SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1996
______ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ___________ to ___________
Commission File Number 1-7978
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57709
Registrant's telephone number, including area code
(605) 348-1700
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common stock of $1.00 par value New York Stock Exchange
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
State the aggregate market value of the voting stock held by non-affiliates of
the Registrant.
At February 28, 1997 $399,347,864
Indicate the number of shares outstanding of each of the Registrant's classes
of common stock, as of the latest practicable date.
CLASS OUTSTANDING AT FEBRUARY 28, 1997
Common stock, $1.00 par value 14,456,723 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. Definitive Proxy Statement of the Registrant filed pursuant to Regulation
14A for the 1997 Annual Meeting of Stockholders to be held on May 20, 1997,
is incorporated by reference in Part III.
TABLE OF CONTENTS
PAGE
ITEM 1. BUSINESS..................................................4
GENERAL...............................................4
ELECTRIC POWER SUPPLY.................................4
ELECTRIC SERVICE TERRITORY AND SALES..................5
COMPETITION IN ELECTRIC UTILITY BUSINESS..............6
COAL SALES............................................7
OIL AND GAS OPERATIONS................................8
ENERGY MARKETING COMPANY..............................8
ENVIRONMENTAL REGULATION..............................8
EMPLOYEES............................................11
ITEM 2. PROPERTIES...............................................11
UTILITY PROPERTIES...................................11
MINING PROPERTIES....................................12
OIL AND GAS PROPERTIES...............................12
ITEM 3. LEGAL PROCEEDINGS........................................13
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..... 13
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS....................................14
ITEM 6. SELECTED FINANCIAL DATA..................................14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS....................15
LIQUIDITY AND CAPITAL RESOURCES......................15
RATE REGULATION......................................17
COMPETITION IN ELECTRIC UTILITY BUSINESS.............18
RESULTS OF OPERATIONS................................21
BUSINESS OUTLOOK STATEMENTS..........................26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..............29
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE....................47
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......47
ITEM 11. EXECUTIVE COMPENSATION...................................47
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT..................................47
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS...........47
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K....................................48
SIGNATURES.........................................................51
DEFINITIONS
WHEN THE FOLLOWING TERMS ARE USED IN THE TEXT THEY WILL HAVE THE MEANINGS
INDICATED.
TERM MEANING
Black Hills Power Black Hills Power and Light Company, the assumed business
name of the Company under which its electric operations are
conducted
Basin Electric Basin Electric Power Cooperative, Inc., a rural electric
cooperative engaged in generating and transmitting electric
power to its member RECs
Company Black Hills Corporation
Clovis Point Mine Clovis Point Mine refers to coal properties belonging to
Kerr-McGee Coal Corporation consisting of a federal coal
lease, a state coal lease and real property interests
including coal processing and rail loading facilities, all
of which Wyodak Resources has contracted to acquire.
DEQ Department of Environmental Quality of the State of Wyoming
FERC Federal Energy Regulatory Commission
MDU Montana-Dakota Utilities Co., a division of MDU Resources
Group, Inc.
