SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
X ACT OF 1934
For the fiscal year ended December 31, 1997
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________________ to __________________
Commission File Number 1-7978
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number, including area code
(605) 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 27, 1998 $471,999,190
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 27, 1998
Common stock, $1.00 par value 14,475,971 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. Definitive Proxy Statement of the Registrant filed pursuant to Regulation
14A for the 1998 Annual Meeting of Stockholders to be held on May 19, 1998,
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...........................6
COMPETITION IN THE ELECTRIC UTILITY BUSINESS...................7
COAL SALES.....................................................7
OIL AND GAS OPERATIONS.........................................8
ENERGY MARKETING OPERATIONS....................................9
ENVIRONMENTAL REGULATION.......................................9
EMPLOYEES.....................................................12
ITEM 2. PROPERTIES........................................................12
UTILITY PROPERTIES............................................12
MINING PROPERTIES.............................................13
OIL AND GAS PROPERTIES........................................13
ITEM 3. LEGAL PROCEEDINGS.................................................14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...............15
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS...............................................15
ITEM 6. SELECTED FINANCIAL DATA...........................................16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS...............................16
LIQUIDITY AND CAPITAL RESOURCES...............................16
RATE REGULATION...............................................19
COMPETITION IN ELECTRIC UTILITY BUSINESS......................20
RESULTS OF OPERATIONS.........................................23
BUSINESS OUTLOOK STATEMENTS...................................29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE............................51
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................51
ITEM 11. EXECUTIVE COMPENSATION............................................52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT....52
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................52
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K...52
SIGNATURES........................................................55
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 ofthe 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
Black Hills Capital Group.....Black Hills Capital Group, Inc., a wholly owned
subsidiary of Wyodak Resources
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
acquired
Company.......................Black Hills Corporation
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 and Neil
Simpson Unit #2
NS #2.........................Neil Simpson Unit #2, an 80 megawatt coal-fired
electric generating 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 ofthe 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
company primarily consisting of four principal businesses: electric, coal
mining, oil and gas production, and energy marketing. The Company's mission
statement is to position the Company nationally to build value for
shareholders, offer competitive prices for customers and create opportunities
for employees through quality energy products and services. The Company
operates its public utility electric operations under the assumed name of Black
Hills Power and Light Company, its coal mining operations through its
subsidiary Wyodak Resources, its oil and gas exploration and production
operations through Western Production, and its energy marketing operations
through Black Hills Capital Group.
Black Hills Power is engaged in the generation, purchase, transmission,
distribution and sale of electric power and energy to approximately 56,300
customers in 11 counties in western South Dakota, northeastern Wyoming and
southeastern Montana, an area with a population estimated at 165,000. The
largest community served is Rapid City, South Dakota, a major retail, wholesale
and health care center, with a population, including environs, estimated at
75,000. Agriculture, tourism, small stakes gambling, mining, lumbering, small
item manufacturing, service and support businesses and government support
through Ellsworth Air Force Base are the primary influences on the economic
well-being of the region.
Wyodak Resources, incorporated under the laws of Delaware in 1956, is engaged
in the mining and sale of low sulfur sub-bituminous coal and is located
approximately five miles east of Gillette, Wyoming, in the Powder River Basin.
Acquired by Wyodak Resources in 1986, Western Production is an oil and gas
exploration and production company with interests located in the Rocky Mountain
region, Texas, California and various other locations.
Black Hills Capital Group, incorporated under the laws of South Dakota in 1997,
holds the Company's investments in Black Hills Energy Resources, Inc. (formerly
Wickford Energy Marketing, Inc.), VariFuel, Inc., and a 50% interest in Enserco
Energy, Inc. The energy marketing companies noted above market natural gas,
crude oil, electricity, and related energy services to customers in the East
Coast, Midwest, Rocky Mountain and West Coast regions. In addition to the
energy marketing companies, Black Hills Capital Group will be a primary vehicle
for future corporate development activities.
Information as to the continuing lines of business of the Company for the
calendar years 1995-1997 is as follows:
1997 1996 1995
(in thousands)
Revenue from sales to
unaffiliated customers:
Electric $126,194 $118,508 $108,563
Coal mining 19,991 20,931 19,372
Oil and gas 13,295 12,555 11,164
Energy marketing 142,790 - -
Revenue from
inter-company sales:
Electric $ 303 $ 210 $ 220
Coal mining 11,089 10,384 10,498
For additional information relating to the Company's operations by business
line see Note 11 of "Notes to Consolidated Financial Statements".
ELECTRIC POWER SUPPLY
GENERAL
Black Hills Power has been able to meet the needs of its customers for electric
power and energy through its owned generating capacity and by contract
purchases. Black Hills Power's peak load of 346 megawatts was reached in July
1997. Approximately 45 megawatts of additional load commenced January 1, 1997,
when Black Hills Power began providing wholesale electricity to MDU for its
Sheridan, Wyoming electric service territory. (See ITEM 1. BUSINESS-ELECTRIC
SERVICE TERRITORY AND SALES - Wholesale to MDU.) Black Hills Power estimates
its required reserves at 82 megawatts. Black Hills Power is not presently a
member of a power pool, but in 1997 Black Hills Power signed a Letter of Intent
to join a new power pool, Rocky Mountain Reserve Group. Rocky Mountain Reserve
Group's formation is pending approval by FERC. Upon joining the FERC-approved
power pool, Black Hills Power's reserve requirement is estimated to be 22
megawatts.
Black Hills Power owns coal-fired generating units having a summer capability
rating of 214 megawatts and 77 megawatts of oil-fired diesel and natural gas
combustion turbines for peaking and standby use. Black Hills purchases
additional resources under three contracts with Pacific Power: the Power Sales
Agreement, under which it purchases 75 megawatts of baseload power declining
to 50 megawatts from 2000 to 2004; the Reserve Capacity Integration Agreement,
under which 33 megawatts of additional reserve capacity are available; and the
Capacity Contract, under which Black Hills Power has options to be exercised
seasonally to purchase up to 60 megawatts of capacity.
PACIFIC POWER'S POWER SALES AGREEMENT
Pacific Power's Power Sales Agreement obligates Black Hills Power to purchase
from Pacific Power 75 megawatts of electric power plus energy at a load factor
varying from a minimum of 41 percent to a maximum of 80 percent as scheduled by
Black Hills Power. In October 1997, Black Hills Power entered into a second
Restated and Amended Power Sales Agreement with Pacific Power. The Amended
Agreement reduces the contract capacity by 25 megawatts (5 megawatts per year
beginning in 2000). The contract terminates December 31, 2023. The power and
energy delivered is power from Pacific Power's system and does not depend on
any one unit, but the price is generally based on Pacific Power's costs in
Units 3 and 4 of the Colstrip coal-fired generating plant near Colstrip,
Montana. Black Hills Power contracts for transmission service from Pacific
Power under Pacific Power's FERC approved transmission rates. The Company has
incurred capacity charges of $15,800 per megawatt month and an average energy
charge of $12.26 per megawatt hour over the last three years of this agreement
with a 55 percent load factor. (See ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK
STATEMENTS.)
PACIFIC POWER'S RESERVE CAPACITY INTEGRATION AGREEMENT
This agreement obligates Pacific Power until the end of the contract in 2012 to
make available to Black Hills Power 100 megawatts of reserve capacity to be
acquired by Black Hills Power only at such time under prudent utility practice
Black Hills Power would have operated its combustion turbines. In return,
Pacific Power has the right to utilize Black Hills Power's four 25 megawatt
combustion turbines (with a summer rating of 67 megawatts), but Black Hills
Power has a prior right to use said turbines to support the transmission
system. The price for any energy Black Hills Power acquires under this
agreement is based upon the lower of Pacific Power's incremental costs of
generation of its highest price coal-fired plant or the cost of fuel to operate
the combustion turbines. Pacific Power also pays certain operating and
maintenance expenses of the combustion turbines, together with a $50,000
payment per month for the remaining life of the contract.
PACIFIC POWER'S CAPACITY CONTRACT
On September 1, 1995, Black Hills Power and Pacific Power entered into the
Pacific Power Capacity Contract. Under the contract, Pacific Power granted
Black Hills Power an option to be exercised for each six-month season for a
period commencing October 1, 1996 and ending March 31, 2007 to purchase up to
60 megawatts of peaking capacity at established prices. Black Hills Power may
schedule the energy at a rate up to 100 percent per hour at a load factor up to
15 percent per season. Other than to give preference to purchasing peaking
capacity from Pacific Power, Black Hills Power is under no obligation to
exercise any of the six-month seasonal options.
In addition to granting Black Hills Power options to purchase peaking capacity,
the Pacific Power Capacity Contract also obligates Black Hills Power to sell to
Pacific Power until December 31, 2000, all surplus energy which is defined as
the difference in Black Hills' Resources (all energy from Black Hills Power's
generating resources and energy entitlement under Pacific Power's Power Sales
Agreement) and Black Hills' Loads (non-end user contracts of five months or
longer and all retail customers as they exist from time to time). The selling
prices are based upon economy energy spot price indices determined daily in the
western part of the United States with a sharing between Pacific Power and
Black Hills Power of prices above certain levels. Black Hills Power is not
obligated to sell any energy below its marginal production cost. The contract
also provides Black Hills Power an option to store energy with Pacific Power
and to take that energy back for the purpose of replacing energy from a forced
or scheduled outage of NS #2 or Black Hills Power's share of the Wyodak Plant.
To the extent of the excess capacity and energy available to Black Hills Power
from its generating resources and the Pacific Power purchased power contracts,
Black Hills Power at this time has the flexibility to serve the expected growth
of its loads in its service territory and as opportunities arise in the
meantime, to increase sales of its energy and capacity.
ELECTRIC SERVICE TERRITORY AND SALES
RETAIL SERVICE TERRITORY
Black Hills Power's service territory is currently protected by assigned
service area and franchises that generally grant to Black Hills Power the
exclusive right to sell all electric power consumed therein, subject to
providing adequate service. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC
UTILITY BUSINESS.)
As evidenced by a 1 percent increase in customers in both 1997 and 1996, the
economy in and around Black Hills Power's service territory is believed by
management to be stable. Small businesses and regional plant expansions are
continually being attracted to the region along with retirees who have
discovered the Black Hills region with its scenery, recreational activities and
medical services to be an attractive place to live. Management anticipates
that the economy will continue to experience modest growth but can give no
assurances as many economic factors will greatly influence any economy.
Ellsworth Air Force Base, a B-1 bomber military base near Rapid City, survived
the fourth round of base closures in 1995. In January 1998, Homestake Mining
Company (Homestake), the Company's third largest customer at 5.6 percent of
electric revenues, announced a reorganization and restructuring plan at its
gold mine in Lead, South Dakota. It is anticipated that the mine workforce
will be reduced from 900 to approximately 400 workers. The Company believes
that any load reductions at Homestake can be somewhat mitigated by additional
off-system sales. Currently, the Company does not believe that this
restructuring will have a material adverse effect on results of operations or
financial position. Other major industries in and around Black Hills Power's
service territory have been economically stable.
WHOLESALE TO CITY OF GILLETTE
Black Hills Power sells electric power and energy to the municipal electric
system at Gillette, Wyoming. Service is rendered under a long-term contract,
recently amended, and expiring July 1, 2012, wherein Black Hills Power sells to
the City of Gillette its first 23 megawatts of capacity requirements and the
associated energy. In 1997, as part of the contract amendment, the
transmission service component was unbundled from the power supply agreement,
and transmission service will be provided at FERC approved rates. In the
amended contract, the City of Gillette has agreed not to apply to FERC for any
rate change to be effective prior to January 1, 2003, unless and in the event
that Black Hills Power files for a rate change with FERC, which rate filing
cannot be effective prior to January 1, 2002, except under extraordinary events
as defined in the contract. In addition, Black Hills Power agreed to phase in
price reductions for the power purchased by the City of Gillette. The most
recent average annual capacity factor for this 23 megawatt demand has been
approximately 89 percent. Sales to Gillette represented 9.3 percent and 10.6
percent of total firm energy sales and 6.6 percent and 7.1 percent of revenue
from total electric sales in 1997 and 1996, respectively.
WHOLESALE TO MDU
Black Hills Power and MDU entered into a Power Integration Agreement, dated as
of September 9, 1994, providing for the sale to MDU of up to 55 megawatts of
power and associated energy to serve MDU's Sheridan, Wyoming, electric service
territory for a period of 10 years which commenced January 1, 1997. The MDU
Sheridan service territory has experienced a 47 megawatt winter peak and
operates at a 57 percent load factor.
The agreement provides for fixed rates for capacity and energy to be paid by
MDU during the 10-year contract term. Black Hills Power and MDU have agreed
not to apply to FERC for any rate changes in the contract for the entire 10-
year term other than increases caused by governmental direct taxes on electric
generation fired by hydrocarbons. The agreement further provides for Black
Hills Power and MDU to equally share the costs of constructing a combustion
turbine of approximately 70 megawatts at such time during the 10-year term that
Black Hills Power determines in its sole discretion that such turbine is
required.
