ITEM 1. BUSINESS GENERAL
Incorporated under the laws of South Dakota in 1941, the Company is an energy services company primarily consisting of three principal businesses: electric, coal mining and oil and gas production. 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 services and products. 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 and its oil and gas exploration and production through Western Production.
Black Hills Power is engaged in the generation, purchase, transmission, distribution and sale of electric power and energy to approximately 55,600 customers in 11 counties in western South Dakota, northeastern Wyoming and southeastern Montana, 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.
Information as to the continuing lines of business of the Company for the calendar years 1994-1996 is as follows:
For additional information relating to the Company's operations 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 303 megawatts was reached in July 1996. Approximately 45 megawatts of additional load commenced January 1, 1997, when Black Hills Power began serving MDU's 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 a member of a power pool.
Black Hills Power owns coal-fired generating units having a summer capability rating of 214 megawatts and 77 megawatts of oil-fired diesel and combustion turbines for peaking and standby use. Black Hills purchases additional resources from three contracts with Pacific Power: the Pacific Power Colstrip Contract, from which it purchases 75 megawatts of baseload power; the Reserve Capacity Integration Agreement, from which 33 megawatts of additional reserve capacity is available; and the Pacific Power Capacity Contract, under which Black Hills Power has options to be exercised seasonally to purchase up to 60 megawatts of capacity.
PACIFIC POWER COLSTRIP CONTRACT
This contract 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. 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, together with a fixed payment for transmission. The Company has incurred capacity charges of $17,850 per megawatt month and an average energy charge of $13.80 per megawatt hour over the last three years of this agreement with a 57 percent load factor. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-BUSINESS OUTLOOK STATEMENTS.)
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 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 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 the Pacific Power Colstrip Contract) 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 price is 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 and 2 percent increase in customers in 1996 and 1995, respectively, the economy in and around Black Hills Power's service territory is believed by management to be strong. 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. 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 the City of Gillette its first 23 megawatts of capacity requirements and the associated energy. The most recent average annual capacity factor for this 23 megawatt demand has been approximately 90 percent. Sales to Gillette represented 10.6 percent of total firm energy sales and 7.1 percent of revenue from total sales in 1996.
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 commencing January 1, 1997. The MDU Sheridan service territory has experienced a 45 megawatt winter peak and operates at a 60 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. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-BUSINESS OUTLOOK STATEMENTS.)
ADDITIONAL OFF-SYSTEM SALES
Black Hills power sold 249,100 and 60,575 megawatt hours of non-firm energy in 1996 and 1995, respectively. The selling price is based on spot market prices which have been low allowing only a small profit margin on the sales. The amount of energy available for non-firm sales should decrease in 1997 due to the serving of the MDU, Sheridan, Wyoming load. (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, among Black Hills Power, Basin Electric and distribution cooperatives serving in and around Black Hills Power's service territory, 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 Gillette's electric requirements purchased from sources other than Black Hills Power. The rates charged under the transmission contract with the cooperatives are fixed formula rates, and the transmission rates under the Gillette contract are subject to being determined by the FERC under a fully compensated just and reasonable standard. (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 5.6 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 $22,643,000 in 1996 or 72 percent of revenue for all coal sold by Wyodak Resources. The quantity of coal sold in 1996 for the Wyodak Plant was 2,125,000 tons, as compared to 1,880,000 tons sold in 1995. 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 17 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 3,243,000 tons of coal sold by Wyodak Resources in 1996, 1,315,000 tons were sold to Black Hills Power, 1,701,000 tons were sold to Pacific Power and 227,000 tons were sold to others.
Wyodak Resources' revenue from sales of coal to Pacific Power and Black Hills Power as compared to its revenue from all sales to other customers for the last three years was as follows:
(1) 1994 and 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 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 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
Oil and gas operations have not been a significant part of the Company's total operations. Net income and assets related to oil and gas operations have been 7 percent or less of the Company's consolidated amounts over the last 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 573,000 equivalent barrels of oil in 1996 comprised of 50 percent oil and 50 percent gas.
ENERGY MARKETING COMPANY
In 1996 Wyodak Resources participated in establishing a startup energy marketing company. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RESULTS OF OPERATIONS-Energy Marketing Company.)
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 required to obtain an air quality operating permit from the DEQ in 1997. Black Hill 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. Black Hills expects to receive operating source permits for all of its plants in calendar year 1997. Air quality permits for the Ben French Station was renewed in 1995 by the Department of Environmental and Natural Resources of South Dakota.
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 material 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 to 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 $430,000, of which amount $310,000 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 transformers in compliance with law as they are discovered.
Black Hills Power has removed all known PCB capacitors and PCB transformers from its system. Several years ago, Black Hills Power began a testing program of possible contaminated transformers. Of the original 11,581 transformers, less than 2,000 remain to be tested, and all testing will be completed in 1997.
High-risk areas have been tested, and statistically fewer than 5 percent or 100 PCB-contaminated transformers remain in service. However, release of PCB-contaminated fluids, especially any involving a fire or a release into a waterway, could result in substantial cleanup costs.
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, 1996, the number of employees of the Company (including Black Hills Power), Wyodak Resources and Western Production were 318, 49 and 36, respectively, for a total of 403 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 1996, 99 percent of the fuel used in electric generation, measured in Btus (British thermal units), was coal.
GENERATING UNITS (a)
(a) The Kirk Plant was placed in cold storage in 1995. The plant has now been fully depreciated as of December 31, 1996 and is no longer a viable resource and is therefore not listed above.