NS #1 Neil Simpson Unit #1, a 20 megawatt coal-fired electric
generating plant owned by the Company and located adjacent
to the Wyodak Plant
NS #2 Neil Simpson Unit #2, an 80 megawatt coal-fired power plant
owned by the Company and located adjacent to the Wyodak
Plant and Neil Simpson Unit #1
Pacific Power PacifiCorp, which operates its electric utility operations
under the assumed names of Pacific Power and Utah Power
RECs Rural electric cooperatives, which are owned by their
customers and which rely primarily on the United States
for their financing needs
SDPUC The South Dakota Public Utilities Commission
WAPA Western Area Power Administration, an agency of the
Department of Energy of the United States of America
WPSC The Wyoming Public Service Commission
Western Production Western Production Company, a wholly owned subsidiary of
Wyodak Resources
Wyodak Resources Wyodak Resources Development Corp., a wholly owned
subsidiary of the Company
Wyodak Plant A 330 megawatt coal-fired electric generating plant which is
owned 20 percent by the Company and 80 percent by Pacific
Power and located near Gillette, Wyoming
PART I
ITEM 1. BUSINESS
GENERAL
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:
1996 1995 1994
(in thousands)
Revenue from sales to
unaffiliated customers:
Electric $118,508 $108,563 $104,431
Coal mining 20,931 19,372 19,149
Oil and gas 12,555 11,164 12,052
Revenue from intercompany
sales:
Electric $ 210 $ 220 $ 325
Coal mining 10,384 10,498 9,445
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:
Year Revenue from % Revenue Tons of Coal
Sale of Coal Derived from Sold
(in thousands) Black Hills (in thousands)
Power
1996 $31,315 33 3,243
1995 29,870 35 2,934
1994 28,594 33 2,796
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:
Year Revenue from Sales Revenue from Sales Revenue from All
To Pacific Power To Black Hills Sales
Power(1) to Unaffiliated
Customers
(includes Pacific
Power)
(in thousands)
1996 $19,189 $10,384 $20,931
1995 16,777 10,498 19,372
1994 16,887 9,445 19,149
(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:
Oil and Gas Gas Plant Field
Sales Revenue Services
(in thousands)
1996 $9,050 $875 $2,630
1995 7,449 762 2,953
1994 8,325 729 2,998
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. 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)
Name Plate
Year of Rating Principal
Installation (Kilowatts) Fuel
Osage Plant - Osage, Wyoming 1948-1952 34,500 Coal
Ben French Station - Rapid City,
South Dakota 1960 25,000 Coal
1965 10,000 Oil
1977-1979(b) 100,000 Oil or gas
Neil Simpson Station -
Gillette, Wyoming 1969 21,760 Coal
1995(c) 88,900 Coal
Wyodak Plant - Gillette,
Wyoming 1978(d) 72,400 Coal
-------
Total 352,560
(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. 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. 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. 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:
1st 2nd 3rd 4th
YEAR ENDED DECEMBER 31, 1996
Dividends paid per
share $0.345 $0.345 $0.345 $0.345
Common stock
prices -
High $26-1/4 $26-1/4 $26 $28-3/4
Low $23-1/4 $23-5/8 $22-3/4 $23-3/4
YEAR ENDED DECEMBER 31, 1995
Dividends paid per
share $0.335 $0.335 $0.335 $0.335
Common stock
prices -
High $24-1/8 $23-5/8 $25-7/8 $26-1/8
Low $20-5/8 $20-1/4 $19-3/4 $24-1/8
ITEM 6. SELECTED FINANCIAL DATA
The following data was derived from the Company's audited financial
statements.
YEARS ENDED DECEMBER 31
1996 1995 1994 1993 1992
(in thousands, except per share amounts)
Operating revenues $162,588 $149,817 $145,402 $139,373 $135,343
Net income 30,252 25,590 23,805 22,946 23,638
Per share of
common stock:
Earnings 2.10 1.78 1.66 1.66 1.73
Dividends paid 1.38 1.34 1.32 1.28 1.24
Total assets 467,354 448,830 436,877 352,853 330,202
Total net long-
term debt 164,691 166,069 128,925 85,274 88,816
Quarterly financial data for the years indicated are summarized as follows:
1st 2nd 3rd 4th
(in thousands, except per share amounts)
YEAR ENDED DECEMBER 31, 1996
Operating revenues $41,104 $37,783 $42,565 $41,136
Operating income 14,182 11,196 14,919 14,008
Net income 8,001 5,887 8,243 8,121
Earnings per share 0.55 0.41 0.57 0.57
YEAR ENDED DECEMBER 31, 1995
Operating revenues $35,939 $34,603 $39,061 $40,214
Operating income 9,573 8,948 11,626 12,015
Net income 5,999 5,642 6,932 7,017
Earnings per share 0.42 0.39 0.48 0.49
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:
1996 1995 1994