ADDITIONAL OFF-SYSTEM SALES
Black Hills Power sold 279,600 and 249,100 megawatt hours of non-firm energy in
1997 and 1996, respectively. The selling price is based on spot market prices
which have generated only a small profit margin on the sales. (See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)
TRANSMISSION SERVICE SALES
Black Hills Power furnishes long-term transmission services under two
contracts: (i) the transmission contract terminating December 31, 2020 (1986
Agreement), among Black Hills Power and Basin Electric and the other
distribution cooperatives as it concerns the transmission contract (the
Cooperatives) and (ii) the agreement with the City of Gillette terminating July
1, 2012 (described under Wholesale to City of Gillette above), under which
Black Hills Power has agreed to deliver all of the City of Gillette's electric
requirements. The rates charged under the transmission contract with the
Cooperatives are fixed formula rates, and the transmission rates under the
Gillette contract are established by FERC under Black Hills Power's open access
transmission tariff. (See ITEM 3. LEGAL PROCEEDINGS - Transmission Rates -
FERC Proceedings and ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.)
COMPETITION IN THE ELECTRIC UTILITY BUSINESS
For information relating to competition in the electric utility business, see
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -COMPETITION IN ELECTRIC UTILITY
BUSINESS.
COAL SALES
SALES TO BLACK HILLS POWER'S PLANTS
Wyodak Resources sells coal to Black Hills Power for all its requirements under
an agreement that limits earnings from all coal sales to Black Hills Power
(including the 20 percent share on the Wyodak Plant and all sales to Black
Hills Power's other plants) to a return on Wyodak Resources' original cost,
depreciated investment base. The return is 4 percent (400 basis points) above
A-rated utility bonds to be applied to Wyodak Resources' coal mining investment
base as determined each year. Black Hills Power made a commitment to the
SDPUC, the WPSC and the City of Gillette that coal would be furnished and
priced as provided by this agreement for the life of NS #2. Earnings from the
intercompany sales of coal at this time represent 5.3 percent of the Company's
consolidated earnings.
Sales and production statistics for the last three calendar years comparing
sales to Black Hills Power to others are as follows:
% Revenue
Revenue Derived from
from Sale Black HILLS Tons of
YEAR OF COAL POWER COAL SOLD
(in thousands, except % revenue)
1997 $31,080 36 3,251
1996 31,315 33 3,243
1995 29,870 35 2,934
SALES TO THE WYODAK PLANT
Wyodak Resources furnishes all of the fuel supply for the Wyodak Plant in which
Black Hills Power owns a 20 percent interest and Pacific Power an 80 percent
interest. (See Note 6 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.) The
price for unprocessed coal sold to Pacific Power for its 80 percent interest in
the Wyodak Plant is determined by a coal supply agreement entered into by Black
Hills Power, Pacific Power and Wyodak Resources in 1978 and terminating in the
year 2013. This agreement was amended and restated in 1987. Revenue from coal
sales to the Wyodak Plant totaled $22,688,000 in 1997 or 73 percent of revenue
for all coal sold by Wyodak Resources. The quantity of coal sold in 1997 for
the Wyodak Plant was 2,155,000 tons, as compared to 2,125,000 tons sold in
1996. Barring unusual periods of maintenance, the quantity of coal for the
maximum consumption capability of the Wyodak Plant for one year is
approximately 2,100,000 tons and the average yearly consumption is 1,900,000
tons. The average consumption is expected to continue during the remaining 16
years of the coal agreement. However, from time to time, the plant's physical
operating capabilities will affect the quantity of coal burned.
Of the 3,251,000 tons of coal sold by Wyodak Resources in 1997, 1,427,000 tons
were sold to Black Hills Power, 1,725,000 tons were sold to Pacific Power and
99,000 tons were sold to others.
Wyodak Resources' revenue from sales of coal to Pacific Power and Black Hills
Power as compared to its revenue from all sales to total unaffiliated customers
for the last three years was as follows:
1997 1996 1995
(in thousands)
Sales to:
Pacific Power $19,240 $19,189 $16,777
Black Hills Power(1) 11,089 10,384 10,498
All unaffiliated
customers 19,991 20,931 19,372
(1) The first seven months of 1995 are not adjusted for the affiliate coal
price adjustment.
Many factors can significantly affect sales of coal and revenue under the
existing contracts. Examples include the seller's or buyer's inability to
perform due to machinery breakdown, damage to equipment, governmental
impositions, labor strikes, coal quality problems, transportation problems and
other unexpected events.
OTHER SALES
In addition to the coal sold to the Wyodak Plant and to Black Hills Power,
Wyodak Resources sold 119,000 tons of coal to the South Dakota State Cement
Plant in 1996. The Cement Plant canceled this contract in October 1996.
Smaller amounts of coal are sold to various businesses. All substantial long-
term contracts contain adjustment clauses based upon certain costs and
government indices.
The coal mining industry is highly competitive and significant new sales
opportunities are limited. Wyodak Resources operates in an area with many
other mining companies which have substantial unused capacity. They, like
Wyodak Resources, have the permits and capability for large increases in
production. Currently, Wyodak Resources' coal sales are confined to sales for
consumption at or near the mine. Wyodak Resources is a relatively small coal
mine in relation to others in the area and its current production costs exceed
the current spot market price for coal. (See ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-BUSINESS OUTLOOK
STATEMENTS-Future Coal Sales.)
OIL AND GAS OPERATIONS
Net income and assets related to oil and gas operations have been 7 percent or
less of the Company's consolidated amounts over the last three years. The oil
and gas industry is highly competitive. Western Production encounters strong
competition from many oil and gas producers in acquiring drilling prospects and
producing properties.
The Company's oil and gas production is sold at or near the wellhead, generally
at prevailing posted prices. Western Production has been able to market all of
its oil and gas production. Operating revenue by source for the last three
years was as follows:
Oil and Gas Gas Plant Field
YEAR SALES REVENUE SERVICES
(in thousands)
1997 $9,763 $755 $2,777
1996 9,050 875 2,630
1995 7,449 762 2,953
Western Production produced approximately 590,000 equivalent barrels of oil in
1997 comprised of 51 percent oil and 49 percent gas.
ENERGY MARKETING OPERATIONS
In July 1997, Black Hills Capital Group acquired the assets and hired the
operational management of Jomax Partners, L.P. as successor and survivor of
Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada Company.
In March 1998, Wickford Energy Marketing, Inc. changed its name to Black Hills
Energy Resources, Inc. Black Hills Energy Resources is headquartered in
Houston, Texas with a natural gas sales office in Calgary, Alberta, Canada and
crude oil sales offices in Tulsa, Oklahoma and Midland, Texas. Black Hills
Energy Resources is a "niche" wholesale natural gas and crude oil marketing
company with expertise in Gulf Coast and Canadian Supply, targeting natural gas
markets in the East Coast and Midwest and crude oil markets primarily in the
Southwest.
Since its acquisition in July 1997, Black Hills Energy Resources marketed
231,000 mmbtus (million British thermal units) of natural gas per day and
12,600 barrels of oil per day. Wholesale natural gas and crude oil businesses
are high volume, lower margin operations. Operating revenues for natural gas
and crude oil sales totaled $94,295,000 and $46,810,000, respectively, for the
five month period since acquisition. With a full year of operations in 1998,
the Company expects revenues to increase substantially from 1997 levels, but
does not expect Black Hills Energy Resources' contribution to total Company
operations to be significant.
In 1996, Wyodak Resources established Enserco Energy, Inc., a Lakewood,
Colorado-based energy marketing company. (See ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -RESULTS OF
OPERATIONS - Energy Marketing Operations.)
ENVIRONMENTAL REGULATION
The Company is subject to extensive federal, state and local laws and
regulations governing discharges to the air and water, as well as the handling
and disposal of solid and hazardous wastes, including without limitation the
federal Clean Air Act (as amended in 1990), the federal Water Pollution Control
Act ("Clean Water Act"), the federal Toxic Substances Control Act and various
state laws, including solid waste disposal laws (collectively "Environmental
Regulatory Laws"). Governmental authorities have the power to enforce
compliance with Environmental Regulatory Laws, and violators may be subject to
civil or criminal penalties, injunctions or both. Third parties also may have
the right to sue to enforce compliance.
AIR QUALITY
Under the federal Clean Air Act, the federal Environmental Protection Agency
("EPA") has promulgated national air quality standards for certain air
pollutants, including sulfur oxides, particulate matter and nitrogen oxides.
The Company was granted a prevention of significant deterioration ("PSD")
construction permit by the DEQ for NS #2. The PSD permit set emission rate
limitations on particulate, sulfur dioxide, nitrogen oxides and opacity. NS #2
is currently working with DEQ to obtain an air quality operating permit and
expects to receive such permit in 1998. Black Hills Power has been in
substantial compliance with its PSD permit in its operations of NS #2 since its
completion in August of 1995. Black Hills Power is continuing to make final
adjustments to NS #2's equipment and operating procedures and to work with the
DEQ to obtain its operating permit and achieve complete compliance.
Amendments to the Clean Air Act in 1990 will require a significant reduction in
nationwide sulfur oxide emissions by fossil fuel-fired generating units to a
permanent total emissions cap in the year 2000. This reduction is to be
achieved by the allotment of allowances to emit sulfur dioxide measured in tons
per year to each owner of a unit and requiring the owner to hold sufficient
allowances each year to cover the emissions of sulfur oxide from the unit
during that year. Black Hills Power holds sufficient allowances credited to it
as a result of sulfur removal equipment previously installed on the Wyodak
Plant to apply to the operation of NS #2 and its interest in the Wyodak Plant
in the year 2000 without requiring the purchase of any additional allowances.
Current law does not require allowances for Black Hills Power's other plants.
All existing generating units of the Company are required to obtain operating
source permits under the Clean Air Act amendments. The operating permit
applications for the Osage and NS #1 generating units were submitted in 1995
and received in 1997. Air quality permits for the Ben French Station were
renewed in 1995 by the Department of Environment and Natural Resources of South
Dakota. Black Hills Power expects to renew this permit in 1998.
Because the 1990 amendments to the Clean Air Act are scheduled to be
implemented and interpreted throughout the 1990s, compliance with yet-to-be
promulgated and interpreted regulations may require additional capital and
operational expenditures in the future, most likely from enhanced monitoring
costs. Due to the political sensitivity and volatility of environmental issues
and how they may be implemented, management can give no assurances that
unexpected additional capital and operating costs may be required in the future
that would have a material impact on financial results.
WATER QUALITY
The federal Clean Water Act requires permits for discharges of effluent and
that all discharges of pollutants comply with federally approved state water
quality standards. Black Hills Power currently has in place all required
permits under the Clean Water Act for discharges from all of the power plants
in which Black Hills Power has an interest. While management believes that it
is in full compliance with all federal and state clean water laws and
regulations, for all the same reasons as stated in the previous paragraph, no
assurances can be given of the extent of costs to comply with clean water
requirements in the future.
LAND QUALITY - SOLID WASTE DISPOSAL
Black Hills Power disposes all solid wastes collected as a result of burning
coal at its power plants in approved solid waste disposal sites. Each disposal
site has been permitted by the state of its location in compliance with law.
Ash and wastes from flue gas and sulfur removal from the Wyodak Plant and NS #2
are deposited in disposal cells located in Wyodak Resources' mined areas.
These disposal cells are located below some shallow water aquifers in the mine.
Management believes that the disposal cells are sufficiently constructed and
lined with clay so as to prevent any pollution of the underground water from
these cells. None of the solid wastes from the burning of coal is classified
as hazardous material, but the wastes do contain minute traces of metals that
would be perceived as polluting if such metals were leached into underground
water. While management does not believe that any substances from the solid
waste disposal will pollute underground water, they can give no assurances that
over a long period of time such could never happen. In such event, the Company
could experience material costs in mitigating any damages from such pollution.
Agreements in place require Pacific Power to be responsible for any such costs
that would be related to the solid waste from its 80 percent interest in the
Wyodak Plant.
Additional unexpected material costs could also result in the future from
either the federal or state government determining that solid waste from the
burning of coal does contain some hazardous material that requires some special
treatment, including solid waste previously disposed of, and holding those
entities who disposed of such waste responsible for such treatment. Such
unexpected governmental requirements are beyond the control of the Company.
RECLAMATION
Under federal and state laws and regulations, Wyodak Resources is required to
submit to and receive approval from the DEQ for a mining and reclamation plan
which provides for orderly mining, reclaiming and restoring of all land in
conformity with all laws and regulations. Wyodak Resources has an approved
mining permit and is otherwise in compliance with other land quality
permitting programs.
One condition that could result in substantial unexpected increases in costs
of the reclamation permit relates to three depressions, the existing south
depression, the Peerless depression and the North Pit depression, which have or
will result from Wyodak Resources' mining. Because of the thick coal seam and
relatively shallow overburden, the present plan for restoration leaves areas of
the mine that will have limited reclamation potential because of their location
in depressions with interior drainage only. While the DEQ has allowed these
depressions in the present plan, the DEQ has reserved the right to review and
evaluate future mining plans proposed by Wyodak Resources. Such plans are
reviewed for the feasibility and desirability of causing Wyodak Resources to
place additional overburden generated elsewhere for the purpose of reducing the
depressions if the DEQ finds that the placement is necessary to prevent
degradation of more areas than expected. The DEQ has allowed the depressions
at the minimum acres specified and subject to maintenance of water quality at
the sites. Exceedence of acreage limitations or degradation of water quality
could result in material additional requirements placed upon Wyodak Resources,
including the placement of additional quantities of overburden in the
depressions and restoring water quality. Based on extensive reclamation
studies, accruals are maintained to comply with all reclamation requirements.