(b) These combustion turbines are those referenced by ITEM 1. BUSINESS-ELECTRIC POWER SUPPLY-Reserve Capacity Integration Agreement with Pacific Power.
(c) NS #2 was placed into commercial operation in August 1995. The plant's total production exceeds its name plate rating by 11 MWs.
(d) 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, 601 miles of 69 kV, 22 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 sale contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal are based upon five federal leases. The estimated recoverable coal from the five leases as of December 31, 1996 is 170,210,000 tons, of which 26,287,000 tons are committed to be sold to the Wyodak Plant and approximately 27,000,000 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. Each federal lease requires diligent development to produce at least one percent of all recoverable reserves within either 10 years from the respective dates of the 1983 leases or 10 years from the date of adjustment of the other leases. Each lease further requires a continuing obligation to mine, thereafter, at an average annual rate of at least one percent of the recoverable reserves. All of the federal leases 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 1992, the date of the logical mining unit. Even if federal coal leases are not mined out in 40 years, the federal coal is likely to be available for further lease after the 40 years. Wyodak Resources' current coal agreements require production which should be sufficient to satisfy the diligent development and continual operation requirements of present law. Wyodak Resources will require additional coal sales in order to mine all of its federal coal within the 40 year requirement.
The law, which requires that an owner of land that is primarily devoted to agriculture must approve a reclamation plan before the state will approve a permit for open pit mining, affects approximately 3,100,000 tons of the recoverable coal. 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 will increase Wyodak Resources reserves to approximately 300 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 and BUSINESS OUTLOOK STATEMENTS.)
OIL AND GAS PROPERTIES
Western Production operates 277 wells as of December 31, 1996. The vast 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 120 producing properties located in the western United States. Western Production owns a 44.7 percent interest in a natural gas processing plant also located at the Finn Shurley Field.
Western Production participated in the drilling of 52 exploratory and development wells in 1996. Western Production's average working interest in such wells was 13 percent, or 7.0 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. Thirty- five out of the 52 wells drilled in 1996 were completed as producing wells for an overall drilling success rate of 67 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, 1996, 1995 and 1994, 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
Under the provisions of Rule 888, which was adopted by the FERC in 1996, the Company has filed its open access transmission rates for wholesale wheeling. In the filing, Black Hills Power did not allocate the capital costs of that portion of its transmission system utilized by Basin Electric and its member rural electric distribution cooperatives. Under the long-term transmission agreement between the Company and the rural electric cooperatives, terminating December 31, 2020 (See ITEM 1. BUSINESS-ELECTRIC SERVICE TERRITORY AND SALES-Transmission Service Sales.), the rural electric cooperatives pay approximately $1,000,000 less than a fully allocated cost of its use of the transmission system but also are prohibited from using the system other than to serve its own retail customers. Therefore, in order to fully recover its costs of the transmission system in rates, Black Hills Power applies the revenue credit method, which excludes the cooperatives' use from the capital costs allocations but credits all revenues paid by the cooperatives against the full revenue which Black Hills Power must collect in order to earn a just and reasonable rate on its investment in its transmission system. Both the South Dakota and Wyoming regulatory commissions have in the past allowed Black Hills Power to use the revenue credit methodology. The issue has never been fully litigated in a contested case.
However, in Black Hills Power's transmission filing with the FERC under Rule 888, the City of Gillette, Wyoming (Gillette) has moved to intervene and answer the Company's FERC transmission filing by contending that the revenue credit method is not fair to Gillette for the transmission service provided by the Company to deliver electric power and energy purchased from sources other than the Company.
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 Basin Electric and other distribution 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 cooperatives' use of that 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. If Black Hills Power is unsuccessful in obtaining a reformation of the cooperatives' transmission agreement and Gillette's position is sustained by the FERC, Black Hills Power will not be able to fully recover its transmission costs from Gillette and future third-party wholesale users of its transmission system. 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. In the past, the state jurisdictions have recognized the revenue credit method of incorporating the Black Hills Power and cooperatives transmission agreement, thereby allowing Black Hills Power to recover its full costs of its transmission system. However, the Company can give no assurances as to whether the FERC or the state regulatory commissions will allow Black Hills Power to recover its full cost of its transmission system in view of the cooperatives' transmission agreement.
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 1996.
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 6,967 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 1997 meeting, the Board of Directors raised the quarterly dividend to 35.5 cents per share, equivalent to an annual increase of 4 cents per share. This regular quarterly dividend is payable March 1, 1997. 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 were as follows:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following data was derived from the Company's audited financial statements.
Quarterly financial data for the years indicated are summarized as follows:
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 1994 through 1996 were primarily for the replacement of equipment, modernization of facilities and for oil and gas investments. The primary capital requirements of the Company for the past three years were as follows:
Capital requirements for projected construction, capital improvements and oil and gas investments 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. WYGEN, Inc., DAKSOFT, 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. Enserco was formed in 1996 as an energy marketing company.
The electric operations is the only segment of the Company's business with long-term debt. Long-term debt sinking fund requirements are: $1,534,000 in 1997, $1,331,000 in 1998 and $1,330,000 in 1999.
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, 1996, accrued reclamation costs were approximately $16,300,000 which includes $7,957,000 for the 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 chose the open market purchase option for all of 1996 and 1995. The Company issued 112,578 new shares under the Plan in 1994. Proceeds from the sale of new shares were used to finance capital expenditures.