(in thousands)
Construction of NS #2 $ - $33,219 $73,984
Other property 24,576 18,676 29,075
additions
Common stock dividends 19,930 19,312 18,920
Maturities/redemptions 1,405 10,499 3,542
of long-term debt
------- ------- --------
$45,911 $81,706 $125,521
Capital requirements for projected construction, capital improvements and
oil and gas investments for the next three years are estimated to be as
follows:
1997 1998 1999
(in thousands)
Electric:
Production $ 1,643 $ 976 $ 1,226
Transmission 5,669 3,338 1,775
Distribution 7,281 7,949 7,622
General 1,540 1,853 2,218
------- ------- -------
16,133 14,116 12,841
Coal mining 1,770 1,576 2,489
Oil and gas 10,585 7,000 7,000
------- ------- -------
$28,488 $22,692 $22,330
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:
1996 1995 1994
Revenue:
Electric 73% 73% 72%
Coal mining 19 20 20
Oil and gas 8 7 8
--- --- ---
100% 100% 100%
=== === ===
Net Income:
Electric 61% 57% 54%
Coal mining 32 38 41
Oil and gas 7 5 5
--- --- ---
100% 100% 100%
=== === ===
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
1996 1995 1994
(in thousands)
Revenue $118,718 $108,783 $104,756
Operating expenses 79,628 80,540 79,680
-------- -------- --------
Operating income $ 39,090 $ 28,243 $ 25,076
======== ======== ========
Net income $ 18,333 $ 14,569 $ 12,852
======== ======== ========
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
1996 1995 1994
(in thousands)
Revenue $31,315 $29,870 $28,594
Operating expenses 19,081 17,644 16,694
------- ------- -------
Operating income $12,234 $12,226 $11,900
======= ======= =======
Net income $ 9,934 $ 9,737 $ 9,918
======= ======= =======
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
1996 1995 1994
(in thousands)
Revenue $12,555 $11,164 $12,052
Production expenses 9,574 9,471 10,196
------- ------- -------
Operating income $ 2,981 $ 1,693 $ 1,856
======= ======= =======
Net income $ 2,198 $ 1,320 $ 1,080
======= ======= =======
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. 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
Years ended December 31 1996 1995 1994
(in thousands)
Operating revenues:
Electric $118,718 $108,783 $104,756
Coal mining 31,315 29,870 28,594
Oil and gas 12,555 11,164 12,052
-------- -------- --------
162,588 149,817 145,402
-------- -------- --------
Operating expenses:
Fuel and purchased power 34,195 39,265 41,970
Operations and maintenance 30,343 28,523 28,713
Administrative and general 8,491 9,226 7,920
Depreciation, depletion
and amortization 22,794 19,660 17,601
Taxes, other than
income taxes 12,460 10,981 10,366
-------- -------- --------
108,283 107,655 106,570
-------- -------- --------
Operating income:
Electric 39,090 28,243 25,076
Coal mining 12,234 12,226 11,900
Oil and gas 2,981 1,693 1,856
-------- -------- --------
54,305 42,162 38,832
-------- -------- --------
Other income (expense):
Interest expense (13,942) (14,195) (10,339)
Investment income 1,373 1,368 1,631
Allowance for funds
used during construction 350 5,867 3,983
Other, net 1,744 1,125 93
-------- -------- --------
(10,475) (5,835) (4,632)
-------- -------- --------
Income before income taxes 43,830 36,327 34,200
Income taxes (13,578) (10,737) (10,395)
-------- -------- --------
Net income $ 30,252 $ 25,590 $ 23,805
======== ======== ========
Weighted average common
shares outstanding 14,440 14,409 14,339
Earnings per share of
common stock $ 2.10 $ 1.78 $ 1.66
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31 1996 1995 1994
(in thousands)
Balance, beginning of year $121,562 $115,284 $110,399
Net income 30,252 25,590 23,805
Cash dividends on common
stock ($1.38, $1.34 and
$1.32 per share,
respectively) (19,930) (19,312) (18,920)
-------- -------- --------
Balance, end of year $131,884 $121,562 $115,284
======== ======== ========
The accompanying notes to consolidated financial statements are an
integral part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Years ended December 31 1996 1995 1994
(in thousands)
Operating activities:
Net income $30,252 $25,590 $23,805
Principal non-cash items-
Depreciation, depletion and
amortization 22,794 19,660 17,601
Deferred income taxes
and investment tax credits 1,872 2,097 2,470
Allowance for other funds
used during construction (188) (3,645) (2,371)
Increase in receivables,
inventories and other
current assets (373) (669) (3,438)
Increase (decrease) in
current liabilities (1,412) (1,420) 5,054
Other, net 2,452 3,677 5,815