However, no assurances can be given that additional requirements in the future
may be imposed that cause unexpected material increases in reclamation costs.
BEN FRENCH OIL SPILL
In 1990 and 1991, Black Hills Power discovered extensive underground fuel oil
contamination at the Ben French Plant site. With the help of expert
consultants, the Company engaged in assessment and remediation and has worked
closely with the South Dakota Department of Environment and Natural Resources.
Assessment and remediation efforts are continuing up to the present time. All
underground oil-carrying facilities from which the contamination occurred are
now above ground. There have been no significant recoveries of free fuel oil
product since 1994. Black Hills Power continues to monitor the site. Soil
borings and monitoring wells on the perimeters of Black Hills Power's Ben
French Plant property are showing no indication of contamination beyond the
property's limits. Management believes that the underground spill has been
sufficiently remedied so as to prevent any oil from migrating off site.
However, due to underground gypsum deposits in this area, the fuel oil has the
potential of migrating to area waterways. In such event, cleanup costs could
be greatly increased. Management believes that sufficient remediation efforts
to prevent such a migration are currently in place, but
due to the uncertainties of underground geology, no assurance can be given.
Cleanup costs recognized to date total approximately $434,000, of which amount
$312,000 has been reimbursed from the South Dakota Petroleum Release
Compensation Fund. To date, no penalties, claims or actions have been taken or
threatened against the Company because of this oil spill.
PCBS
Under the federal Toxic Substances Control Act, the EPA has issued regulations
that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs
had been widely used as insulating fluids in many electric utility transformers
and capacitors manufactured before the Toxic Substances Control Act prohibited
any further manufacture of such PCB equipment. Black Hills Power removes and
disposes of PCB-contaminated equipment in compliance with law as it is
discovered.
Several years ago, Black Hills Power began a testing program of possible PCB-
contaminated transformers, and in 1997 completed testing of all transformers
and capacitators which are not located in Black Hills Power's electric
substations. Black Hills Power has not completed the testing of sealed
potential transformers and bushings located in its electric substations as the
testing of such equipment will require the destruction of the equipment. While
release of PCB-contaminated fluid, if present, from such equipment is unlikely
and the volume of fluid in such equipment is generally less than one gallon,
any release of such fluid would be confined to Black Hills Power's substation
site.
Release of PCB-contaminated fluids, especially any involving a fire or a
release into a waterway, could result in substantial cleanup costs. The
Company has not received any notices of non-compliance relating to PCB
regulations.
ELECTROMAGNETIC FIELDS
A number of studies have examined the possibility of adverse health effects
such as cancer from electromagnetic fields (EMF) which are caused by electric
transmission and distribution facilities. Certain states have enacted
regulations to limit the strength of magnetic fields at the edge of
transmission line rights-of-way. None of the jurisdictions in which Black
Hills Power operates has adopted formal rules or programs with respect to EMF
or EMF considerations in the siting of electric facilities. Black Hills Power
expects that public concerns will make it more difficult and costly to site and
construct new power lines and substations in the future. It is uncertain
whether Black Hills Power's operations may be adversely affected in other ways
as a result of EMF concerns. Black Hills Power is designing all new
transmission lines under EMF standards adopted by the State of Florida so as to
minimize the EMF effect. The Company is unable to predict the future costs to
the electric utility industry, including the Company, if a determination is
made in the future, either based on facts or perception, that EMF causes
adverse health effects.
The Company makes ongoing efforts to comply with new as well as existing
environmental laws and regulations to which it is subject. It is unable to
estimate the ultimate effect of existing and future environmental requirements
upon its operations.
EMPLOYEES
At December 31, 1997, the number of employees of the Company (including Black
Hills Power), Wyodak Resources, Western Production and Black Hills Capital
Group were 324, 53, 35, and 34, respectively, for a total of 446 employees.
Approximately 44 percent of the employees of Black Hills Power are covered by
union contracts with the International Brotherhood of Electrical Workers. In
the Company's opinion employee relations are satisfactory.
ITEM 2. PROPERTIES
UTILITY PROPERTIES
The following table provides information on the generating plants of Black
Hills Power. During 1997, 99 percent of the fuel used in electric generation,
measured in Btus (British thermal units), was coal.
GENERATING UNITS
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(a) 100,000 Oil or gas
Neil Simpson Station -
Gillette,Wyoming 1969 21,760 Coal
1995(b) 88,900 Coal
Wyodak Plant -
Gillette, Wyoming 1978(c) 72,400 Coal
Total 352,560
(a) These combustion turbines are those referenced by ITEM 1. BUSINESS -
ELECTRIC POWER SUPPLY - Pacific Power's Reserve Capacity Integration
Agreement.
(b) NS #2 was placed into commercial operation in August 1995. The plant's
total production may, at times, exceed its name plate rating by 11 MWs.
(c) Black Hills Power's 20 percent interest. See Note 6 of "Notes to
Consolidated Financial Statements". Black Hills Power owns transmission
lines and distribution systems in and adjoining the communities served
consisting of 447 miles of 230 kV, 530 miles of 69 kV, 8 miles of 47 kV and
numerous distribution lines of less voltage. Black Hills Power owns a
service center in Rapid City, several district office buildings at
various locations within its service area and an eight-story home office
building at Rapid City, South Dakota, housing its home office
on four floors, with the balance of the building rented to others.
MINING PROPERTIES
Wyodak Resources is engaged in mining and processing sub-bituminous coal near
Gillette in Campbell County, Wyoming, and owns or has user rights in the
necessary mining, processing and delivery equipment to fulfill its sales
contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal
are based upon four federal leases and one state lease. The estimated
recoverable coal from the leases as of December 31, 1997 is 284,175,000 tons,
of which 24,132,000 tons are committed to be sold to the Wyodak Plant and
approximately 26,130,000 tons to Black Hills Power's other plants.
Each federal lease grants Wyodak Resources the right to mine all of the coal in
the land described therein, but the government has the right at the end of 20
years from the date of the lease to readjust royalty payments and other terms
and conditions. All of the federal leases provide for a royalty of 12.5
percent of the selling price of the coal. The state lease provides for a
royalty to be determined every five years. Currently, the royalty on the state
lease, to be reviewed in 1998, is 7% of the selling price of the coal. Each
federal lease and state lease requires diligent development to produce at least
one percent of all recoverable reserves within either 10 years from the
respective dates of the 1983 leases or 10 years from the date of adjustment of
the other leases. Each lease further requires a continuing obligation to mine,
thereafter, at an average annual rate of at least one percent of the
recoverable reserves. All of the federal leases and the state lease constitute
one logical mining unit which is treated as one lease for the purpose of
determining diligent development and continuing operation requirements. All
coal is to be mined within 40 years from December 31, 1991, the date of the
logical mining unit. Even if federal and state coal leases are not mined out
in 40 years, the federal coal is likely to be available for further lease after
the 40 years. Wyodak Resources' current coal agreements require production
which should be sufficient to satisfy the diligent development and continual
operation requirements of present law. Wyodak Resources will require
additional coal sales in order to mine all of its state and federal coal within
the 40 year requirement.
The law, which requires that an owner of land that is primarily devoted to
agriculture must approve a reclamation plan before the state will approve a
permit for open pit mining, affects approximately 3,100,000 tons of the
recoverable coal. Wyodak Resources has excluded these tons of coal from its
mine plan and will not mine such coal until a surface consent has been
negotiated or the right to mine has been settled by litigation.
In September 1996, Wyodak Resources entered into an agreement to purchase the
Clovis Point Mine properties from Kerr McGee Coal Corporation. Acquisition of
the property increased Wyodak Resources' 1996 recoverable reserves to
approximately 288 million tons and includes a train loadout facility,
maintenance and processing facilities and a developed open pit. (See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES - Acquisition of Clovis Point Mine
Properties.)
OIL AND GAS PROPERTIES
Western Production operates 310 wells as of December 31, 1997. The majority
of these wells are in the Finn Shurley Field, located in Weston and Niobrara
Counties, Wyoming. Western Production does not operate, but owns a working
interest in 174 producing properties located in the western and southern United
States. Western Production also owns a 44.7 percent non-operating interest in
a natural gas processing plant also located at the Finn Shurley Field.
Western Production participated in the drilling of 37 exploratory and
development wells in 1997. Western Production's average working interest in
such wells was 19 percent, or 7 net wells. A development well is a well
drilled within the presently proved productive area of an oil and gas
reservoir, as indicated by reasonable interpretation of available data, with
the objective of completing in that reservoir. An exploratory well is a well
drilled in search of a new, as yet undiscovered oil or gas reservoir or to
greatly extend the known limits of a previously discovered reservoir. Twenty-
two out of the 37 wells drilled in 1997 were completed as producing wells for
an overall drilling success rate of 59 percent.
See the table in Note 10 of "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS"
for Western Production's estimated quantities of proved developed and
undeveloped oil and natural gas reserves at December 31, 1997, 1996 and 1995,
and a reconciliation of the changes between these dates using constant product
prices for the respective years.
ITEM 3. LEGAL PROCEEDINGS
TRANSMISSION RATES - FERC PROCEEDINGS
In Black Hills' open access transmission tariff proceedings before the FERC
under the provisions of Rule 888, Black Hills and the FERC Trial Staff have
reached a settlement which has been forwarded to the FERC for their review and
approval. This settlement allows Black Hills to use the revenues received
under the long-term transmission agreement between the Company and the
Cooperatives which terminates on December 31, 2020 (SEE ITEM 1. BUSINESS -
ELECTRIC SERVICE TERRITORY AND SALES) as being equal to the cost of providing
service to the Cooperatives. The settlement recognizes the benefits realized
by Black Hills in working with the RECs relating to the construction of
transmission facilities and, as a result of these joint efforts, applies the
revenue credit method in determining Black Hills Power's open access
transmission tariff rates by crediting the revenue received from the
Cooperatives against Black Hills Power's revenue requirements necessary to earn
a just and reasonable rate on its transmission facilities. The Cooperatives'
transmission loads are not considered when calculating Black Hills' open access
transmission tariff rates; and as such, the Cooperatives are paying less than
their fully allocated cost for use of the transmission system. But as a result
of allowing the revenue credit methodology, the open access transmission rates
still allow Black Hills to earn a just and reasonable rate on its transmission
facilities. The settlement with the FERC is consistent with past actions of
the SDPUC and WPSC, which similarly have allowed Black Hills to use the revenue
credit methodology in determining bundled rates for retail customers. The
settlement with the FERC now applies the revenue credit methodology in
determining wholesale transmission rates.
In the settlement with the FERC Trial Staff, Black Hills has agreed to file for
new open access transmission tariff rates in the event that: (1) either the
South Dakota or the Wyoming legislatures adopt retail access which would allow
alternative electricity suppliers to have access to existing franchised retail
service territories; (2) an entity other than Black Hills Power or the
Cooperatives establishes generation tied to a Cooperative's transmission line
as identified in the 1986 Black Hills Power-Basin Electric Transmission
Agreement for service to that entity's existing retail customers within the
joint transmission area; (3) an AC/DC/AC tie is established near Rapid City,
South Dakota, to connect the western electric transmission and eastern electric
transmission grids of the United States; or (4) the FERC revises the rates
Black Hills Power charges the Cooperatives. Finally, to the extent that a
transmission customer (other than Black Hills Power or the Cooperatives)
arranges for transmission service on the Cooperatives' transmission facilities
as defined in the 1986 Agreement for the purposes of serving the transmission
customer's retail customers within the joint transmission area as defined
within the 1986 Agreement, Black Hills Power shall provide a credit, not to
exceed its tariff rate, against their rates for transmission service it charges
to such transmission customer for its use of the Cooperatives' transmission
facilities to serve the transmission customer's retail customers within the
joint transmission area.
Because Rule 888 now gives the cooperatives the full use of the transmission
system, in another FERC proceeding, Black Hills Power has filed a complaint
against the Cooperatives asking the FERC to modify the transmission contract
with the cooperatives so that the Cooperatives will in the future be obligated
to pay a just and reasonable rate that would fairly allocate the capital costs
of the transmission system to reflect the cooperative's use of that system.
No further action has occurred in the complaint filed by Black Hills Power
against the Cooperatives and Black Hills' request to require the Cooperatives
to pay a just and reasonable rate for their use of the transmission system.
In view of the uncertainty as to how the FERC will administer the new Rule 888
in ordering open access transmission and the uncertainty of whether the FERC
will interfere with existing transmission contracts, the Company can give no
opinion as to the outcome of the FERC proceedings outlined above. However,
Black Hills Power does not anticipate any material use of its transmission
system by third-parties until such time that retail wheeling may be instituted.
It is uncertain at this date as to what extent the FERC or the state regulatory
jurisdictions will have jurisdiction over determining retail wheeling rates.
(See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)
OTHER LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in minor routine administrative
proceedings and litigation incidental to the businesses, none of which, in the
opinion of management, will have a material effect on the consolidated
financial statements of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter
of 1997.
PART II
ITEM 5. MARKET FOR REGISTRANT'S
COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The Company's Common Stock ($1 par value) is traded on The New York Stock
Exchange. Quotations for the Common Stock are reported under the symbol BKH.
