7 percent. Wyodak Resources paid royalties in the amount of $3,969,000, $3,995,000 and $2,323,000 in 1997, 1996 and 1995, respectively. 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 leases or 10 years from the date of adjustment of the 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 constitute one logical mining unit which is treated as one lease for the purpose of determining diligent development and continuing operation requirements.
PACIFIC POWER'S POWER SALES AGREEMENT
In 1983 the Company entered into a 40 year power agreement with Pacific Power providing for the purchase by the Company of 75 megawatts of electric capacity and energy from Pacific Power's system. The price paid for the capacity and energy is based on the operating costs of one of Pacific Power's coal-fired electric generating plants. Costs incurred under this agreement were $20,251,000, $19,777,000 and $20,689,000 in 1997, 1996 and 1995, respectively.
ACQUISITION OF CLOVIS POINT MINE PROPERTIES
In September 1996 Wyodak Resources entered into an agreement to purchase a portion of the Clovis Point and East Gillette Mine properties from Kerr-McGee Coal Corporation. The Clovis Point Mine properties are located adjacent to Wyodak Resources' current reserves in Campbell County, Wyoming, and consist of State of Wyoming and federal leased coal reserves.
Acquisition of the property in 1996 increased Wyodak Resources' reserves from 170 million tons to approximately 288 million tons and included a train loadout facility, maintenance and processing facilities and a developed open pit.
The purchase price consisted of the assumption of the responsibility to reclaim the existing Clovis Point open pit of which the Company recorded a liability of $7,957,000 and the payment of overriding royalties to Kerr McGee if and when coal is produced from the acquired properties. Wyodak Resources is not obligated to mine the coal.
RECLAMATION
Under its mining permit, Wyodak Resources is required to reclaim all land where it has mined coal reserves. The cost of reclaiming the land is accrued as the coal is mined. While the reclamation process takes place on a continual basis, much of the reclamation occurs over an extended period after the area is mined. Approximately $700,000 is charged to operations as reclamation expense annually. As of December 31, 1997, accrued reclamation costs were approximately $16,700,000 which includes $7,957,000 for the Clovis Point Mine Acquisition.
PRICE RISK MANAGEMENT ACTIVITIES
The Company utilizes a variety of financial instruments to hedge the impact of price fluctuations on its oil and gas production and energy marketing operations. The Company does not hold or issue derivative financial instruments for trading purposes.
The Company utilizes deferral (hedge) accounting in conjunction with such financial instruments; gains or losses from changes in the market value of the financial instruments are deferred until the gain or loss on the hedged item is recognized.
Financial instruments are classified as being used for a hedge only if the instrument reduces the risk of the underlying hedged item and is designated at the inception as a hedge with respect to the hedged item.
The primary financial instruments the Company uses in managing its price risk exposure are exchange traded natural gas futures contracts and over-the-counter natural gas and crude oil swaps, collar and option contracts. The Company would be exposed to credit losses in the event of nonperformance by the counterparties that have issued the financial instruments. The Company does not expect that the counterparties will fail to meet their obligations, based on the Company's review of the financial condition of the counterparties and/or their credit ratings.
At December 31, 1997, the Company has fixed rate for floating rate price swaps to hedge crude oil price risk for 15,000 barrels of oil per month at prices ranging from $19.00 per barrel to $20.93 per barrel. In addition, the Company has fixed rate for floating rate price swaps on 3.9 bcf of natural gas to hedge fixed price sales commitments in a similar quantity.
OTHER
The Company is subject to various legal proceedings and claims which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the consolidated financial position or results of operations of the Company.
(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 securities and cash equivalents.
Net pension expense for the Plan was as follows:
Funding information for the Plan as of October 1 each year was as follows:
The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. Expenses recognized under the plans were $94,000, $498,000 and $350,000 in 1997, 1996 and 1995, respectively.
The Company follows the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." The 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 in 1993, 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:
Funding information as of October 1 was as follows:
For measurement purposes, a 9.5 percent annual rate of increase in healthcare benefits was assumed for 1998; the rate was assumed to decrease gradually to 6 percent in 2005 and remain at that level thereafter. The healthcare cost trend rate assumption has a significant effect on the amounts reported. A one percent increase in the healthcare cost trend assumption would increase the net periodic postretirement cost by approximately $130,000 annually or 24.3 percent. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7.5 percent.