------- ------- -------
55,397 45,290 48,936
------- ------- -------
Investing activities:
Neil Simpson Unit #2
construction costs,
excluding allowance
for other funds used
during construction - (29,820) (71,956)
Other property additions,
excluding allowance for
other funds used
during construction (24,388) (18,430) (28,732)
Available for sale
securities purchased (40,894) (19,323) (41,923)
Available for sale
securities sold 36,189 36,941 46,964
------- ------- -------
(29,093) (30,632) (95,647)
------- ------- -------
Financing activities:
Dividends paid (19,930) (19,312) (18,920)
Common stock issued 511 654 2,436
Net short-term
borrowings (repayments) (475) (36,400) 25,250
Long-term debt issued 156 46,904 45,795
Long-term debt retired (1,405) (10,499) (3,542)
------- ------- -------
(21,143) (18,653) 51,019
------- ------- -------
Increase (decrease) in
cash and cash equivalents 5,161 (3,995) 4,308
Cash and cash equivalents:
Beginning of year 8,179 12,174 7,866
------- ------- -------
End of year $13,340 $ 8,179 $12,174
======= ======= =======
Supplemental disclosure of
cash flow information:
Assumption of
reclamation liability $ 7,957 $ - $ -
in acquisition of
Clovis Point properties
Cash paid during the
period for-
Interest $13,996 $12,901 $ 9,244
Income taxes $12,616 $ 7,775 $ 7,290
The accompanying notes to consolidated financial statements are an
integral part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31 1996 1995
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 13,340 $ 8,179
Securities available for sale 11,458 6,804
Receivables, net
Customers 12,961 13,339
Other 2,727 3,825
Materials, supplies and fuel 7,861 7,415
Prepaid expenses 2,650 1,247
-------- --------
50,997 40,809
-------- --------
Property and investments:
Electric 479,237 469,135
Coal mining 53,200 44,473
Oil and gas 45,336 40,704
Other 3,764 3,330
-------- --------
581,537 557,642
Less accumulated depreciation and (181,103) (164,383)
depletion
-------- --------
400,434 393,259
-------- --------
Deferred charges:
Federal income taxes 7,972 7,543
Regulatory asset 3,176 2,576
Other 4,775 4,643
-------- --------
15,923 14,762
-------- --------
$467,354 $448,830
======== ========
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of long-term debt $ 1,534 $ 1,405
Notes payable 143 618
Accounts payable 7,332 9,737
Accrued liabilities-
Taxes 8,633 7,047
Interest 4,035 4,089
Other 6,438 6,977
-------- --------
28,115 29,873
-------- --------
Deferred credits:
Federal income taxes 48,262 45,290
Investment tax credits 4,516 5,018
Reclamation costs 16,267 7,974
Regulatory liability 6,692 7,111
Other 5,636 5,153
-------- --------
81,373 70,546
-------- --------
Commitments and contingent liabilities
(Notes 6, 7 and 8)
Capitalization, per accompanying statements:
Common stock equity 193,175 182,342
Long-term debt 164,691 166,069
-------- --------
357,866 348,411
-------- --------
$467,354 $448,830
======== ========
The accompanying notes to consolidated financial statements are an
integral part of these consolidated balance sheets.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 1996 1995
(in thousands)
Common stock equity:
Common stock, $1 par value;
50,000,000 shares authorized;
14,450,199 and 14,424,952 shares
outstanding respectively $ 14,450 $ 14,425
Additional paid-in capital 46,841 46,355
Retained earnings 131,884 121,562
-------- --------
Total common stock equity 193,175 182,342
-------- --------
Cumulative preferred stock:
No par value; 400,000 share
authorized; no shares outstanding - -
$100 par value; 270,000 shares
authorized; no shares outstanding - -
Long-term debt:
First mortgage bonds-
6.50% due 2002 15,000 15,000
9.00% due 2003 7,870 9,275
8.06% due 2010 30,000 30,000
9.49% due 2018 6,000 6,000
9.35% due 2021 35,000 35,000
8.30% due 2024 45,000 45,000
-------- --------
138,870 140,275
-------- --------
Other-
6.7% pollution control revenue bonds,
due 2010 12,300 12,300
7.5% pollution control revenue bonds,
due 2024 12,200 12,200
Other long-term obligations 2,855 2,699
-------- --------
27,355 27,199
-------- --------
Total long-term debt 166,225 167,474
Current maturities (1,534) (1,405)
-------- --------
Net long-term debt 164,691 166,069
-------- --------
Total capitalization $357,866 $348,411
======== ========
The accompanying notes to consolidated financial statements are an
integral part of these consolidated financial statements.