At year-end, the Company had 6,539 common shareholders of record. All 50
states and the District of Columbia plus 8 foreign countries are represented.
The Company has declared Common Stock dividends payable in cash in each year
since its incorporation in 1941. At its January 1998 meeting, the Board of
Directors raised the quarterly dividend to 25.0 cents per share, equivalent to
an annual increase of 5.3 cents per share. This regular quarterly dividend is
payable March 1, 1998. Dividend payment dates are normally March 1, June 1,
September 1, and December 1.
Quarterly dividends paid and the high and low Common Stock prices for the last
two years adjusted for the 3-for-2 Common Stock split in March 1998 were as
follows:
Year ended December 31, 1997
1ST 2ND 3RD 4TH
Dividends paid
per share $0.237 $0.237 $0.237 $0.237
Common stock
prices
High $19.25 $19.67 $19.75 $24.29
Low $17.50 $17.58 $17.92 $19.50
Year ended December 31, 1996
1ST 2ND 3RD 4TH
Dividends paid
per share $0.230 $0.230 $0.230 $0.230
Common stock
prices
High $17.50 $17.50 $17.33 $19.17
Low $15.50 $15.75 $15.17 $15.83
ITEM 6. SELECTED FINANCIAL DATA
The following data was derived from the Company's audited financial statements.
Years ended December 31 1997 1996 1995 1994 1993
(in thousands, except per share amounts)
Operating revenues $313,662 $162,588 $149,817 $145,402 $139,373
Net income 32,359 30,252 25,590 23,805 22,946
Per share of common stock*:
Earnings - basic
and diluted 1.49 1.40 1.19 1.11 1.11
Dividends paid 0.95 0.92 0.89 0.88 0.85
Total assets 508,741 467,354 448,830 436,877 352,853
Long-term debt 163,360 164,691 166,069 128,925 85,274
* The per share of common stock information has been restated to reflect the
3-for-2 Common Stock split in March 1998.
Quarterly financial data for the years indicated are summarized as follows:
1ST 2ND 3RD 4TH
Year ended December 31, 1997
Operating revenues $43,879 $40,259 $98,182 $131,342
Operating income 15,707 12,894 15,642 14,667
Net income 8,586 6,762 8,644 8,367
Earnings per share* 0.39 0.31 0.40 0.39
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* 0.37 0.27 0.38 0.38
*The earnings per share amounts have been restated to reflect the March 1998
stock split.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
The Company generated cash from operations sufficient to meet operating needs,
pay dividends on common stock and finance a portion of capital requirements.
Except for the construction of NS #2, a new power plant which began commercial
operation in August 1995, property additions from 1995 through 1997 were
primarily for the replacement of equipment, modernization of facilities, oil and
gas investment and expansion of energy marketing operations. The primary
capital requirements of the Company for the past three years were as follows:
1997 1996 1995
(in thousands)
Construction of NS #2 $ - $ - $33,219
Other property additions 21,186 24,576 18,676
Common stock dividends 20,540 19,930 19,312
Energy marketing assets 7,232 - -
Maturities/redemptions of long-term debt 1,534 1,405 10,499
$50,492 $45,911 $81,706
Capital requirements for projected construction, capital improvements, oil and
gas investments and corporate development activities for the next three years
are estimated to be as follows:
1998 1999 2000
(in thousands)
Electric:
Production $ 928 $ 972 $ 959
Transmission 5,395 1,993 3,010
Distribution 7,811 8,002 8,083
General 1,890 2,400 2,378
16,024 13,367 14,430
Coal mining 1,306 2,466 4,546
Oil and gas 11,047 10,000 10,000
Corporate development 20,000 10,000 10,000
$48,377 $35,833 $38,976
The electric and coal mining operations' forecasted expenditures include the
replacement of equipment and modernization of facilities. Forecasted
expenditures for the oil and gas operations are dependent upon future cash
flows and include an active development and exploratory drilling program and
acquisition of existing producing properties. Forecasted investment in
corporate development activities are dependent on market conditions at the time
and the Company's ability to identify opportunities consistent with its
corporate strategy. WYGEN, Inc., DAKSOFT, Inc., Black Hills Energy
Resources, Inc. (formerly Wickford Energy Marketing, Inc.), VariFuel, Inc. and
Enserco Energy, Inc., do not have any forecasted capital expenditures that are
significant. WYGEN was formed as an exempt wholesale generator and will not
incur substantial costs until and unless long-term power sale contracts are
obtained. DAKSOFT was formed to develop and market internally generated
computer software associated with the Company's business
segments. Black Hills Energy Resources, Inc. and VariFuel, Inc. were acquired
in 1997 and are energy marketing companies. Enserco was formed in 1996 as an
energy marketing company. The energy marketing companies are generally not
capital intensive businesses. If long term sales agreements are reached
requiring capital expenditures, such expenditures will be evaluated at that
time.
Electric operations is the only segment of the Company's business with long-
term debt. Long-term debt sinking fund requirements are: $1,331,000 in 1998,
$1,330,000 in 1999 and $1,330,000 in 2000.
Under its mining permit, Wyodak Resources is required to reclaim all land where
it has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual
basis, much of the reclamation occurs over an extended period after the area is
mined. Approximately $700,000 is charged to operations as reclamation expense
annually. As of December 31, 1997, accrued reclamation costs were
approximately $16,700,000 which includes $7,957,000 for the 1996 Clovis Point
Mine Acquisition. (See Acquisition of Clovis Point Mine Properties following
this section.)
The Company has a Dividend Reinvestment and Stock Purchase Plan, under which
shareholders may purchase additional shares of Common Stock through dividend
reinvestment or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing
the shares on the open market. The Company used the open market purchase
option for all of 1997, 1996 and 1995.
Under a 1994 shelf registration, the Company issued bonds in the amount of
$30,000,000 on February 3, 1995 and $15,000,000 on July 14, 1995. The
$30,000,000 bond issue has a 15-year life with an 8.06 percent rate of
interest; and the $15,000,000 bond issue has a 7-year life with a 6.5 percent
rate of interest. The $30,000,000 bond issue is redeemable at the option of
the holders in integral multiples of $1,000 on February 1, 2002. The debt
component of the Company's capital structure at December 31, 1997 and 1996, was
44 percent and 46 percent, respectively. The Company does not anticipate any
additional long-term debt financings in the next three years and would expect
the debt ratio to decrease to approximately 40 percent over the next 3 to 5
year period unless the WYGEN project is constructed or significant other
development opportunities are consummated. (See ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-
RESULTS OF OPERATIONS-Independent Power Business.)
The Company had $12,000,000 of unsecured short-term lines of credit at December
31, 1997 and 1996, which provide for interim borrowings and the opportunity for
timing of permanent financing. There were no borrowings outstanding under
these lines of credit as of December 31, 1997. Borrowings outstanding under
these lines of credit were $120,000 as of December 31, 1996 at a weighted
average interest rate of 8.0 percent. There are no compensating balance
requirements associated with these lines of credit.
In addition to the above lines of credit, Black Hills Energy Resources has a
$65,000,000 uncommitted line of credit with a national bank ($50,000,000 for
letters of credit and $15,000,000 for working capital) to provide credit
support for purchases and sales of natural gas and crude oil. The Company does
not provide credit support for this agreement. At December 31, 1997, there
were outstanding letters of credit totaling $29,000,000 which reduced the
available credit to $36,000,000.
In addition to the above lines of credit, Black Hills Energy Resources has
guaranteed a $15,000,000 line of credit for Enserco to use to guarantee letters
of credit. Enserco pays a 0.125 percent facility fee on this line of credit.
At December 31, 1997, there were no balances outstanding on this line of
credit.
In the past, the Company has relied upon internally generated funds, issuance
of short and long-term debt and sales of common stock to finance its
activities.
Credit ratings for the Company's First Mortgage Bonds are at an A1 level at
Moody's Investors Service, Inc. and at an A+ at Standard & Poor's. These
ratings reflect the respective agencies' opinions of the credit quality of the
Company's first mortgage bonds.
ACQUISITION OF CLOVIS POINT MINE PROPERTIES
In September 1996, Wyodak Resources entered into an agreement to purchase the
Clovis Point Mine properties from Kerr-McGee Coal Corporation. The Clovis
Point Mine properties are located adjacent to Wyodak Resource's current
reserves in Campbell County, Wyoming, and consist of State of Wyoming and
federal leased coal reserves.
Acquisition of the property increased the Company's 1996 recoverable reserves
from 170 million tons to approximately 288 million tons and included a train
loadout facility, maintenance and processing facilities and a developed open
pit.
The purchase price consisted of the assumption of the responsibility to reclaim
the existing Clovis Point open pit and the payment of overriding royalties to
Kerr McGee if and when coal is produced from the acquired properties. Wyodak
Resources is not obligated to mine the coal. (See NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS - Note 7.) The acquisition was subject to the approval of
the Bureau of Land Management(BLM) of the United States of a logical mining unit
(LMU) including the newly acquired Clovis Point Mine. The Company received the
BLM approvalin 1997. The Board of Land Commissioners of the State of Wyoming
approved the transfer of the state lease in 1996. The modified LMU meets all
requirements of the laws and regulations for an LMU.
RATE REGULATION
COMMERCIAL OPERATION OF NS #2 AND THE RELATED RATE RECOVERY
NS #2, an 80 megawatt coal-fired electric generating plant located adjacent to
the Company's coal mine, began commercial operation in August 1995. The cost
of the plant was approximately $122,000,000 which was $2,900,000 under the
initial project budget. A portion of the generation from the plant replaced
power Black Hills Power was purchasing from other sources.
Black Hills Power was authorized a 6.76 percent increase in electric rates
charged its South Dakota customers (representing approximately 81 percent of
1995 sales) effective August 1, 1995, an 8.97 percent increase for its Wyoming
retail customers (representing approximately 8 percent of 1995 sales) effective
August 16, 1995, and a 12.3 percent increase for its only wholesale customer in
1995, the City of Gillette (representing approximately 10 percent of 1995
sales), effective September 6, 1995. The increase for the City of Gillette
was reduced to an 8.8 percent increase commencing January 1, 1997, when Black
Hills Power began to receive additional revenue from wholesale sales to MDU for
its Sheridan, Wyoming, service territory. (See ITEM 1. BUSINESS - ELECTRIC
SERVICE TERRITORY AND SALES - Wholesale to City of Gillette; Wholesale to MDU.)
The South Dakota and Wyoming settlements further provide that unless an
extraordinary event occurs, Black Hills Power will not file for any increase in
rates or invoke any fuel and purchased power automatic adjustment tariff to
take effect during a freeze period ending January 1, 2000. The specified
extraordinary events are: new governmental impositions increasing annual costs
in South Dakota above $1,000,000 or $325,000 in Wyoming, forced outages of
both the Wyodak Plant and NS #2 projected to continue at least 60 days in South
Dakota and three months in Wyoming, forced outages occurring to either plant
which are continued for a period of three months or projected to last at least
nine months and an increase in the Consumer Price Index at a monthly rate for
six consecutive months which would result in a 10 percent or more annual
inflation rate.
During the freeze period, Black Hills Power is undertaking the risks of
machinery failure, load loss caused by either an economic downturn or changes
in regulation, increased costs under existing power purchase contracts over
which the Company has no control, government interferences, acts of nature and
other unexpected events that could cause material losses of income or increases
in costs of doing business. However, the settlement anticipates that Black
Hills Power will retain during that period of time earnings realized from more
efficient operations, sales from load growth, and off-system sales of power and
energy, including the sale to MDU. (See ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - BUSINESS OUTLOOK
STATEMENTS.)
LONG-TERM CONTRACTS
As a result of rate negotiations, Black Hills Power was successful in entering
into long-term contracts with most of its industrial and large commercial
customers. The all requirements electric service agreement with Homestake
Mining Company expires September 9, 2002, and the other contracts have terms of
five years that begin to expire in 2000. However, each of the contracts
provides options for the customer to keep the term of the contract extended for
at least three years, with the proviso that if the customer allows the term to
reduce to less than two years, Black Hills Power will be able to invoke a
planning surcharge on that customer. If deregulation in retail electric sales
occurs, the contracts give Black Hills Power notice to allow for planning to
make the transition to full competition, guard against stranded investment and
protect other customers from rate impacts of unexpected load loss. However,
management cannot predict if the notice period would be sufficient to fully
adapt for competition. These industrial and large commercial customers,
together with the wholesale power sales agreements to the City of Gillette and
MDU, result in approximately 40 percent of Black Hills Power's firm load under
these term contracts.
BUSINESS DEVELOPMENT RATES
Both the SDPUC and the WPSC authorized Black Hills Power to negotiate rates
above its marginal costs but below full cost with any customer with a load of
over 250 KVA if that customer has a legal choice of its electric supplier.
Black Hills Power expects to utilize this tariff in those instances where a new
business would have a choice of locating in the service territory of either
Black Hills Power or a competing REC or enticing a new business to locate or
relocate in Black Hills Power's service territory. Black Hills Power has
available resources to compete for new large load customers through this new
tariff.