The Company filed a Form S-3, shelf registration in 1994 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 $45,000,000 bond issue has a 30-year life with an 8.3 percent rate of interest; 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 Company also issued $3,000,000 of Environmental Improvement Revenue Bonds in 1994 with a variable rate of interest which is currently reset weekly. The average interest rate applied to the bonds was 3.8 percent, 4.2 percent and 3.5 percent in 1996, 1995 and 1994, respectively. The Company has the option to remarket the environmental bonds on a short-term or long-term basis depending on the remarketability of the bonds. Proceeds from all of the above bond issues were used to finance NS #2. These additional financings increased the debt component of the Company's capital structure from 34 percent at December 31, 1993 to 46 percent at December 31, 1996. 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. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-RESULTS OF OPERATIONS-Independent Power Business.)
The Company also completed the refinancing of the $12,200,000, City of Gillette Pollution Control Revenue Bonds during 1994. The new bonds were issued in July 1994 at 7.5 percent, as agreed to in a 1992 forward refunding agreement, and the Series 1984 bonds were called and redeemed on August 1, 1994 at 102 percent of par.
The Company had $12,000,000 of unsecured short-term lines of credit at December 31, 1996 and $36,000,000 at December 31, 1995, which provide for interim borrowings and the opportunity for timing of permanent financing. Borrowings outstanding under these lines of credit were $120,000 and $575,000 as of December 31, 1996 and 1995, respectively. The weighted average interest rate on these borrowings at December 31, 1996 and 1995 was 8.0 percent and 7.4 percent, respectively. There are no compensating balance requirements associated with these lines 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, 1996, 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 remained 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 will increase the Company's reserves from 170 million tons to approximately 300 million tons and includes a train loadout facility, maintenance and processing facilities and a developed open pit.
The purchase price consists 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.
The acquisition is 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. Upon such approval and to meet minimum production limitations under the modified LMU, Wyodak Resources will relinquish certain existing federal leases; but with the newly acquired Clovis Point Mine, Wyodak Resources will increase its coal reserves from 170 million to approximately 300 million tons. The Company expects to receive the BLM approval by mid-1997. The Board of Land Commissioners of the State of Wyoming has approved the transfer of the state lease. Wyodak Resources has had extensive meetings with the BLM concerning the approval of the transfer of the federal lease and the modified LMU. The BLM has completed its initial review of the LMU. All communications with the BLM indicate that the BLM will approve the transfer and the LMU. The modified LMU meets all requirements of the laws and regulations for an LMU. Wyodak Resources is qualified to receive additional federal coal leases and meets all of the laws and regulations to hold the coal reserves underlying the federal lease to be assigned. Based on the Company's review of the law and regulations and the precedents of the BLM approving LMUs of other applicants, the Company concluded that the approvals were perfunctory and recorded the acquisition and associated liability at $7,957,000. The Company is not aware of any event or any likelihood of any event that would prevent the transfer of the federal lease and the approval of the modified LMU. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-BUSINESS OUTLOOK STATEMENTS under this Item 7.)
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, 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 sales to MDU for its Sheridan, Wyoming, service territory. (See ITEM 1. BUSINESS-ELECTRIC SERVICE TERRITORY AND SALES-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.
Black Hills Power is undertaking during the freeze period 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.)
The rate settlements resulted in the inclusion of NS #2 into Black Hills Power's rate base without any disallowance.
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 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 power sales agreement to the City of Gillette and the MDU contract, 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 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. 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 Polices 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.)
Black Hills Power's success in constructing NS #2 and getting it into rate base was unusual for this period of time. The isolated area in which Black Hills Power serves, the need for generation internal to its system to support the limited transmission system and the Company's control of its fuel supply at the mine site allowed Black Hills Power to satisfy regulators that constructing NS #2 was the least cost of any alternative, including purchased power. In the future, however, because of the competitive forces described herein, it will become increasingly difficult for any public utility to build base load generation and expect to pass those costs on to its customers under the traditional rate base methodology. 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 and for the City of Gillette, Wyoming through contracts. 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 are 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 were formerly captive 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 and the end of exclusive franchised service territories will come. 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, neither South Dakota nor Wyoming have had any legislative activity regarding retail wheeling, however 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 investment due to competition should be allowed payment for such 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 effect 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 1996 due to an increase in oil and gas prices, record coal production and strong growth in electric sales. Consolidated net income for 1996 was $30,252,000 compared to $25,590,000 in 1995 and $23,805,000 in 1994 or $2.10 per average common share in 1996, $1.78 per average common share in 1995 and $1.66 per average common share in 1994. This equates to a 15.7 percent return on year-end common equity in 1996, 14.0 percent in 1995 and 13.6 percent in 1994. Consolidated net income includes noncash earnings of $3,645,000 and $2,371,000 for allowance for equity funds used during construction in 1995 and 1994, respectively.
Consolidated revenue and income provided by the three businesses as a percentage of the total were as follows:
Dividends paid on common stock totaled $1.38 per share in 1996. This reflected increases approved by the Board of Directors from $1.34 per share in 1995 and $1.32 per share in 1994. 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 2.5 percent and the payout ratio for 1996 was 66 percent.
In January 1997 the Board of Directors increased the quarterly dividend 2.9 percent to 35.5 cents per share. If this dividend is maintained during 1997, the increase will be equivalent to $1.42 per share, an annual increase of 4 cents per share.
ELECTRIC OPERATIONS
Electric revenue increased 9.1 percent in 1996 compared to a 3.8 percent increase in 1995 and a 6.7 percent increase in 1994. Firm kilowatthour sales increased 3.9 percent in 1996 compared to a 0.5 percent increase in 1995 and a 2.7 percent increase in 1994 and have averaged an annual 2.4 percent growth rate over the last three years.