(9) INCOME TAXES
Income tax expense for the years indicated was:
The temporary differences which gave rise to the net deferred tax liability at December 31, 1997 and 1996 were as follows:
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
(10) OIL AND GAS RESERVES (Unaudited)
Western Production has interests in 484 producing oil and gas properties in eight states. Western Production also holds leases on approximately 42,200 net undeveloped acres.
The following table summarizes Western Production's quantities of proved developed and undeveloped oil and natural gas reserves, estimated using constant year-end product prices, as of December 31, 1997, 1996 and 1995, and a reconciliation of the changes between these dates. These estimates are based on reserve reports by Ralph E. Davis Associates, Inc. (an independent engineering company selected by the Company). Such reserve estimates are based upon a number of variable factors and assumptions which may cause these estimates to differ from actual results.
(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
The four primary segments of the Company's business are its electric operations, coal mining operations, oil and gas operations and energy marketing operations. The following table summarizes certain information specifically identifiable with each segment as of, or for, the years ended December 31.
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
Taxes Other than Income Taxes
(13) ACQUISITIONS
In July 1997, Black Hills Capital Group acquired the assets and hired the operational management of Jomax Partners, L.P. as successor and survivor of Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada Company. In March 1998, Wickford was renamed Black Hills Energy Resources, Inc. Black Hills Energy Resources is headquartered in Houston, Texas with a natural gas sales office Calgary, Alberta, Canada and crude oil sales offices in Tulsa, Oklahoma and Midland, Texas. Black Hills Energy Resources is a "niche" wholesale natural gas and crude oil marketing company with expertise in Gulf Coast and Canadian Supply, targeting natural gas markets in the East Coast and Midwest and crude oil markets primarily in the Southwest.
The Company accounted for this acquisition using the purchase method. Results of operations since the acquisition date are included in the consolidated results.
The Company recorded goodwill and intangible assets resulting from the acquisition. The Company is amortizing the goodwill and intangible assets over the expected benefit periods of 15 years and 5 years, respectively, using the straight-line method.
The following, unaudited proforma financial information assumes the acquisition occurred at January 1, 1996, in thousands, except per share amounts:
FINANCIAL STATISTICS
*Common Stock Data has been restated to reflect the 3-for-2 stock split on March 10, 1998.
ELECTRIC OPERATION STATISTICS
ITEM 9.
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.
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 19, 1998.
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, 51, Chairman, President and Chief Executive Officer of Black Hills Corporation Mr. Landguth was elected to his present position in January 1991.
Roxann R. Basham, 36, Vice President - Finance and Secretary/Treasurer Ms. Basham was elected to her present position on December 9, 1997. She had served as Secretary/Treasurer since 1993. She had served as Assistant Secretary/Treasurer since May 1991.
David R. Emery, 35, Vice President - Fuel Resources Mr. Emery was elected to his present position in January 1997. He had served as General Manager of Western Production Company since June 1993 and Petroleum Engineer since 1989.
Gary R. Fish, 39, Vice President - Corporate Development Mr. Fish was elected to his present position in October 1996. He had served as Controller since 1988.
Everett E. Hoyt, 58, President and Chief Operating Officer of Black Hills Power Mr. Hoyt was elected to his present position in October 1989.
James M. Mattern, 43, Vice President - Corporate Administration and Assistant to the CEO Mr. Mattern was elected to his present position in September 1997. He had served as Vice President - Corporate Administration since January 1994 and had served as Director of Human Resources since 1991.
Thomas M. Ohlmacher, 46, Vice President - Power Supply Mr. Ohlmacher was elected to his present position on August 1, 1994. He had served as Director of Power Generation since 1993 and Director of Electric Operations since 1991.
Mark T. Thies, 34, Controller Mr. Thies was elected to his present position on May 1, 1997. Previously, Mr. Thies had served in a number of accounting positions, most recently as Assistant Controller, at InterCoast Energy Company, a wholly owned subsidiary of MidAmerican Energy Holdings Company since 1990.
Kyle D. White, 38, Vice President - Energy Services Mr. White was elected to his present position on January 29, 1998. He had served as Director of Strategic Marketing and Sales since 1993. He had served as Manager, Rates and Regulatory Affairs since 1991.
ITEM 11.
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 19, 1998.
ITEM 12.
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 19, 1998.
ITEM 13.