COMPETITION IN ELECTRIC UTILITY BUSINESS
CURRENT STATUS OF COMPETITION FOR SERVICE AT RETAIL
In addition to Black Hills Power, RECs and the federal government through WAPA
provide electric service in and around the service territory of Black Hills
Power. Black Hills Power's transmission system is interconnected to Pacific
Power's transmission system near Gillette, Wyoming, and to WAPA's system near
Scottsbluff, Nebraska. Pacific Power provides electric service at retail to
large portions of Wyoming. Black Hills Power and the RECs serve in territories
which are protected by state laws or regulations which generally give each
entity the exclusive right to serve retail customers in its respective
territory; however, these laws or regulations are subject to change and there
are certain exceptions. In South Dakota, the SDPUC may allow a new customer
with a load of over 2,000 kilowatts to choose to be served by a utility other
than the utility in whose territory the new customer locates. In Wyoming,
public utilities operate in service territories assigned by the WPSC, and a
franchise granted by the municipality's governing body is required to serve
within a municipality. Black Hills Power may apply for and obtain the right to
serve in another utility's electric service territory if it is found to be in
the public interest to do so, but such applications are rarely granted.
The respective service territories of Black Hills Power and the RECs were
originally assigned based on where each was serving at the time of assignment.
Since the RECs were serving in rural areas (the purpose for which they were
formed), a large portion of the rural area surrounding the municipalities in
which Black Hills Power serves constitutes REC service territory. Although
Black Hills Power has traditionally served considerable territory outside of
municipalities and, therefore, has been assigned a large amount of such
territory, the RECs have the largest portion of such area and, if the laws are
not changed, will over a long period of time tend to receive a larger portion
of the growth of the population centers.
Every municipality in Black Hills Power's service territory has the right, upon
meeting certain conditions, to acquire or construct a municipally owned
electric system and to serve customers within its city. As a wholesaler of
electric power and energy, such municipality would have the power to demand and
receive transmission access over Black Hills Power's transmission system
consistent with its open access transmission tariff. The FERC has recognized
the principle that a city, which establishes a municipal electric system and
buys power from a supplier other than its former electric utility, should
compensate the former supplier for any stranded costs caused by the change in
the power supplier. However, the Company can give no assurances to what extent
the stranded cost provisions will be administered or how they would be applied
to Black Hills Power. Black Hills Power is not aware of any movement by any
municipality in its service territory which does not already have a municipally
owned electric system to establish one.
The primary competing fuel in Black Hills Power's territory is natural gas
which is available to approximately 80 percent of its customers.
COMPETITION IN ELECTRIC GENERATION
The business of electric generation is no longer reserved exclusively for the
traditional public utility such as Black Hills Power. The Energy Policy Act of
1992 exempted independent power producers engaged exclusively in the sale of
power at wholesale from the onerous restrictions of the Public Utility Holding
Company Act. The Public Utility Regulatory Policies Act of 1978 (PURPA)
authorizes entities generating electricity from waste fuel and renewable fuel
or utilizing steam for both generation and other purposes to force a public
utility to purchase the energy at an avoided cost. These laws, together with
the FERC mandating all public utilities under its jurisdiction to file tariffs
providing transmission access for sales of energy at wholesale, have caused
electric generation and the marketing of electric energy at wholesale to become
extremely competitive. While independent power producers, other than
qualifying facilities under PURPA, are regulated by the FERC, the FERC is
allowing rates for the sale of generation to be determined by the market rather
than by costs if the producer or marketer can demonstrate no market power.
As a result of these changes in the law and regulations, the traditional public
utility, such as Black Hills Power, is more likely to purchase energy required
for its franchised service territories through competitive bidding and either
not expand its rate base generating capabilities or engage in the electric
generation business through independent power producers by selling to other
utilities. (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS -RESULTS OF OPERATIONS - Independent Power
Business.)
Future generation, whether constructed by a public utility or an independent
power producer, is likely to be justified strictly on the basis of the
marketability of the capacity and energy from the new source in a competitive
market.
Black Hills Power could face the competition of industrial and public customers
constructing self-generation facilities using alternative fuels, such as waste
material, natural gas or oil. To date, Black Hills Power has not faced any
material competition from such sources and management does not believe that
such sources are cost effective, but no assurances can be given that material
competition from these sources will not occur.
TRANSMISSION ACCESS
In 1996, the FERC adopted Rule 888 that requires each public utility under its
jurisdiction to file open access transmission tariffs that provide rates which
are comparable to the same transmission costs of the public utility to transmit
power over its system. The rates provide for various transmission services to
be provided for any competitor but apply to the transmission of electric power
for wholesale purposes only. Black Hills Power filed an application with the
FERC in 1996 to approve its open access transmission tariffs. The regulations
further require the public utility to keep posted for public access, on an
electronic bulletin board, all current information concerning the availability
and rates for these transmission services. Black Hills Power was granted an
extension by FERC to delay establishing an electronic bulletin board until
WAPA, which operates the control area in which Black Hills Power is located,
establishes or participates in an electronic bulletin board. The public
utilities are further required by FERC to adopt standards of conduct which
require the functional separation of those persons who operate and market the
transmission system from those persons who buy and sell power for the same
utility; however, the FERC granted a waiver to Black Hills Power from the
requirement to adopt the standards of conduct in view of Black Hills Power's
small transmission system and lack of significant market control. The
regulations are designed to attempt to eliminate any market advantage of the
utility owning transmission over others engaged in the sale of electric power
at wholesale.
The new FERC regulations requiring the filing of open access tariffs does not
apply to the nonjurisdictional utilities such as the RECs and publicly owned
electric utilities. However, these nonjurisdictional utilities are subject to
the law that allows the FERC to force them to provide transmission services
upon application, and the FERC has adopted reciprocity regulations that would
authorize a jurisdictional utility to deny transmission access to a
nonjurisdictional utility which has denied access.
Black Hills Power currently furnishes transmission service for competing RECs
through contract. As long as the states in which Black Hills Power operates
continue to grant exclusive service territories, the federal government does
not preempt this state jurisdiction and municipalities in Black Hills Power's
service territory do not establish municipal electric systems, the increase in
transmission access for wholesale purposes through Black Hills Power's
transmission system is not likely to have any material adverse effect upon
Black Hills Power. Such open access may have a beneficial effect by opening
opportunities for the Company to further the marketing of coal-fired energy
outside of its service territory.
RETAIL WHEELING
Legislative proposals requiring a public utility to allow its competitors to
utilize the utility's electric distribution system to serve end-use customers
who are located in service areas assigned to that public utility, commonly
referred to as retail wheeling, are getting serious consideration in Congress
and in many states. Since the duplication of electric transmission and
distribution systems would neither be efficient nor tolerable by the public,
the transmission and distribution portion of the business is likely to continue
to be regulated with rates based on costs. The Company cannot predict when and
if mandated retail wheeling will come to the areas where it now provides
exclusive retail electric service. Major problems should be resolved first,
such as the preservation of reliable service, compensation to a utility for
investment incurred to fulfill its duty to serve but stranded because of
competition, fairness of market pricing between large industrial users and
small business and residential users and assurances that all utilities,
including the RECs, are bound to operate under the same rules. At this time,
South Dakota does not have any legislative activity regarding retail wheeling.
A committee of the Wyoming legislature considered an electric deregulation
bill for the 1998 session. The bill did not get out of committee, however, it
or an alternative bill could be introduced to the full Wyoming legislature for
consideration. The regulatory commissions in both states are considering the
potential impacts of electric utility industry restructuring. The Company is
unable to predict whether Congress or the states may in the future require
electric retail competition and, if they do, whether the ground rules for
competition will be fair to all participants.
Management is unable to predict the effect of full electric retail competition
on the Company's earnings. Management does anticipate that a transition period
of at least five years will be required to achieve a fully competitive electric
energy retail market. During that five years, Black Hills Power will endeavor
to increase its earnings through additional sales and cost containment. Based
upon the FERC's expressed positions concerning open access transmission
regulations, electric utilities which will lose revenues due to competition
should be allowed recovery of stranded costs. The market price of electric
energy in a fully competitive market is expected to be based upon a much wider
geographical area than just Black Hills Power's service territory. Because
energy providers are likely to seek the markets where the highest profit
margins can be realized, today's rates designed to serve exclusive service
territories may be substantially different for service to a fully competitive
market. Lower rates today are partially caused by excess generation capacity
which allows providers to sell energy above their marginal costs but below full
costs.
However, the Company is unable to predict future markets and economic
conditions and government actions or inaction that could have a materially
adverse affect on Black Hills Power's ability to compete in a fully competitive
electric power market and to maintain its equity return on investment. (See
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - BUSINESS OUTLOOK
STATEMENTS.)
REGULATORY ACCOUNTING
Black Hills Power follows Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation," and its
financial statements reflect the effects of the different ratemaking principles
followed by the various jurisdictions regulating Black Hills Power. As a
result of Black Hills Power's recent regulatory activity, a 50-year depreciable
life for NS #2 is used for financial reporting purposes. If Black Hills Power
were not following SFAS 71, a 35 to 40 year life would probably be more
appropriate which would increase depreciation expense by approximately $600,000
per year. If rate recovery of generation-related costs becomes unlikely or
uncertain, due to competition or regulatory action, these accounting standards
may no longer apply to Black Hills Power's generation operations. In the event
Black Hills Power determines that it no longer meets the criteria for following
SFAS 71, the accounting impact to the Company would be an extraordinary noncash
charge to operations of an amount that could be material. Criteria that give
rise to the discontinuance of SFAS 71 include increasing competition that could
restrict Black Hills Power's ability to establish prices to recover specific
costs and a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. The
Company periodically reviews these criteria to ensure the continuing
application of SFAS 71 is appropriate.
RESULTS OF OPERATIONS
CONSOLIDATED RESULTS
The Company reported record earnings for 1997 due to strong sales growth in
electric operations, record coal production and stable oil and gas results.
Consolidated net income for 1997 was $32,359,000 compared to $30,252,000 in
1996 and $25,590,000 in 1995 or $1.49 per average common share in 1997, $1.40
per average common share in 1996 and $1.19 per average common share in 1995.
This equates to a 15.8 percent return on year-end common equity in 1997, 15.7
percent in 1996 and 14.0 percent in 1995. Consolidated net income includes
noncash earnings of $3,645,000 for allowance for equity funds used during NS
#2 construction in 1995.
Consolidated revenue and net income (loss) provided by the four business
segments as a percentage of the total were as follows:
1997 1996 1995
Revenue:
Electric 40% 73% 73%
Coal mining 10 19 20
Oil and gas 4 8 7
Energy
marketing 46 - -
100% 100% 100%
1997 1996 1995
Net Income (Loss):
Electric 68% 61% 57%
Coal mining 28 32 38
Oil and gas 7 7 5
Energy marketing
and other (3) - -
100% 100% 100%
Dividends paid on common stock totaled $0.95 per share in 1997. This reflected
increases approved by the Board of Directors from $0.92 per share in 1996 and
$0.89 per share in 1995. All dividends were paid out of current earnings. The
Company's dividend objective is to increase the dividend at or above the
electric utility average and reduce the Company's payout ratio to the low 60's.
Management believes this objective is attainable through earnings growth. The
Company's three year dividend growth rate was 2.6 percent and the payout ratio
for 1997 was 63 percent.
In January 1998 the Board of Directors increased the quarterly dividend 5.6
percent to 25 cents per share. If this dividend is maintained during 1998, it
will be equivalent to $1.00 per share, an annual increase of 5 cents per share.
The Board of Directors, at its January 1998 meeting, declared a 3-for-2 Common
Stock split effected in the form of a stock dividend. The stock distribution
is payable March 10, 1998 to shareholders of record on February 13, 1998 and is
reflected in this report.
ELECTRIC OPERATIONS
1997 1996 1995
(in thousands)
Revenue $126,497 $118,718 $108,783
Operating
expenses 81,886 79,628 80,540
Operating income $ 44,611 $ 39,090 $ 28,243
Net income $ 22,106 $ 18,333 $ 14,569
Electric revenue increased 6.6 percent in 1997 compared to a 9.1 percent
increase in 1996 and a 3.8 percent increase in 1995. Firm kilowatthour sales
increased 13.0 percent in 1997 compared to a 3.9 percent increase in 1996 and a
0.5 percent increase in 1995 and have averaged an annual 5.7 percent growth
rate over the last three years.
The increase in electric revenue and firm kilowatthour sales in 1997 was
primarily due to the additional load to serve MDU's energy requirements for its
customers in the Sheridan, Wyoming area. Partially offsetting the increase,
residential sales declined 3 percent primarily due to milder weather. Degree
days, a measure of weather trends, were 15 percent below last year and 2
percent below normal.
The increase in electric revenue in 1996 was due to strong sales growth in all
sectors of the Company's electric business, including the industrial sector
which had a decrease in sales in 1995, and the inclusion of NS #2 in the
Company's rate base (See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - RATE REGULATION - Commercial
Operation of NS #2 and the Related Rate Recovery).
The increase in revenue in 1995 was primarily due to the increase in electric
rates and strong growth in the residential and commercial sectors of the
Company's electric business. While the residential and commercial sectors
which provide Black Hills Power with the highest margin sales showed strong
growth, the impact of this growth was partially offset by a 5.2 percent
decrease in kilowatthour sales to the industrial customers.