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 kilowatthour sales was caused by a one percent increase in the number of customers served and adverse weather conditions. Degree days, which is a measure of weather trends, were 15 percent above last year and 14 percent above normal.
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. The residential sector showed a 1.8 percent growth in the number of customers and a 4.1 percent growth in kilowatthour sales. The commercial sector showed a 2.6 percent growth in the number of customers and a 3.6 percent growth in kilowatthour sales. 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. Homestake Mining Company, representing 10.5 percent of firm kilowatthour sales, purchased 7.7 percent less energy in 1995 by continuing to concentrate on more efficient production areas. The South Dakota Cement Plant, representing 6.3 percent of firm kilowatthour sales, purchased 12.5 percent less energy than the previous year because of a decrease in cement production and sales and the installation of more efficient equipment.
The increase in revenue in 1994 was due to the 2.7 percent increase in firm kilowatthour sales and an increase in the fuel and purchased power adjustment passed on to electric customers. The increase in purchased power costs was primarily due to replacement power purchased while the Wyodak Plant was out of service for maintenance.
Revenue per kilowatthour sold was 5.8 cents in 1996 compared to 6.1 cents in 1995 and 1994. The number of customers in the service area increased to 55,601 in 1996 from 55,018 in 1995 and 53,959 in 1994. 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 non-firm sales in 1996 and 60,575 megawatt hours in 1995. Excluding non-firm sales the rate per kilowatthour sold was 6.5 cents in 1996 and 6.3 cents in 1995.
Operating expenses have remained fairly stable over the last three years. 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, 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 impact on the consolidated financial statements.
Depreciation expense increased 35 percent in 1996 related to the depreciation on NS #2 and accelerated depreciation which was taken on 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 291 MWs established in January 1996 and a summer peak of 303 MWs established in July 1996. 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.
In addition to the above forecast for normal growth, the Company expects to have an additional 14 percent growth in firm sales and an additional 40 to 45 MW of demand in 1997 as a result of serving the MDU Sheridan, Wyoming, energy requirements. (See ITEM 1. BUSINESS-ELECTRIC SERVICE TERRITORY AND SALES-Wholesale to MDU.)
COAL MINING OPERATIONS
Revenue increased 4.8 percent in 1996 and 4.5 percent in 1995 and decreased 4.1 percent in 1994 due to a 10.5 percent and a 5.0 percent increase in tons of coal sold in 1996 and 1995, respectively, and a 7.6 percent decrease in 1994. Wyodak Resources had record coal production of 3,243,000 tons in 1996. The increase in revenue in 1996 and 1995 was partially offset by a decrease in the price of coal charged to the utility's operations. (See explanation of the change in coal pricing methodology under Electric Operations.) The decrease in tons of coal sold in 1994 was caused by the Wyodak Plant being out of service for five weeks of scheduled maintenance. Operating expenses increased 8.1 percent in 1996 and 5.7 percent in 1995 reflecting the increase in tons of coal sold. Operating expenses decreased 4.0 percent in 1994 reflecting the decrease in tons of coal mined offset by an increase in depreciation expense.
Non-operating income was $2,725,000 in 1996 compared to $2,279,000 in 1995 and $1,750,000 in 1994. Non-operating income includes gains or losses on sale or disposal of property and equipment, a coal contract settlement from Grand Island, Nebraska 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. Non-operating income decreased in 1994 due to a decrease in interest income attributable to lower interest rates.
Wyodak Resources will experience a decrease in coal sales in 1997 unless a new coal sale is made. The Wyodak Plant is scheduled to be out of service for maintenance for approximately 12 days in 1997 which will result in approximately a 70,000 ton reduction in coal sales and the South Dakota Cement Plant which purchased 119,000 tons of coal in 1996 canceled its contract in October 1996.
OIL AND GAS PRODUCTION
Although the oil and gas operations showed a 67 percent increase in earnings in 1996, it is not a significant part of the Company's total operations. Net income and assets related to oil and gas operations have been 7 percent or less of the Company's consolidated amounts over the last three years.
Revenue is primarily comprised of oil and gas sales and is supplemented by field services in eastern Wyoming. Equivalent barrels of oil sold was 569,000 barrels in 1996, 599,000 barrels in 1995 and 624,000 barrels in 1994. The average sales price of oil per barrel was $21.09 in 1996 compared to $17.09 in 1995 and $15.56 in 1994. The average sales price per mcf of gas was $2.05 in 1996 compared to $1.46 in 1995 and $1.81 in 1994. Western Production's production expenses increased 1.1 percent in 1996, decreased 7.1 percent in 1995 and increased 2.5 percent in 1994.
During 1995 Western Production sold its interest in several wells with estimated net remaining reserves of 208,000 barrels of oil equivalents for approximately $2,175,000. The impact of this sale reduced 1995 production by approximately 100,000 equivalent barrels.
Production expenses decreased in 1995 reflecting lower depletion expense associated with higher oil prices and a successful drilling program. Production expenses increased in 1994 primarily due to increased depletion expense as a result of increased oil and gas production and lower oil and gas prices. Western Production recognized $3,434,000, $3,730,000 and $4,450,000 of depletion expense in 1996, 1995 and 1994, 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 and development activities are conducted or additional proved reserves are acquired. Western Production has been in an active exploration and development drilling program during the past three years. Western Production participated in the drilling of 52 wells in 1996 with an average working interest of 13 percent or 7.0 net wells and 22 wells in 1995 with an average working interest of 21 percent or 4.7 net wells. Thirty-five of the 52 wells were completed in 1996 as producing wells, and 14 of the 22 wells were completed as producing wells in 1995, for an overall success rate of 67 percent and 64 percent, respectively. Much of the production growth in 1994 was the result of a horizontal drilling program in the Austin Chalk formation in Texas. 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 2.4, 1.6 and 1.4 million barrels of oil and 11.0, 7.7 and 9.1 billion cubic feet of natural gas as of December 31, 1996, 1995 and 1994, respectively. 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. The increase in reserves as of December 31, 1994 was primarily due to the active drilling program and a production acquisition in South Texas.