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 19, 1998.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
Financial statements required by Item 14 are listed in the index included in Item 8 of Part II.
2. Schedules
All schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in the Form 10-K.
3. Exhibits
*3(a) Restated Articles of Incorporation dated May 24, 1984 (Exhibit 3(I) to Form 8-K dated June 7, 1994, File No. 1-7978).
*3(b) Bylaws dated January 30, 1997. (Exhibit 3(b) to Form 10-K for 1997.)
*4(a) Reference is made to Article Fourth (7) of the Restated Articles of Incorporation of the Company (Exhibit 3(a) 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 A-2, File No. 2-4832); (Exhibit 7-B to Form S-1, File No. 2-6576); (Exhibit 7-C to Form S-1, File No. 2-7695); (Exhibit 7-D to Form S-1, File No. 2-8157); (Exhibit 4.05(e) to Form S-3, File No. 33-54329); (Exhibit 4-I to Form S-1, File No. 2-9433); (Exhibit 4-H to Form S-1, File No. 2-13140); (Exhibit 4-I to Form S-1, File No. 2-14829); (Exhibits 4-J and 4-K to Form S-1, File No. 2-16756); (Exhibits 4-L, 4-M, and 4-N to Form S-1, 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 4.05(t), 4.05(u) and 4.05(v) to Form S-3, File No. 33-54329); (Exhibit 4(b) to Form S-3, File No. 2-81643); (Exhibit 4.05(x), 4.05(y), and 4.05(z) to Form S-3, File No. 33-54329); (Exhibit 4(d) and 4(e) to Post- Effective Amendment No. 1 to Form S-8, File No. 33-15868); and (Exhibit 4.05(ac), 4.05(ad), and 4.05(ae) to Form S-3, File No. 33-54329).
*4(d) Indentures of Trust dated as of June 1, 1992, City of Gillette, Campbell County, Wyoming; Lawrence County, South Dakota; Pennington County, South Dakota; Weston County Wyoming; and Campbell County, Wyoming; to Norwest Bank Minnesota, National Association, as Trustee (Exhibits 10(n), 10(q), 10(s), 10(u), and 10(w), to Form 10-K for 1992).
*10(a) 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(b) Restated and Amended Coal Supply Agreement for NS #2 dated February 12, 1993 (Exhibit 10(c) to Form 10-K for 1992).
*10(c) Coal Leases between Wyodak Resources Development Corp. and the Federal Government -Dated May 1, 1959, (Exhibit 5(i) to Form S-7, File No.2-60755) -Modified January 22, 1990 (Exhibit 10(h) to Form 10-K for 1989) -Dated April 1, 1961 (Exhibit 5(j) to Form S-7, File No.2-60755) -Modified January 22, 1990 (Exhibit 10(i) to Form 10-K for 1989) -Dated October 1, 1965 (Exhibit 5(k) to Form S-7, File No.2-60755) -Modified January 22, 1990 (Exhibit 10(j) to Form 10-K for 1989)
*10(d) Further Restated and Amended Coal Supply Agreement dated May 5, 1987 between Wyodak Resources Development Corp. and Pacific Power & Light Company (Exhibit 10(k) to Form 10-K for 1987).
10(e) Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and the Company.
*10(f) 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 Agreement for Coal Supply for Wyodak #2 dated May 5, 1987 (Exhibit 10(o) to Form 10-K for 1987).
10(g) Third Restated Electric Power and Energy Supply and Transmission Agreement dated January 1, 1998, by and between the Company and the City of Gillette, Wyoming.
*10(h) 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(i) Compensation Plan for Outside Directors (Exhibit 10(bb) to Form 10-K for 1992).
*10(j) The Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 27, 1995 (Exhibit 10 (ad) to Form 10-K for 1994).
*10(k) The Amended and Restated Pension Plan of Black Hills Corporation (Exhibit 10 (ad) to Form 10-K for 1994).
*10(l) Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for 1992).
*10(m) Power Integration Agreement, dated September 9, 1994, between the Company and Montana-Dakota Utilities Co., a Division of MDU Resources Group, Inc. (Exhibit 10(gg) to Form 8-K dated September 12, 1994, File No. 1-7978).
*10(n) Change in Control Agreements dated January 30, 1996 for Daniel P. Landguth, Everett E. Hoyt, Thomas M. Ohlmacher, James M. Mattern, Roxann R. Basham and Gary R. Fish (Exhibit 10(af) to Form 10-K for 1995).