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:
1996 1995 1994
(in thousands)
Balance, beginning of year $46,355 $45,740 $43,420
Premium, net of expenses
received from sale of stock 486 615 2,320
------- ------- -------
Balance, end of year $46,841 $46,355 $45,740
======= ======= =======
(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:
1996 1995
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
(in thousands)
Cash and cash equivalents $ 13,340 $ 13,340 $ 8,179 $ 8,179
Securities available for sale:
Corporate debt securities - - 1,000 1,000
State and local agency
obligations 11,458 11,458 5,804 5,804
Long-term debt 166,225 184,508 167,474 194,625
(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:
1996 1995 1994
(in thousands)
Service cost $ 874 $ 802 $ 865
Interest cost 2,239 2,169 2,074
Return on
assets:
Actual (4,477) (5,204) (1,819)
Deferred 1,502 2,603 (793)
------ ------ ------
Net pension
expense $ 138 $ 370 $ 327
====== ====== ======
Actuarial
assumptions:
Discount rate 7.5% 7.5% 8.0%
Expected long-
term rate of
return on assets 10.5% 10.5% 10.5%
Rate of increase in
compensation levels 5% 5% 5%
Funding information for the Plan as of October 1 of each year was as follows:
1996 1995
(in thousands)
Fair value of plan assets $31,953 $29,184
Projected benefit obligation (32,722) (30,714)
------- -------
(769) (1,530)
Unrecognized:
Net loss 659 1,559
Prior service cost 707 796
Transition asset (361) (451)
------- -------
Prepaid pension cost $ 236 $ 374
======= =======
Accumulated benefit obligation $26,376 $24,969
======= =======
Vested benefit obligation $25,266 $23,919
======= =======
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:
1996 1995 1994
(in thousands)
Service cost $166 $211 $188
Interest cost 304 429 303
Amortization of transition
obligation 150 150 150
Amortization of (gain) loss (1) 79 28
---- ---- ----
$619 $869 $669
==== ==== ====
Funding information as of October 1 was as follows:
1996 1995
(in thousands)
Accumulated postretirement benefit obligation:
Retirees $1,743 $1,485
Fully eligible active participants 756 723
Other active participants 1,941 1,906
Unfunded accumulated postretirement
benefit obligation 4,440 4,114
Unrecognized net gain 173 140
Unrecognized transition obligation (2,397) (2,546)
------ ------
$2,216 $1,708
====== ======
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:
1996 1995 1994
(in thousands)
Current $11,706 $ 8,640 $7,925
Deferred 2,533 2,600 2,975
Investment tax credits, net (661) (503) (505)
------- ------- -------
$13,578 $10,737 $10,395
======= ======= =======
The temporary differences which gave rise to the net deferred tax liability at
December 31, 1996 and 1995 were as follows:
Net Deferred
Income
Tax Asset
December 31, 1996 Assets Liabilities (Liability)
(in thousands)
Accelerated depreciation and other
plant-related differences $ - $42,088 $(42,088)
Regulatory asset 2,309 - 2,309
Regulatory liability - 1,415 (1,415)
Unamortized investment
tax credits 1,580 - 1,580
Mining development and
oil exploration 1,417 4,220 (2,803)
Employee benefits 2,107 97 2,010
Other 559 442 117
------ ------- --------
$7,972 $48,262 $(40,290)
====== ======= ========
Net Deferred
Income
Tax Asset
December 31, 1995 Assets Liabilities (Liability)
(in thousands)
Accelerated depreciation and other
plant-related differences $ - $42,182 $(42,182)
Regulatory asset 2,482 - 2,482
Regulatory liability - 1,415 (1,415)
Unamortized investment
tax credits 1,756 - 1,756
Mining development and
oil exploration 988 898 90
Employee benefits 1,828 137 1,691
Other 489 658 (169)
------ ------- --------
$7,543 $45,290 $(37,747)
====== ======= ========
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
1996 1995 1994
Federal statutory rate 35.0% 35.0% 35.0%
Regulatory asset recognition (1.7) (1.9) -
Amortization of investment
tax credits (1.5) (1.4) (1.5)
Tax-exempt interest income (0.6) (0.8) (1.1)
Percentage depletion in
excess of cost (0.5) (0.4) (1.7)
Other 0.2 (0.9) (0.3)
---- ---- ----
30.9% 29.6% 30.4%
==== ==== ====
(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.