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 would not commence construction of the Wygen Plant until such time that WYGEN receives sufficient power purchase contracts from responsible entities which would be required to obtain the necessary financing. It is anticipated that the WYGEN Plant will be financed primarily with non-recourse debt secured only by the WYGEN Plant assets. The wholesale market is currently highly competitive (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-COMPETITION IN THE ELECTRIC UTILITY BUSINESS.), and the Company can give no assurances that the project is feasible at this time.
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 interests 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.
ENERGY MARKETING COMPANY
In 1996 Wyodak Resources, with the participation of three individuals, formed an energy marketing startup company under the name of Enserco Energy, Inc., 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, whereby 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 sale 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. 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.
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 affiliated with an energy marketing company, 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.
Enserco is a startup company and has not as yet realized a profit. Its operations are not material to the Company at this time.
As an energy marketing company, Enserco anticipates generating large amount of revenue and corresponding expense related to buying and selling energy products. Associated with the purchase and sale of energy products, Enserco 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 Enserco have adopted a risk management policy and established a risk management committee to further mitigate risk associated with the sale and purchase of energy products. Some purchasers and sellers with whom Enserco transacts 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 Enserco and corresponding loss to Wyodak Resources as it concerns the outstanding letters of credit.
OTHER SEGMENTS OF BUSINESS
DAKSOFT, Inc., a subsidiary of Wyodak Resources, was formed in 1994 to develop and market internally generated computer software associated with the Company's business segments. DAKSOFT entered into a multi-year enhancement and sales contract in 1995 totaling $700,000. The revenue from this contract is earned as the product enhancement occurs. Approximately $370,000 and $290,000 of revenue was recognized in 1996 and 1995, respectively. 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, Enserco, DAKSOFT and Landrica were not material to the Company.
NEW ACCOUNTING PRONOUNCEMENT
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 are not expected to have a material impact on the Company's financial position or results of operations.
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 COLSTRIP CONTRACT
The Pacific Power Colstrip Contract 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, commencing January 1, 2000, to achieve some cost reductions through a Restated Agreement recently entered into between Pacific Power and the Company.
The Company has been able to utilize the 75 MW resource from the Pacific Power Colstrip contract at a load factor of only 57 percent. The Company anticipates better 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 Colstrip contract under which Black Hills Power has the right without any additional charge to cause the power and energy to be delivered at any point on Pacific Power's transmission system (defined as both Pacific Power owned and contract transmission paths) where capacity is available.
Black Hills Power and Pacific Power have recently entered into an agreement (Restated Agreement) that restates and amends the Colstrip contract with an effective date of January 1, 2000 (Effective Date). The Restated Agreement is subject to the acceptance or approval of the FERC, for which application will not be filed until 90 days prior to the Effective Date. Under the Restated Agreement, commencing with the Effective Date, the rate to be taken times Pacific Power's investment in the Colstrip units to determine the capacity charges to be paid by Black Hills Power will be based each month thereafter on Pacific Power's then most recent capital structure and cost of capital as determined by the FERC, rather than the formula under the present contract, which fixes Pacific Power's capital structure ratios and fixes rates of 12.8 and 13.3 percent for the taxable debt and preferred stock components, respectively. In addition, the Restated Agreement, commencing with the Effective Date
and continuing for a ten-year period thereafter, will grant Black Hills Power a monthly credit against capacity charges of $117,525. The Restated Agreement will further increase the assumed amount of Pacific Power's capacity from the Colstrip units from 142.5 MW to 150 MW, thereby reducing the price of each unit of capacity, and for the purposes of determining variable costs per kilowatthour incorporates an assumption that the Colstrip Units operated at an 80 percent load factor. In the recent past, the Colstrip units have been taken off line at times that market energy was below the incremental production costs to operate the units. Because of these amendments, the Company anticipates that commencing with the Effective Date of January 1, 2000, Black Hills Power will realize a 10 to 20 percent reduction in the cost of capacity and energy from this contract. However, the Company cannot predict the effects of inflation and other factors internal to Pacific Power's business and operations which are beyond the control of the Company and which may cause unexpected changes in Pacific Power's capital structure and debt, preferred stock and equity costs. If these increased capital costs are unexpectedly high after January 1, 2000, such costs could have a material adverse effect on the charges paid by Black Hills under the Restated Agreement as compared to what would have been charged under the present agreement. Since the Restated Agreement is likely to provide a reduction to the rates paid by Black Hills Power, FERC's acceptance or approval of the Restated Agreement is probable, but the Company cannot predict future regulatory decisions or the law, regulations or prior precedential decisions which will affect such decision at the time it is made.
WHOLESALE TO MDU
Black Hills Power believes that the MDU sale will have a positive effect on earnings. However, 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. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-COMPETITION IN ELECTRIC UTILITY BUSINESS.)