*10(o) Marketing, Capacity and Storage Service Agreement between Black Hills Corporation and PacifiCorp dated September 1, 1995 (Exhibit 10(ag) to Form 10- K for 1995).
10(p) Change in Control Agreement dated February 1, 1997 for David R. Emery.
10(q) Change in Control Agreement dated May 1, 1997 for Mark T. Thies.
10(r) Change in Control Agreement dated December 31, 1997 for Kyle D. White.
10(s) Black Hills Corporation 1996 Stock Option Plan.
10(t) The Outside Directors Stock Based Compensation Plan.
10(u) Assignment of Mining Leases and Related Agreement effective May 27, 1997, between Wyodak Resources Development Corp. and Kerr-McGee Coal Corporation. Included in this Agreement are coal leases between Wyodak Resources Development Corp. and the Federal Government and the State of Wyoming, as modified by the decision dated May 27, 1997 from the U.S. Department of the Interior - Bureau of Land Management.
21 Subsidiaries of the Registrant.
23a Consent of Independent Public Accountants with respect to Annual Report on Form 10-K.
23b Consent of Independent Public Accountants with respect to Annual Report on Form 11-K.
27 Financial Data Schedule.
99 Annual Report on Form 11-K of the Black Hills Corporation Employee Stock Purchase Plan for the year ended December 31, 1997.
* Exhibits incorporated by reference.
(b) The Company filed a report on Form 8-K on October 10, 1997 relating to the renegotiated Power Sales Agreement with Pacific Power. (c) See (a) 3. above. (d) See (a) 2. above.
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 /s/ DANIEL P. LANDGUTH Daniel P. Landguth, Chairman, President and Chief Executive 					 Officer
Dated: March 9, 1998
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.
/s/ DANIEL P. LANDGUTH Director and Principal March 9, 1998 Daniel P. Landguth, Chairman, Executive Officer President, and Chief Executive Officer
/s/ ROXANN R. BASHAM Principal Financial Officer March 9, 1998 Roxann R. Basham, Vice President-Finance, and Corporate Secretary/Treasurer
/s/ MARK T. THIES Principal Accounting Officer March 9, 1998 Mark T. Thies, Controller
/s/ ADIL M. AMEER Director March 9, 1998 Adil M. Ameer
/s/ GLENN C. BARBE Director March 9, 1998 Glenn C. Barber
/s/ BRUCE B. BRUNDAGE Director March 9, 1998 Bruce B. Brundage
/s/ JOHN R. HOWARD Director March 9, 1998 John R. Howard
/s/ EVERETT E. HOYT Director and Officer March 9, 1998 Everett E. Hoyt (President and Chief Operating Officer of Black Hills Power)
/s/ KAY S. JORGENSEN Director March 9, 1998 Kay S. Jorgensen
/s/ THOMAS J. ZELL Director March 9, 1998 Thomas J. Zeller
BOARD OF DIRECTORS AND OFFICERS
BOARD OF DIRECTORS OFFICERS
Daniel P. Landguth Daniel P. Landguth Chairman of the Board, President and Chairman of the Board,President Chief Executive Officer of the Company and Chief Executive Officer
Adil M. Ameer Roxann R. Basham President and Chief Executive Officer Vice President - Finance and Rapid City Regional Hospital Corporate Secretary/Treasurer
Glenn C. Barber David R. Emery President and Chief Executive Officer Vice President - Fuel Resources Glenn C. Barber & Associates, Inc.
Bruce B. Brundage Gary R. Fish President and Director Vice President - Corporate Brundage & Company Development
John R. Howard Everett E. Hoyt President President and Chief Operating Industrial Products, Inc. Officer of Black Hills Power and Light Company
Everett E. Hoyt James M. Mattern President and Chief Operating Officer Vice President-Corporate Black Hills Power and Light Company Administration and Assistant to the CEO
Kay S. Jorgensen Thomas M. Ohlmacher Owner - Jorgensen-Thompson Vice President-Power Supply Creative Broadcast Services; and South Dakota Legislative Representative Lawrence County, South Dakota
Thomas J. Zeller Mark T. Thies President Controller RE/SPEC Inc.
Kyle D. White Vice President-Energy Services Black Hills Power and Light Company