1996 1995 1994
OIL GAS OIL GAS OIL GAS
(in thousands of barrels of oil and MCF of gas)
Proved developed and
undeveloped reserves:
Balance at beginning of year 1,612 7,658 1,438 9,080 1,116 2,759
Production (286) (1,718) (266) (1,986) (321) (1,731)
Additions 404 5,098 168 4,106 107 7,582
Property sales (9) (312) (103) (843) - -
Revisions to previous
estimates due primarily
to changed economic
conditions 665 246 375 (2,699) 536 470
----- ------ ----- ------ ----- ------
Balance at end of year 2,386 10,972 1,612 7,658 1,438 9,080
===== ====== ===== ====== ===== ======
Proved developed reserves at
end of year included above 2,376 9,633 1,606 6,370 1,436 6,246
===== ====== ===== ====== ===== ======
Year-end prices $24.04 $ 3.20 $18.50 $ 1.90 $15.75 $ 1.72
(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.
1996 1995 1994
(in thousands)
Assets at year-end:
Electric $382,753 $380,256 $340,042
Coal mining 55,470 45,224 72,851
Oil and gas 29,131 23,350 23,984
-------- -------- --------
$467,354 $448,830 $436,877
======== ======== ========
Depreciation, depletion
and amortization:
Electric $ 16,104 $ 11,943 $ 10,314
Coal mining 2,981 3,575 2,427
Oil and gas 3,709 4,142 4,860
-------- -------- --------
$ 22,794 $ 19,660 $ 17,601
======== ======== ========
Capital expenditures:
NS #2 (includes AFDC) $ - $ 33,219 $ 73,984
Other electric 12,822 11,242 14,187
Coal mining 2,169 1,546 5,911
Oil and gas 9,585 5,888 8,977
-------- -------- --------
$ 24,576 $ 51,895 $103,059
======== ======== ========
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
TAXES OTHER THAN INCOME TAXES
1996 1995 1994
(in thousands)
Property $ 4,368 $ 3,696 $ 3,637
Production and severance 4,105 3,385 2,995
Payroll 1,307 1,402 1,334
Black lung 1,320 1,263 1,205
Federal reclamation 1,135 1,027 979
Other 225 208 216
------- ------- -------
$12,460 $10,981 $10,366
======= ======= =======
FINANCIAL STATISTICS
Years ended December 31 1996 1995 1994 1993 1992
TOTAL ASSETS (in thousands) $467,354 $448,830 $436,877 $352,853 $330,202
PROPERTY AND INVESTMENTS
(in thousands)
Total property and
investments $581,537 $557,642 $519,296 $433,143 $413,192
Accumulated depreciation
and depletion 181,103 164,383 156,046 144,492 132,890
Capital expenditures
(includes AFDC) 24,576 51,895 103,059 40,290 27,915
CAPITALIZATION (in thousands)
Long-term debt $164,691 $166,069 $128,925 $ 85,274 $ 88,816
Common stock equity 182,342 168,089 149,158 193,175 175,410
-------- -------- -------- -------- --------
Total $357,866 $348,411 $304,335 $253,363 $237,974
======== ======== ======== ======== ========
CAPITALIZATION RATIOS
Long-term debt 46.0% 47.7% 42.4% 33.7% 37.3%
Common stock equity 54.0 52.3 57.6 66.3 62.7
----- ----- ----- ----- -----
Total 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
AVERAGE INTEREST RATE ON
LONG-TERM DEBT 8.1% 8.1% 8.5% 9.0% 8.9%
NET INCOME AVAILABLE FOR
COMMON STOCK
(in thousands) $30,252 $25,590 $23,805 $22,946 $23,638
DIVIDENDS PAID ON COMMON
STOCK (in thousands) $19,930 $19,312 $18,920 $17,720 $16,977
COMMON STOCK DATA
(in thousands)
Shares outstanding,
average 14,440 14,409 14,339 13,811 13,689
Shares outstanding,
end of year 14,450 14,425 14,386 14,270 13,701
Earnings per average
share, in dollars $2.10 $1.78 $1.66 $1.66 $1.73