FUTURE ELECTRIC SALES
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 COAL SALES
Because of an acquisition of an unit train load-out, Wyodak Resources expects to increase its market opportunities by the acquisition of the Clovis Point Mine properties. However, the approximately 8,000 Btu per pound content of the Powder River Basin coal at the location of 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 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 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. During that five years, Black Hills Power will endeavor to increase its earnings through additional sales and costs containment. Based upon the FERC's expressed positions concerning open access transmission regulations, electric utilities which will lose investment due to competition should be allowed payment for such 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 this excess capacity will be more fully utilized within the next five years. 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 settlement made with the South Dakota and Wyoming Commissions is 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.
RISKS AND UNCERTAINTIES
The above statements contained in this Business Outlook Statements are forward-looking statements that 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 natural gas and coal; government regulations of the environment, especially to the extent to which further 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 29
Consolidated Statements of Income and Retained Earnings for the three years ended December 31, 1996 30
Consolidated Statements of Cash Flows for the three years ended December 31, 1996 31
Consolidated Balance Sheets as of December 31, 1996 and 1995 32
Consolidated Statements of Capitalization as of December 31, 1996 and 1995 33
Notes to Consolidated Financial Statements 34
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, 1996 and 1995, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota, January 30, 1997
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
BLACK HILLS CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS
BLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS
BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CAPITALIZATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1996, 1995 AND 1994
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BUSINESS DESCRIPTION
Black Hills Corporation and its subsidiaries operate in three primary business segments: electric, coal mining and oil and gas production. The Company's electric utility operation is engaged in the generation, purchase, transmission, distribution and sale of electric power and energy in western South Dakota, northeastern Wyoming and southeastern Montana. Sales of electric power to the three largest electric customers represented 17 percent of the Company's electric revenue in 1996, 18 percent in 1995 and 20 percent in 1994. 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 65 percent of the coal mining operation's sales are to the Wyodak Plant. Sales of coal to the Company and to PacifiCorp represent 94 percent of total coal sales in 1996. The Company's oil and gas exploration and production business operates and has working interests in properties located in the western United States.
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 $10,384,000, $10,498,000 and $9,445,000 in 1996, 1995 and 1994, 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, "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 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 3.4 percent in 1996, 3.0 percent in 1995 and 3.1 percent in 1994. Composite depreciation rates for other property were 7.7 percent, 8.9 percent and 10.3 percent in 1996, 1995 and 1994, respectively. Depletion of coal and oil and gas properties is computed using the cost method for financial reporting and the gross income method or cost method, whichever is applicable, for federal income tax reporting.
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 and the City of Gillette Wholesale Tariff contain clauses that allow recovery of certain fuel and purchased power costs in excess of the level of such costs included in base rates. These cost adjustment tariffs are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses 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 to MDU 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 EXPLORATION
The Company accounts for its oil and gas exploration activities under the full cost method. Capitalized costs associated with unsuccessful wells are amortized over future periods as the reserves from successful wells are produced.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction (AFDC) represents the approximate composite cost of borrowed funds and a return on capital used to finance construction expenditures and is capitalized as a component of the electric property. The AFDC was computed at an annual composite rate of 10.0 percent in 1996, 10.2 percent in 1995 and 8.7 percent in 1994.
INCOME TAXES
Deferred taxes are provided on all significant temporary differences, principally depreciation. Investment tax credits have been deferred in the electric operation and the accumulated balance is amortized as a reduction of income tax expense over the useful lives of the related electric property which gave rise to the credits.
NEW ACCOUNTING PRONOUNCEMENT
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 are not expected to have a material impact on the Company's financial position or results of operations.
(2) CAPITAL STOCK
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 these plans under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized.
Had compensation cost for these plans been determined consistent with SFAS No. 123, the Company's net income and earnings per share would have been reduced to the following pro forma amounts;
1996 1995 (in thousands) Net income: As reported $30,252 $25,590 Pro forma $30,215 $25,542
1996 1995 Earnings per share: As reported $2.10 $1.78 Pro forma $2.09 $1.77
The Company issued 25,247 and 38,599 shares of common stock under the ESPP Plan in 1996 and 1995, respectively. At December 31, 1996, 206,168 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 of shares sold in 1996 was $22.50.
The Company may grant options for up to 200,000 shares of common stock under the 1996 Stock Option Plan. The Company has granted options on 55,800 shares through December 31, 1996. The option exercise price equals the fair market value of the stock on the day of the grant. The 55,800 options granted in 1996 have an exercise price of $25. The 1996 options granted vest one-third a year for three years and all expire after ten years. 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 1996 grants: risk free interest rate of 6.15 percent; expected dividend yields of 5.5 percent; expected life of 10 years; and expected volatility of 18 percent. The weighted average fair value of the 1996 options is 50 cents per option.
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 1996 and 1995 and issued 112,578 new shares under the Plan in 1994. At December 31, 1996, 860,531 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: $1,534,000 in 1997, $1,331,000 in 1998, $1,330,000 in 1999, $1,330,000 in 2000 and $3,029,000 in 2001.
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, 1996. Borrowings outstanding under these lines of credit were $120,000 and $575,000 as of December 31, 1996 and 1995, respectively. The weighted average interest rate on these borrowings at December 31, 1996 and 1995 was 8.0 percent and 7.4 percent, respectively. 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, 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, 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, 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 PacifiCorp an 80 percent interest in the Wyodak Plant (the Plant), a 330 megawatt coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp 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, 1996, the Company's investment in the Plant included $73,121,000 in electric plant and $23,824,000 in accumulated depreciation. The Company's share of direct expenses of the Plant were $6,458,000, $6,503,000 and $6,945,000 for the years ended December 31, 1996, 1995 and 1994, respectively, and are 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 PacifiCorp 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, 1996, approximately 26,287,000 tons were covered under this agreement. Wyodak Resources' sales to the Plant were $22,643,000, $20,224,000 and $20,671,000 for the years ended December 31, 1996, 1995 and 1994, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
MDU POWER SALE
During 1994 the Company entered into a Power Integration Agreement with MDU. The agreement provides that for a period of 10 years commencing January 1, 1997, the Company will supply up to 55 megawatts of electric power and associated energy required by MDU for its Sheridan, Wyoming, service territory. MDU's Sheridan service area has experienced a 45 megawatt peak and a load factor of approximately 60 percent.