Revenue per kilowatthour sold was 5.5 cents in 1997 compared to 5.8 cents in
1996 and 6.1 cents in 1995. The number of customers in the service area
increased to 56,269 in 1997 from 55,601 in 1996 and 55,018 in 1995. The
revenue per kilowatthour sold in 1997 reflects the increased wholesale sales to
MDU's Sheridan, Wyoming customers and 279,600 megawatthours of wholesale non-
firm sales. The revenue per kilowatthour sold in 1996 and 1995 reflects the
increase in electric rates and the strong growth in the higher margin sectors
of Black Hills Power's business offset by the impact of 249,100 megawatt hours
of wholesale non-firm sales in 1996 and 60,575 megawatt hours in 1995.
Excluding Sheridan, Wyoming's sales and non-firm sales, the rate per
kilowatthour sold was 6.5 cents in 1997 and 1996 and 6.3 cents in 1995.
Operating expenses have remained fairly stable over the last three years. The
increase in operating expenses in 1997 are primarily due to the increased load
requirements to serve MDU's Sheridan, Wyoming energy needs. The increase in
operating expenses and depreciation associated with the commercial operation of
NS #2 were offset by a decrease in fuel and purchased power costs. Coinciding
with the commercial operation of NS #2, in 1995, the electric operations
realized a decrease in the cost of coal per ton charged by Wyodak Resources.
Over the past several years Black Hills Power was not allowed to include in
rates charged to its South Dakota customers any cost of coal which allowed
Wyodak Resources to earn a return on equity on sales of coal to Black Hills
Power in excess of a percentage equal to the rate on long-term "A" rated
utility bonds plus 400 basis points (4 percent). Any excess amount that was
charged was refunded to Black Hills Power's South Dakota customers through the
fuel and purchased power adjustment clause. Beginning with the commercial
operation of NS #2, Wyodak Resources changed its coal pricing methodology to
Black Hills Power making the price of coal equal to the above limitation
thereby eliminating the need for any further adjustment to the electric
operations revenue. The impact of this change reduced fuel expense for the
electric operations, reduced revenue for the coal mining operations and had no
material impact on the consolidated financial statements.
`
Depreciation expense decreased 9 percent in 1997 as a result of the 1996
accelerated depreciation of the Kirk Power Plant. Depreciation expense
increased 35 percent in 1996 related to a full year of depreciation on NS #2
and accelerated depreciation related to the Kirk Power Plant. The Kirk Power
Plant was placed in cold reserve in August 1995 and was fully depreciated at
December 31, 1996.
Firm energy sales are forecasted to increase over the next 10 years at an
annual compound growth rate of approximately 2 percent with the system demand
forecasted to increase 2.1 percent in the summer and 2.4 percent in the winter.
The Company currently has a winter peak of 327 MWs established in January 1997
and a summer peak of 346 MWs established in July 1997. These forecasts are
from studies conducted by the Company with the help of outside consultants
whereby Black Hills Power's service territory is examined and analyzed to
estimate changes in the needs for electrical energy and demand over a 20-year
period. These forecasts are only estimates, and the actual changes in electric
sales may be substantially different as was experienced with the industrial
sales growth in 1995. However, in the past the forecasts tracked actual sales
within a band of reasonableness over a period of several years. Weather
deviations can adversely effect energy sales when compared to forecasts based
on normal weather.
COAL MINING OPERATIONS
1997 1996 1995
(in thousands)
Revenue $31,080 $31,315 $29,870
Expenses 18,863 19,081 17,644
Operating income $12,217 $12,234 $12,226
Net income $ 9,073 $ 9,934 $ 9,737
Revenue decreased 1 percent in 1997 due to a decrease in the price charged to
the utility's operations. (See explanation of the change in coal pricing
methodology under Electric Operations). Wyodak Resources had record coal
production of 3,251,000 tons in 1997.
Revenue increased 4.8 percent in 1996 and 4.5 percent in 1995, due to a 10.5
percent and a 5.0 percent increase in tons of coal sold in 1996 and 1995,
respectively.
Operating expenses decreased 1 percent in 1997 due to lower revenue based taxes
other than income taxes and increased 8.1 percent in 1996 and 5.7 percent in
1995 reflecting the increase in tons of coal sold.
Non-operating income was $1,066,000 in 1997 compared to $2,725,000 in 1996 and
$2,279,000 in 1995. Non-operating income includes gains or losses on sale or
disposal of property and equipment and interest income from investments. Non-
operating income increased in 1996 due to a $700,000 gain realized on the
disposal of equipment and an increase in cash available for investment. Non-
operating income increased in 1995 due to a $700,000 gain realized on the
disposal of equipment offset by a decrease in interest rates.
Wyodak Resources expects relatively stable sales in 1998 absent unplanned
outages at the Wyodak Plant or Black Hills Power's plants.
OIL AND GAS OPERATIONS
1997 1996 1995
(in thousands)
Revenue $13,295 $12,555 $11,164
Expenses 10,388 9,574 9,471
Operating income $ 2,907 $ 2,981 $ 1,693
Net income $ 2,147 $ 2,198 $ 1,320
Net income and assets related to oil and gas operations have been 7 percent or
less of the Company's consolidated amounts over the last three years.
Western Production's product sales and product prices for the last three years
were as follows:
1997 1996 1995
Barrels of oil sold 299,000 286,000 266,000
Mcf of natural gas sold 1,747,000 1,718,000 1,986,000
Equivalent barrels
of oil sold 590,000 572,000 597,000
Price per barrel
of oil $19.05 $21.09 $17.09
Price per mcf of
natural gas $2.42 $2.05 $1.46
In 1997 and 1996, Western Production sold certain interest in natural gas
properties for $165,000 and $380,000, respectively. Such sales are not
expected to materially impact future production.
During 1995, Western Production sold its interest in several wells with
estimated net remaining reserves of 208,000 barrels of oil equivalent for
approximately $2,175,000. The impact of this sale reduced 1995 production by
approximately 100,000 equivalent barrels.
Western Production's production expenses increased 8.5 percent in 1997, 1.1
percent in 1996, and decreased 7.1 percent in 1995. Production expenses
increased in 1997 due to increased depletion as a result of increased oil and
gas production and lower crude oil prices. Production expenses decreased in
1995 reflecting lower depletion expense associated with higher oil prices and a
successful drilling program. Western Production recognized $3,920,000,
$3,434,000 and $3,730,000 of depletion expense in 1997, 1996 and 1995,
respectively. Low oil and gas prices reduce the cash flow and value of the
Company's oil and gas assets and will cause the Company to increase its
depletion expense.
Western Production's proved reserves and the revenues generated from production
decline as production occurs, except to the extent successful exploration,
development, and production enhancement activities are conducted or additional
proved reserves are acquired. Western Production has been active in
exploration and development drilling during the past three years.
Western Production's drilling results were as follows:
1997 1996 1995
GROSS NET GROSS NET GROSS NET
Wells drilled 37 7.1 52 7.0 22 5.2
Producing 22 3.5 35 4.7 14 3.8
Success Rate 59% 67% 64%
In 1997, Western Production acquired approximately 121,000 barrels of oil and
0.2 bcf of natural gas in the Finn Shurley Field for $455,000.
Western Production intends to increase its net proved reserves by selectively
increasing its oil and gas exploration and development activities and by
acquiring producing properties primarily with the use of internally generated
funds.
Western Production's reserves are based on reports prepared by Ralph E. Davis
Associates, Inc. Reserves were determined using constant product prices at the
end of the respective years. Estimates of economically recoverable reserves
and future net revenues are based on a number of variables which may differ
from actual results. Western Production's unaudited reserves, principally
proved developed and proved undeveloped properties, were estimated to be 2.5,
2.4, and 1.6 million barrels of oil and 9.1, 11.0 and 7.7 billion cubic feet
of natural gas as of December 31, 1997, 1996 and 1995, respectively. The
decrease in reserves at December 31, 1997 was due to lower oil and gas prices
and reductions in engineering estimates of recoverable reserves for certain
natural gas properties. The increase in reserves at December 31, 1996 was due
to a successful drilling program and higher oil and gas prices. The decrease
in reserves at December 31, 1995 was due to the sale of properties described
above and low gas prices.
ENERGY MARKETING OPERATIONS
Within the context of this report, an energy marketing company is a company
that sells and buys natural gas and electric power at market prices and
ordinarily does not participate in the production of energy. A marketing
company is not a traditional public utility servicing a franchised service
territory at rates that are just and reasonable based upon a rate of return on
an investment rate base as permitted by regulatory commissions.
Black Hills Capital Group, Inc. was incorporated by the Company to hold the
Company's equity and debt investments in Black Hills Energy Resources, Inc.
(formerly Wickford Energy Marketing, Inc.), VariFuel, Inc. and Enserco Energy,
Inc. (the energy marketing companies are described in more detail below). In
addition to the energy marketing companies, Black Hills Capital Group will be
the primary vehicle for future corporate development activities outside of the
internal company specific activities.
In 1997, Black Hills Capital Group incurred a net loss of $746,900 primarily
due to mild weather conditions in its target markets, start-up expenses and
additional administrative expenses to expand its energy marketing operations.
In July 1997, Black Hills Capital Group acquired the assets and hired the
operational management of Jomax Partners, L.P. as successor and survivor of
Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada Company.
Black Hills Energy Resources, Inc. (formerly Wickford Energy Marketing, Inc.)
is headquartered in Houston, Texas with a natural gas sales office in Calgary,
Alberta, Canada and crude oil sales offices in Tulsa, Oklahoma, and Midland,
Texas. Black Hills Energy Resources is a "niche" wholesale natural gas and
crude oil marketing company with expertise in Gulf Coast and Canadian supply,
targeting natural gas markets in the East Coast and Midwest and crude oil
markets primarily in the Southwest.
Since its acquisition in July 1997, Black Hills Energy Resources marketed
231,000 mmbtus of natural gas per day and 12,600 barrels of oil per day.
Wholesale natural gas and crude oil businesses are high volume, lower margin
operations. Operating revenues for natural gas and crude oil sales totaled
$94,295,000 and $46,810,000, respectively, for the five-month period since
acquisition. Cost of natural gas and crude oil sold (included in Fuel and
Purchased Power in the CONSOLIDATED STATEMENTS OF INCOME) relating to the above
revenues totaled $140,151,000 in 1997. With a full year of operations in 1998,
the Company expects revenues and related expenses to increase substantially
from 1997 levels, but does not expect Black Hills Energy Resources'
contribution to total Company operations to be significant.
Black Hills Energy Resources has a $65,000,000 uncommitted line of credit with
a national bank ($50,000,000 for letters of credit and $15,000,000 for working
capital) to provide credit support for purchases and sales of natural gas and
crude oil. The Company does not provide credit support for this agreement.
In November 1997, Black Hills Capital Group, Inc. acquired the assets and hired
the operational management of VariFuel, Inc. (VariFuel). VariFuel targets
commercial and industrial natural gas customers located primarily in the
Chicago, Illinois and northern Indiana area. VariFuel is headquartered in
Houston, Texas with a sales office in Chicago, Illinois. VariFuel's retail
marketing operations complement Black Hills Energy Resources' wholesale
marketing operations in the Midwest. The financial position and results of
operations of VariFuel are not significant to the Company at this time.
In 1996, Wyodak Resources, with the participation of three individuals, formed
an energy marketing startup company under the name of Enserco Energy, Inc.
(Enserco), headquartered in Lakewood, Colorado. Wyodak Resources acquired 50
percent of the capital stock of Enserco, and the other 50 percent was acquired
by three of the full-time officers of Enserco. However, to fund the startup
operations, Wyodak Resources acquired a convertible debenture from Enserco,
that Wyodak Resources has the right to convert to additional capital stock of
Enserco, which would increase Wyodak
Resources' ownership interest to 70 percent of the issued and outstanding
capital stock of Enserco.
To provide Enserco with the financial backing to participate in the purchase
and sale of natural gas and electric power, Wyodak Resources has agreed to
guarantee up to $15,000,000 of letters of credit to be issued by banks to
guarantee purchases and sales of natural gas and electric power.
Enserco has acquired the approval from the FERC of a tariff which allows
Enserco to sell electric power at market prices. Enserco is also qualified to
purchase and sell natural gas at market prices. Enserco is a startup company
and has not as yet realized a profit. Its operations are not material to the
Company at this time.
Although the energy marketing business is highly competitive, management is of
the opinion that due to the increasing competition in the energy business, it
is essential for many reasons to be active with the energy marketing business,
including the knowledge the Company gains in the marketing of energy, which is
required for the Company to effectively compete in all aspects of its energy
business.
The energy marketing companies anticipate generating large amounts of revenue
and corresponding expense related to buying and selling energy products.
Associated with the purchase and sale of energy products, the energy marketing
companies will use derivatives (exchange traded and over-the-counter energy
financial instruments) to manage risk associated with the buying and selling
of energy products whose prices can be extremely volatile. The use of
derivatives helps mitigate risk in the trading of energy products but does not
eliminate the risk. Wyodak Resources and the energy marketing companies have
adopted risk management policies and established risk management committees to
further mitigate risk associated with the sale and purchase of energy products.
Some purchasers and sellers with whom the energy marketing companies transact
business require the utilization of letters of credit to assure the underlying
performance of the obligations between the parties. The failure of a party to
perform may result in a significant risk of loss to the energy marketing
companies and corresponding loss to Wyodak Resources as it concerns the
outstanding letters of credit to Enserco.