Dividends paid per share,
in dollars $1.38 $1.34 $1.32 $1.28 $1.24
Book value per share, end
of year, in dollars $13.37 $12.64 $12.19 $11.78 $10.89
RETURN ON COMMON STOCK
EQUITY 15.7% 14.0% 13.6% 13.7% 15.8%
ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION AS PERCENT OF
NET INCOME 1.2% 22.9% 16.7% 3.2% 1.6%
ELECTRIC OPERATION STATISTICS
Years ended December 31 1996 1995 1994 1993 1992
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt
hours)
Generated, net station
output 1,659,671 1,320,630 1,108,530 1,227,084 1,226,153
Purchased and net
interchange 380,106 473,175 595,872 435,990 397,478
--------- --------- --------- --------- ---------
Total generated and
purchased 2,039,777 1,793,805 1,704,402 1,663,074 1,623,631
Company use and losses (80,106) (87,512) (65,651) (61,336) (73,627)
--------- --------- --------- --------- ---------
Total electric energy
sales 1,959,671 1,706,293 1,638,751 1,601,738 1,550,004
========= ========= ========= ========= =========
ELECTRIC ENERGY SALES
(megawatt hours)
Residential 406,658 383,929 368,953 370,736 339,341
General and commercial 541,463 513,854 495,909 469,496 446,036
Industrial 555,601 552,829 583,258 568,316 572,244
Public authorities 25,083 23,164 23,051 22,621 21,798
Sales for resale 181,766 171,942 166,580 162,789 160,180
--------- --------- --------- --------- --------
Total firm electric
energy sales 1,710,571 1,645,718 1,637,751 1,593,958 1,539,599
Non-firm sales 249,100 60,575 1,000 7,780 10,405
--------- --------- --------- --------- ---------
Total electric
revenue sales 1,959,671 1,706,293 1,638,751 1,601,738 1,550,004
========= ========= ========= ========= =========
ELECTRIC REVENUE
(in thousands)
Residential $ 33,230 $ 30,433 $ 28,574 $ 27,064 $ 25,366
General and commercial 41,307 37,663 35,390 32,295 30,742
Industrial 26,915 26,495 27,318 25,901 27,106
Public authorities 1,970 1,775 1,718 1,537 1,586
Sales for resale 8,189 7,625 7,460 7,122 7,002
-------- -------- ------- ------- -------
Total firm electric
revenue 111,611 103,991 100,460 93,919 91,802
Non-firm electric
revenue 2,985 741 - 202 230
Other revenue 4,122 4,051 4,296 4,034 5,416
-------- -------- -------- -------- --------
Total revenue $118,718 $108,783 $104,756 $ 98,155 $ 97,448
======== ======== ======== ======== ========
ELECTRIC CUSTOMERS
(end of year)
Residential 46,146 45,886 45,060 44,657 44,100
General and commercial 9,280 8,958 8,732 8,507 8,279
Industrial 37 35 36 41 38
Public authorities 137 138 130 124 117
Other electric utilities 1 1 1 1 1
------ ------ ------ ------ ------
Total 55,601 55,018 53,959 53,330 52,535
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No change of accountants or disagreements on any matter of accounting
principles or practices or financial statement disclosure have occurred.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Company is incorporated herein by
reference to the Proxy Statement for the Annual Shareholders' Meeting to be
held May 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. 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. 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. 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. 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.