COAL OBLIGATIONS
In addition to the 26,287,000 tons of coal reserved under the agreement to supply coal to the Wyodak Plant, Wyodak Resources has reserved 27,105,000 tons of coal under existing contracts.
COAL LEASES
Wyodak Resources' mining rights to its coal are based upon five federal leases. The federal leases provide for a royalty of 12.5 percent of the selling price of the coal. Wyodak Resources paid federal royalties in the amount of $3,995,000, $2,323,000 and $3,456,000 in 1996, 1995 and 1994, 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.
PACIFICORP PURCHASE POWER AGREEMENT
In 1983 the Company entered into a 40 year power agreement with PacifiCorp providing for the purchase by the Company of 75 megawatts of electric capacity and energy from PacifiCorp's system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants. Costs incurred under this agreement were $19,777,000, $20,689,000 and $23,132,000 in 1996, 1995 and 1994, 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 will increase Wyodak Resources' reserves from 170 million tons to approximately 300 million tons and includes a train loadout facility, maintenance and processing facilities and a developed open pit.
The purchase price consists 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.
The acquisition is subject to certain federal and state approvals. Based on the Company's review of the law and regulations and the precedents of the Bureau of Land Management approving logical mining units of other applicants, Wyodak Resources determined that the approvals were perfunctory and recorded the acquisition and associated reclamation liability at $7,957,000.
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, 1996, accrued reclamation costs were approximately $16,300,000 which includes $7,957,000 for the Clovis Point Mine Acquisition.
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 of each year was as follows:
1996 1995 (in thousands)
The change in the assumed discount rate from 8.0 percent in 1994 to 7.5 percent in 1995 resulted in an increase in the accumulated benefit obligation and projected benefit obligation of $1,381,000 and $1,923,000, respectively.
The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. Expenses recognized under the plans were $498,000, $350,000 and $401,000 in 1996, 1995 and 1994, 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:
1996 1995 (in thousands)
For measurement purposes, a 10 percent annual rate of increase in healthcare benefits was assumed for 1997; 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 $143,000 annually or 22.2 percent. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7.5 percent.
(9) 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.
Income tax expense for the years indicated was:
The temporary differences which gave rise to the net deferred tax liability at December 31, 1996 and 1995 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 422 producing oil and gas properties in seven states. Western Production also holds leases on approximately 42,400 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, 1996, 1995 and 1994, 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 three primary segments of the Company's business are its electric, coal mining and oil and gas production operations. The following table summarizes certain information specifically identifiable with each segment as of or for the years ended December 31.
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
TAXES OTHER THAN INCOME TAXES
FINANCIAL STATISTICS
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 20, 1997.
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, 50, Chairman, President and Chief Executive Officer of Black Hills Corporation Mr. Landguth was elected to his present position in January 1991.
Roxann R. Basham, 35, Secretary and Treasurer Ms. Basham was elected to her present position January 1, 1993. She had served as Assistant Secretary/Treasurer since May 1991 and as Financial Analyst since February 1985.
Dale E. Clement, 63, Senior Vice President - Finance Mr. Clement was elected to his present position in September 1989.
David R. Emery, 34, 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, 37, Vice President - Development and Controller Mr. Fish was elected to his present position in October 1996. He has served as Controller since 1988.
Everett E. Hoyt, 57, President and Chief Operating Officer of Black Hills Power Mr. Hoyt was elected to his present position in October 1989.
James M. Mattern, 42, Vice President - Administration Mr. Mattern was elected to his present position on August 1, 1994. He had served as Rapid City Area Manager since January 1994 and Director of Human Resources since 1991.
Thomas M. Ohlmacher, 45, 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.
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 20, 1997.
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 20, 1997.
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 20, 1997.
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 24,1994 (Exhibit 3(i) to Form 8-K dated June 7, 1994, File No. 1-7978).
3(b) Bylaws dated January 30, 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).
*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) Coal Supply Agreement and First Amendment dated September 1, 1977, between the Company and Wyodak Resources Development Corp. (Exhibit 5(g) to Form S-7, File No. 2-60755). Second Amendment to Coal Supply Agreement dated November 2, 1987 (Exhibit 10(f) to Form 10-K for 1987). 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 Lease dated May 1, 1959, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 5(i) to Form S-7, File No. 2-60755). Modified coal lease dated January 22, 1990, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(h) to Form 10-K for 1989).
*10(d) Coal Lease dated April 1, 1961, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 5(j) to Form S-7, File No. 2-60755). Modified coal lease dated January 22, 1990, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(i) to Form 10-K for 1989).
*10(e) Coal Lease dated October 1, 1965, between Wyodak Resources Development Corp. and the Federal Government, as amended (Exhibit 5(k) to Form S-7, File No. 2-60755). Modified coal lease dated January 22, 1990, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(j) to Form 10-K for 1989).