INDEPENDENT POWER BUSINESS
In 1994, Wyodak Resources formed a wholly owned subsidiary named WYGEN, Inc.
WYGEN applied for and received from the FERC a determination that WYGEN has
exempt wholesale generator status under Section 32 of the Public Utility
Holding Company Act. WYGEN was formed for the sole purpose of engaging in the
generating and selling of electric power and energy at wholesale. At this time
WYGEN is proposing to build an 80 megawatt coal-fired electric generating plant
to be known as the WYGEN Plant adjacent to NS #2. In 1996, WYGEN received a
prevention of significant deterioration air quality construction permit from
the DEQ. Construction must commence within
two years of the granting of the permit or WYGEN will be required to reapply.
As an independent power project, the air quality permit is the only major
permit required. WYGEN plans to renew this permit in 1998.
Viable markets for the electric power and energy from the WYGEN Plant will
depend partially upon the cost of transmission rights to deliver the electric
power and energy to higher priced energy markets. While the FERC's open access
transmission regulations should make such transmission legally available,
physical transmission constraints or the perception of such constraints may
require WYGEN's participation in transmission improvements which, together with
transmission rates for access across transmission systems, could make the WYGEN
Plant less economical. The economics of delivering power over multiple-owned
transmission systems will depend upon how successful the FERC is in bringing
about regional transmission systems operated independently of the interest of
any one provider, with mechanisms to pool costs and cause transmission system
improvements to be constructed, on a timely basis, with broad participation.
In addition, to the WYGEN Project, the Company is exploring opportunities for
participating in the acquisition of existing or new independent power projects
fueled by coal or natural gas and located at Wyodak Resources' mine or at other
locations in the United States.
OTHER SEGMENTS OF BUSINESS
DAKSOFT, Inc. was incorporated by the Company in 1994, to develop and market
internally generated computer software associated with the Company's business
segments. Additionally, DAKSOFT has developed internet/intranet products which
are currently being used internally and marketed to third parties. No
significant revenues have been received to date. DAKSOFT entered into a
multiyear enhancement and sales contract in 1995. The revenue from this
contract is earned as the product enhancement occurs. Approximately $219,000,
$370,000 and $290,000 of revenue was recognized in 1997, 1996, and 1995,
respectively. Also, in 1997, DAKSOFT entered into an implementation and
enhancement agreement for the customized installation of its Customer
Information System (CIS) product. Revenue from such installation and
enhancement agreement totaled $457,000 in 1997.
Landrica was incorporated by the Company in March 1984, and holds minor
interests in real estate.
The financial position and results of operations of WYGEN, DAKSOFT and
Landrica are not material to the Company.
YEAR 2000 ISSUES
The Company uses technologies throughout its operations that will be affected
by year 2000 issues. During 1997, the Company implemented remediation steps to
make the core business systems which are part of the Company's mid-range
computer systems year 2000 compliant. The Company also has initiated a
company-wide project, to be completed in 1998, to identify and assess year 2000
compliance for all other Company systems and the compliance status of its
critical suppliers. The expenses relating to year 2000 compliance incurred in
1997 were not material, and the Company believes the amounts that are expected
to be expensed in the future for such compliance will not have a material
impact on its results of operations.
NEW ACCOUNTING PRONOUNCEMENT
In March 1997, the Financial Accounting Standards Board released Statement of
Financial Accounting Standards No. 128, Earnings per Share, (SFAS 128) which
requires the disclosure of basic earnings per share and diluted earnings per
share. The diluted earnings per share recognizes the impact of the Company's
stock option plans (See NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 2
Common Stock) as if fully vested at the grant date. Adoption of this statement
did not have a material affect on the results of operations or financial
position of the Company.
BUSINESS OUTLOOK STATEMENTS
The following statements are based on current expectations. These statements
under this Business Outlook Statements section are forward-looking, and actual
results may differ materially.
PACIFIC POWER'S POWER SALES AGREEMENT
Pacific Power's Power Sales Agreement represents Black Hills Power's highest-
cost electric power resource. Black Hills Power expects to reduce these costs
in the future through better utilization of the resource and as a result of the
Second Restated and Amended Power Sales Agreement executed between Pacific
Power and Black Hills Power. This Second Restated and Amended Power Sales
Agreement, effective August 1, 1997, and terminating December 31, 2023,
supersedes the Restated Agreement, which was intended to be effective January
1, 2000.
Black Hills Power has been able to utilize the 75 MW resource from Pacific
Power's Power Sales Agreement at a load factor of only 55 percent. Black Hills
Power anticipates higher utilization of this resource in the future and
lowering the average cost per megawatt hour through an active marketing program
to sell the power and energy. This marketing program will include the use of
the Pacific Power's Power Sales Agreement contract under which Black Hills
Power has the right to cause the power and energy to be delivered at any
point on Pacific Power's transmission system (defined as both Pacific Power's
owned and contracted transmission paths) where capacity is available.
The Second Restated Agreement provides (i) that 25 megawatts of the contract
capacity amount and the charges thereof will be deleted, 5 megawatts each year
commencing in the year 2000, (ii) Black Hills Power shall pay no levelized
annual charges for Colstrip Plants' additions and replacements which are
completed after January 1, 1997, (iii) that commencing January 1, 1997, all
fixed cost components of the Variable Costs to be paid by the company shall be
based on an assumption that the Colstrip Plants operated at an 80 percent load
factor, (iv) beginning August 1, 1997 and continuing until December 31, 1999,
Black Hills Power shall pay Pacific Power annual fixed cost of $164.59 per kW-
yr multiplied by the capacity purchased, (v) commencing January 2000 and
continuing until December 2018, Black Hills Power shall pay Pacific Power's
initial investment in Colstrip Units 3 and 4 using Pacific Power's then most
current applicable cost of capital consisting of Pacific Power's then current
FERC approved capital structure, Pacific Power's then current weighted average
cost of long-term debt and preferred stock using FERC approved methods and
Pacific Power's then current FERC approved cost of common equity, (vi) that
for the invoices the fixed amount calculated above shall be reduced by $95,564
each month for the years 2000 through 2009, and (vii) unbundling of the
transmission charge in the contract to Pacific Power's FERC-filed rates.
Future cost reductions or increases related to these amendments will depend on
Pacific Power's future capital structure and cost of capital and the cost of
replacement power starting in the year 2000. However, the Company believes the
reduction of the 25 MWs of capacity which begins in the year 2000 at a rate of
5 MW a year is positive as the Company enters a deregulated electricity market
and believes Pacific Power's future cost of capital under the FERC approved
capital structure will be lower than the cost of capital formulas embedded in
the existing contract.
FUTURE ELECTRIC SALES
Future earnings from all power sales are dependent on many economic and
political factors, including the move toward competition at the retail level,
the market price of electricity, the ability of Black Hills Power to generate
and deliver electric power at a cost that will allow a profit margin and the
regulatory treatment of electric utilities during the transition period toward
competition.
In order to realize a higher margin of profit than from sales on the spot
market, Black Hills Power continues to look for opportunities to sell power
off-system over a term of six months or longer. The highly competitive
wholesale electric power market, the lack of an open retail market at this
time, the cost of transmission to deliver the power to markets where prices are
higher, the current low natural gas prices and the availability of surplus
capacity and energy are the current competitive conditions that make it
difficult to find new markets. However, management believes that Black Hills
Power's marginal production costs are low enough and the quantity of power
Black Hills Power has available high enough that new opportunities for off-
system sales are feasible.
FUTURE RETAIL WHEELING
Management is unable to predict the effect of full electric retail competition
(if it comes about) on the Company's earnings. Management does anticipate that
a transition period of at least five years will be required to achieve a fully
competitive electric energy retail market. Black Hills Power continues to
endeavor to increase its earnings through additional sales and cost
containment. Based upon the FERC's expressed positions concerning open access
transmission regulations, electric utilities which will lose revenue due to
competition should be allowed to recover stranded costs. The market price of
electric energy in a fully competitive market is expected to be based upon a
much wider geographical area than just Black Hills Power's service territory.
Because the energy providers are likely to seek the markets where the highest
profit margin can be realized, today's rates designed to serve exclusive
service territories may be substantially different for service to a fully
competitive market. Based upon industry predictions, management believes that
the industry's excess capacity will be more fully utilized in the future.
Management believes that coal-fired plants will become more competitive with
natural gas-fired plants in the future as natural gas prices increase.
However, the Company is unable to predict future markets and economic
conditions and government actions or inactions that could have a materially
adverse effect on Black Hills Power's ability to compete in a fully competitive
electric power market and to maintain its equity return on investment.
RATE REGULATION
Management's expectation is that the rate settlements made with the South
Dakota and Wyoming Commissions are beneficial in that (i) management has
confidence in the operational capability of Black Hills Power's power plants;
(ii) management does not anticipate purchasing any substantial amount of
capacity and energy during the freeze period except for its existing purchase
power agreements; and (iii) Wyodak Resources' mining costs are not expected to
materially increase.
FUTURE COAL SALES
Because of an acquisition of unit train load-out facilities with the Clovis
Point Mine Properties, Wyodak Resources expects to increase its market
opportunities. However, the heating value (approximately 8,000 Btu per pound)
of the coal at Wyodak Resources' mine and the Clovis Point Mine Properties is
approximately 400 to 800 Btus less than Powder River Basin coal available at
other locations. This difference makes Wyodak Resources' coal noncompetitive
in the current market for coal to be shipped by rail over long distances
because of higher freight rates per Btu. Notwithstanding this limitation, the
acquisition of a unit train loadout facility has led management to investigate
opportunities for Wyodak Resources to ship coal by rail at closer distances
where the Btu difference would not be a major factor, and to ship coal that is
enhanced at the coal mine site by various processes, one of the results of
which would remove some of the moisture content of the coal and thereby
increase the Btu per pound content. Processes for the enhancement of Powder
River Basin coal are being developed and seriously considered for commercial
operations by the coal industry. Management can give no assurances at this
time that any coal enhancement process is commercially practical in view of the
current low spot market price of Powder River Basin coal, that a market for
enhanced coal can be developed or that a coal enhancement project at Wyodak
Resources' mine would be feasible.
Freight rates to ship coal by rail are also a material factor in determining
the economic feasibility of selling either raw run-of-the-mine coal or enhanced
coal products. At this time only one rail carrier, the Burlington Northern, is
available to Wyodak Resources for such sales. Reasonable freight rates are a
requirement for any rail transported sales from Wyodak Resources' mine.
FUTURE ENERGY MARKETING SALES
The profitability of the Company's energy marketing operations depends in large
part on management's ability to assess and respond to changing market
conditions. Such conditions include, but are not limited to, availability of
supply, availability of transportation capacity from supply area to markets
served and market demand. In addition, such operations are highly sensitive to
weather conditions in the markets served. The Company is unable to predict
future markets and economic conditions that could effect the profitability of
the energy marketing operations.
FUTURE CORPORATE DEVELOPMENT ACTIVITIES
The Company created a new subsidiary named Black Hills Capital Group, Inc. to
spearhead its corporate development activities. Black Hills Capital Group,
Inc.'s focus is to increase the Company's earnings and assets through energy
related investments that position the Company to earn multiple revenue streams
in the energy value chain. Potential investment could comprise of independent
power projects, coal reserves, oil and gas reserves, energy transportation
assets, energy marketing assets or other related assets. The success of the
Black Hills Capital Group acquiring such assets will depend on future market
conditions. The market for such assets is very competitive. The Company is
unable to predict future markets and economic conditions that could effect the
profitability and probability of the success of corporate development
activities.