*10(f) Participation Agreement dated May 16, 1978, and various related agreements dated June 8, 1978, including, without limitation, Lease Agreement, Amended and Restated Coal Supply Agreement, Coal Supply System Agreement and Security Agreement, and Real Estate Mortgage (all relating to the lease financing of the Wyodak Plant and the dedication by Wyodak Resources Development Corp. of coal deposits with respect thereto) filed pursuant to item 6(b) of Amendment No. 1 to Registrant's Current Report on Form 8-K for June 1978 and located in Commission File No. 2-4832. Further Restated and Amended Coal Supply Agreement dated May 5, 1987 (Exhibit 10(k) to Form 10-K for 1987).
*10(g) Power Sales Agreement dated December 31, 1983, between Pacific Power & Light Company and the Company (Exhibit 7(b) to Form 8-K for January 1984, File No. 0-0164).
*10(h) 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(i) Coal lease dated February 16, 1983, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(p) to Form 10-K for 1983).
*10(j) Coal lease dated September 28, 1983, between Wyodak Resources Development Corp. and the Federal Government (Exhibit 10(q) to Form 10-K for 1983).
*10(k) Indenture of Trust dated as of June 1, 1992, City of Gillette, Campbell County, Wyoming, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(n) to Form 10-K for 1992).
*10(l) Loan Agreement dated as of June 1, 1992, by and between City of Gillette, Campbell County, Wyoming, and the Company (Exhibit 10(o) to Form 10-K for 1992).
*10(m) Loan Agreement dated as of June 1, 1992, by and between Lawrence County, South Dakota and the Company (Exhibit 10(p) to Form 10-K for 1992).
*10(n) Indenture of Trust dated as of June 1, 1992, Lawrence County, South Dakota, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(q) to Form 10-K for 1992).
*10(o) Loan Agreement dated as of June 1, 1992, by and between Pennington County, South Dakota and the Company (Exhibit 10(r) to form 10-K for 1992).
*10(p) Indenture of Trust dated as of June 1, 1992, Pennington County, South Dakota, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(s) to Form 10-K for 1992).
*10(q) Loan Agreement dated as of June 1, 1992, by and between Weston County, Wyoming and the Company (Exhibit 10(t) to Form 10-K for 1992).
*10(r) Indenture of Trust dated as of June 1, 1992, Weston County, Wyoming, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(u) to Form 10-K for 1992).
*10(s) Loan Agreement dated as of June 1, 1992, by and between Campbell County, Wyoming and the Company (Exhibit 10(v) to Form 10-K for 1992).
*10(t) Indenture of Trust dated as of June 1, 1992, Campbell County, Wyoming, to Norwest Bank Minnesota, National Association, as Trustee (Black Hills Power and Light Company Project) (Exhibit 10(w) to Form 10-K for 1992).
*10(u) Second Restated Electric Power and Energy Supply and Transmission Agreement dated February 28, 1995, by and between the Company and the City of Gillette, Wyoming.
*10(v) 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(w) Compensation Plan for Outside Directors (Exhibit 10(bb) to Form 10-K for 1992).
*10(x) Retirement Plan for Outside Directors dated January 1, 1993 (Exhibit 10(cc) to Form 10-K for 1992).
*10(y) The Amended and Restated Pension Equalization Plan of Black Hills Corporation dated January 27, 1995.
10(z) Black Hills Corporation 1997 Executive Gainsharing Program.
10(aa) Black Hills Corporation 1997 Results Compensation Program.
*10(ab) The Amended and Restated Pension Plan of Black Hills Corporation.
*10(ac) Agreement for Supplemental Pension Benefit for Everett E. Hoyt dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for 1992).
*10(ad) Agreement for Supplemental Pension Benefit for Dale E. Clement dated December 19, 1991 (Exhibit 10(hh) to Form 10-K for 1992).
*10(ae) 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(af) Change in Control Agreements dated January 30, 1996 for Daniel P. Landguth, Dale E. Clement, Everett E. Hoyt, Thomas M. Ohlmacher, James M. Mattern, Roxann R. Basham and Gary R. Fish.
*10(ag) 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).
21 Subsidiaries of the Registrant.
23 Consent of Independent Public Accountants.
27 Financial Data Schedule.
* Exhibits incorporated by reference.
(b) No reports on Form 8-K have been filed in the quarter ended December 31, 1996. (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
Dated: March 7, 1997
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 7, 1997 Daniel P. Landguth (Chairman, Executive Officer President, and Chief Executive)
/s/ DALE E. CLEMENT Director and Principal March 7, 1997 Dale E. Clement (Senior Vice Financial Officer President - Finance)
/s/ GARY R. FISH Principal Accounting Gary R. Fish (Vice President - Officer March 7, 1997 Development and Controller)
/s/ ADIL M. AMEER Director March 7, 1997 Adil M. Ameer
/s/ GLENN C. BARBER Director March 7, 1997 Glenn C. Barber
/s/ BRUCE B. BRUNDAGE Director March 7, 1997 Bruce B. Brundage
/s/ JOHN R. HOWARD Director March 7, 1997 John R. Howard
/s/ EVERETT E. HOYT Director and Officer March 7, 1997 Everett E. Hoyt (President and Chief Operating Officer of Black Hills Power)
/s/ KAY S. JORGENSEN Director March 7, 1997 Kay S. Jorgensen
/s/ THOMAS J. ZELLER Director March 7, 1997 Thomas J. Zeller
EXHIBIT INDEX
EX-3(b) Bylaws dated January 30, 1997.
EX-10(z) Black Hills Corporation 1997 Executive Gainsharing Program.
EX-10(aa) Black Hills Corporation 1997 Results Compensation Program.
EX-21 Subsidiaries of the Registrant.
EX-23 Consent of Independent Public Accountants.