RISKS AND UNCERTAINTIES
The forward looking statements contained in the Management's Discussion and
Analysis of Financial Condition and Results of Operations involve a number of
risks and uncertainties. In addition to factors discussed above, other factors
that could cause actual results to differ materially are the following: the
extent to which the federal government or the state governments, or both,
institute competition in the electric utility business; the market value of
electric power at the time full competition comes about, including any
competitor's delivery costs to Black Hills Power's current markets and Black
Hills Power's ability to produce and deliver power at those market prices; the
extent to which the surplus electric generation continues; the extent that any
electric generating surplus is exhausted and customers are again entering into
longer-term purchased power contracts with prices relating more to the full
cost of generating and delivering electric power; the future market prices of
crude oil, natural gas and coal; government regulations of the environment,
especially to the extent to which further financial burdens may be placed upon
coal versus natural gas and additional governmental burdens that may be placed
upon the burning of all fossil fuels; the extent to which competition will be
fairly administered for participants in the electric utility business and
whether it will be applied equally to investor-owned companies, rural electric
cooperatives, public power agencies and municipalities; technological advances
in the generation and delivery of electric power; the general economy as it
affects the use of electric power; the market price of competing fuels to
electricity, such as natural gas; the extent to which coal
beneficiation programs are efficiently developed and the extent to which the
new coal products will be accepted by the market; the general economy of Black
Hills Power's retail service territory; and other risk factors which are
referenced in this report and other SEC reports filed prior hereto.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants 32
Consolidated Statements of Income and Retained Earnings
for the three years ended December 31, 1997 33
Consolidated Statements of Cash Flows for
the three years ended December 31, 1997 34
Consolidated Balance Sheets as of December 31, 1997 and 1996 35
Consolidated Statements of Capitalization as of
December 31, 1997 and 1996 36
Notes to Consolidated Financial Statements 37
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Black Hills Corporation:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Black Hills Corporation and Subsidiaries as of December 31,
1997 and 1996, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended
December 31, 1997. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Black Hills Corporation and
Subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 28, 1998
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31 1997 1996 1995
(in thousands, except per share amounts)
Operating revenues:
Electric $126,497 $118,718 $108,783
Coal mining 31,080 31,315 29,870
Oil and gas 13,295 12,555 11,164
Energy marketing 142,790 - -
313,662 162,588 149,817
Operating expenses:
Fuel and purchased power 177,071 34,195 39,265
Operations and maintenance 31,743 30,343 28,523
Administrative and general 11,642 8,491 9,226
Depreciation, depletion and
amortization 22,311 22,794 19,660
Taxes, other than income taxes 11,985 12,460 10,981
254,752 108,283 107,655
Operating income (loss):
Electric 44,611 39,090 28,243
Coal mining 12,217 12,234 12,226
Oil and gas 2,907 2,981 1,693
Energy marketing (825) - -
58,910 54,305 42,162
Other income (expense):
Interest expense (14,123) (13,942) (14,195)
Investment income 2,136 1,373 1,368
Allowance for funds used during
construction 188 350 5,867
Other, net (426) 1,744 1,125
(12,225) (10,475) (5,835)
Income before income taxes 46,685 43,830 36,327
Income taxes (14,326) (13,578) (10,737)
Net income $ 32,359 $ 30,252 $ 25,590
Earnings per share of common stock:
Basic and diluted $1.49 $1.40 $1.19
Weighted average common shares outstanding:
Basic 21,692 21,660 21,614
Diluted 21,706 21,660 21,614
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31 1997 1996 1995
(in thousands)
Balance, beginning of year $131,884 $121,562 $115,284
Net income 32,359 30,252 25,590
Cash dividends on common stock
($0.95, $0.92 and $0.89 per share,
respectively) (20,540) (19,930) (19,312)
Balance, end of year $143,703 $131,884 $121,562
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31 1997 1996 1995
(in thousands)
Operating activities:
Net income $32,359 $30,252 $25,590
Principal non-cash items-
Depreciation, depletion and amortization 22,311 22,794 19,660
Deferred income taxes and investment tax
credits 2,457 1,872 2,097
Allowance for other funds used during
construction (99) (188) (3,645)
Increase in receivables, inventories and other
current assets (27,067) (373) (669)
Increase (decrease) in current liabilities 26,015 (1,412) (1,420)
Other, net 73 2,452 3,677
56,049 55,397 45,290
Investing activities:
Energy marketing assets (7,232) - -
Neil Simpson Unit #2 construction costs,
excluding allowance for other funds used
during construction - - (29,820)
Other property additions, excluding allowance
for other funds used during construction (21,087) (24,388) (18,430)
Available for sale securities purchased (31,944) (40,894) (19,323)
Available for sale securities sold 29,433 36,189 36,941
(30,830) (29,093) (30,632)
Financing activities:
Dividends paid (20,540) (19,930) (19,312)
Common stock issued 409 511 654
Repayment of short-term borrowings (120) (475) (36,400)
Long-term debt issued - 156 46,904
Long-term debt retired (1,534) (1,405) (10,499)
(21,785) (21,143) (18,653)
Increase (decrease) in cash and cash
equivalents 3,434 5,161 (3,995)
Cash and cash equivalents:
Beginning of year 13,340 8,179 12,174
End of year $16,774 $13,340 8,179
Supplemental disclosure of cash flow information:
Assumption of reclamation liability in acquisition
of Clovis Point Properties $ - $ 7,957 $ -
Clovis Point properties
Cash paid during the period for-
Interest $14,167 $13,996 $12,901
Income taxes $11,840 $12,616 $ 7,775
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
At December 31, 1997 1996
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 16,774 $ 13,340
Securities available for sale 13,969 11,458
Receivables, net
Customers 39,639 12,961
Other 3,414 2,727
Materials, supplies and fuel 8,642 7,861
Prepaid expenses 1,571 2,650
84,009 50,997
Property and equipment:
Electric 487,424 479,237
Coal mining 52,804 53,200
Oil and gas 52,412 45,336
Other 5,666 3,764
598,306 581,537
Less accumulated depreciation and depletion (197,179) (181,103)
401,127 400,434
Deferred charges:
Federal income taxes 8,061 7,972
Regulatory asset 3,776 3,176
Other 11,768 4,775
23,605 15,923
$508,741 $467,354
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of long-term debt $ 1,331 $ 1,534
Notes payable 23 143
Accounts payable 32,622 7,332
Accrued liabilities-
Taxes 8,040 8,633
Interest 3,991 4,035
Other 7,800 6,438
53,807 28,115
Deferred credits:
Federal income taxes 53,010 48,262
Investment tax credits 4,014 4,516
Reclamation liability 16,664 16,267
Regulatory liability 6,152 6,692
Other 6,331 5,636
86,171 81,373
Commitments and contingent liabilities (Notes 6, 7 and 8)
Capitalization, per accompanying statements:
Common stock equity 205,403 193,175
Long-term debt 163,360 164,691
368,763 357,866
$508,741 $467,354
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1997 1996
(in thousands)
Common stock equity:
Common stock $1 par value; 50,000,000
shares authorized; 21,704,592 and 14,450,199
shares outstanding repsecitvely $ 21,705 $ 14,450
Additional paid-in capital 39,995 46,841
Retained earnings 143,703 131,884
Total common stock equity 205,403 193,175
Cumulative preferred stock:
No par value; 400,000 shares authorized;
no shares outstanding - -
$100 par value; 270,000 shares authorized;
no shares outstanding - -
Long-term debt:
First mortgage bonds-
6.50% due 2002 15,000 15,000
9.00% due 2003 6,336 7,870
8.06% due 2010 30,000 30,000
9.49% due 2018 6,000 6,000
9.35% due 2021 35,000 5,000
8.30% due 2024 45,000 5,000
137,336 138,870
Other-
6.7% pollution control revenue bonds, due 2010 12,300 2,300
7.5% pollution control revenue bonds, due 2024 12,200 12,200
Other long-term obligations 2,855 2,855
27,355 27,355
Total long-term debt 164,691 166,225
Current maturities (1,331) (1,534)
Net long-term debt 163,360 164,691
Total capitalization $368,763 $357,866
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
(1) BUSINESS DESCRIPTION AND SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES
BUSINESS DESCRIPTION
Black Hills Corporation and its subsidiaries operate in four primary business
segments: electric, coal mining, oil and gas production, and energy marketing.
The Company's electric utility operation is engaged in the generation,
purchase, transmission, distribution and sale of electric power and energy in
western South Dakota, northeastern Wyoming and southeastern Montana. Sales of
electric power to the three largest electric customers represented 18 percent
of the Company's electric revenue in 1997, 17 percent in 1996 and 18 percent in
1995. The coal mining operation of the Company, located in northeastern
Wyoming, mines and sells sub-bituminous coal primarily under long-term coal
supply agreements. As discussed in Note 6, approximately 73 percent of the
coal mining operation's sales are to the Wyodak Plant. Sales of coal to the
Company and to PacifiCorp, herein referred to as Pacific Power, represent 98
percent of total coal sales in 1997. The Company's oil and gas exploration and
production business operates and has working interests in properties located in
the western and southern United States. The Company's energy marketing
businesses market natural gas, crude oil and electricity and provide related
energy services to customers in the West Coast, Rocky Mountain region,
Southwest, Midwest and East Coast markets.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Black Hills
Corporation and its wholly owned subsidiaries. All significant intercompany
balances and transactions have been eliminated in consolidation except for
revenues and expenses associated with intercompany coal sales in accordance
with the provisions of Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation." Total
intercompany coal sales not eliminated were $11,089,000, $10,384,000 and
$10,498,000 in 1997, 1996 and 1995, respectively.
Investments in and advances to Enserco, in which the Company has a 50 percent
ownership interest, are accounted for on the equity method of accounting.
The Company uses the proportionate consolidation method to account for its
working interests in oil and gas properties.
REGULATORY ACCOUNTING
Black Hills Power follows the provisions of SFAS No. 71, and its financial
statements reflect the effects of the different ratemaking principles followed
by the various jurisdictions regulating Black Hills Power. As a result of Black
Hills Power's 1995 rate case settlement, a 50-year depreciable life for NS #2
is used for financial reporting purposes. If Black Hills Power were not
following SFAS 71, a 35 to 40 year life would be more appropriate which would
increase depreciation expense by approximately $600,000 per year. If rate
recovery of generation-related costs becomes unlikely or uncertain, due to
competition or regulatory action, these accounting standards may no longer
apply to Black Hills Power's generation operations. In the event Black Hills
Power determines that it no longer meets the criteria for following SFAS 71,
the accounting impact to the Company would be an extraordinary noncash charge
to operations of an amount that could be material. Criteria that give rise to
the discontinuance of SFAS 71 include increasing competition that could
restrict Black Hills Power's ability to establish prices to recover specific
costs and a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. The
Company periodically reviews these criteria to ensure the continuing
application of SFAS 71 is appropriate.
PROPERTY
Property is recorded at cost which includes an allowance for funds used during
construction where applicable. The cost of electric property retired, together
with removal cost less salvage, is charged to accumulated depreciation.
Repairs and maintenance of property are charged to operations as incurred.
The Company periodically evaluates assets under SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and Long-Lived Assets to Be Disposed Of,"
which imposes a stricter criterion for assets by requiring that such assets be
probable of future recovery at each balance sheet date.
DEPRECIATION AND DEPLETION
Depreciation is computed using the straight-line method over the estimated
useful lives of the related assets. Depreciation provisions for the electric
property were equivalent to annual composite rates of 3.0 percent in 1997, 3.4
percent in 1996 and 3.0 percent in 1995. Composite depreciation rates for
other property were 8.1 percent, 7.7 percent and 8.9 percent in 1997, 1996 and
1995, respectively. Depletion of coal and oil and gas properties is computed
using the cost method for financial reporting.
AVAILABLE FOR SALE SECURITIES
The Company has investments in marketable securities which are classified as
available-for-sale securities and are carried at fair value. The difference
between the securities' fair value and cost basis and the realized gains and
losses on sales of the securities were not significant for the periods
presented.
REVENUE RECOGNITION
Revenue from sales of electric energy is based on rates filed with applicable
regulatory authorities. Electric revenue includes an accrual for estimated
unbilled revenue for services provided through year-end. Revenue from other
business segments is recognized at the time the products are delivered or the
services are rendered.
FUEL AND PURCHASED POWER ADJUSTMENT TARIFFS
The Company's Montana Retail Tariffs contain a clause that allow recovery of
certain fuel and purchased power costs in excess of the level of such costs
included in base rates. The cost adjustment tariff is revised periodically for
any difference between the total amount collected under the clause and the
recoverable costs incurred. The adjustments are recognized as current assets
or current liabilities until adjusted through future billings to customers.
The Company's South Dakota, Wyoming and wholesale tariffs do not include an
automatic fuel and purchased power adjustment tariff.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Ultimate results could differ from those estimates.
OIL AND GAS OPERATIONS
The Company accounts for its oil and gas drilling activities under the full
cost method. Under the full cost method, all productive and nonproductive
costs related to acquisition, exploration and development activities are
capitalized. These costs are amortized using a unit-of-production method based
on volumes produced and proved reserves. Under the full cost method, net
capitalized costs may not exceed the present value of proved reserves.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction (AFDC) represents the approximate
composite cost of borrowed funds and a return on capital used to finance
construction expenditures and is capitalized as a component of the electric
property. The AFDC was computed at an annual composite rate of 10.0 percent in
1997 and 1996 and 10.2 percent in 1995.
INCOME TAXES
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes," which requires the use of the liability method in accounting for income
taxes. Under the liability method, deferred income taxes are recognized, at
currently enacted income tax rates, to reflect the tax effect of temporary
differences between the financial and tax bases of assets and liabilities.
Such temporary differences are the result of provisions in the income tax law
that either require or permit certain items to be reported on the income tax
return in a different period than they are reported in the financial
statements. To the extent such income taxes are recoverable or payable through
future rates, regulatory assets and liabilities have been recorded in the
accompanying consolidated balance sheets.
Deferred taxes are provided on all significant temporary differences,
principally depreciation and depletion. Investment tax credits have been
deferred in the electric operation and the accumulated balance is amortized as
a reduction of income tax expense over the useful lives of the related electric
property which gave rise to the credits.
ENVIRONMENTAL REMEDIATION
In October 1996 the American Institute of Certified Public Accountants issued
Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities" which
provides authoritative guidance on specific accounting issues that are present
in the recognition, measurement, display and disclosure of environmental
remediation liabilities. The provisions of the SOP are effective for the
Company for fiscal year 1997 but did not have a material impact on the
Company's financial position or results of operations.
(2) CAPITAL STOCK
In January, 1998, the Board of Directors declared a 3-for-2 Common Stock Split
effected in the form of a stock dividend. The stock dividend is payable March
10, 1998 to shareholders of record on February 13, 1998. The common stock
share and per share information in the accompanying consolidated financial
statements and notes have been restated to reflect the stock distribution.
NET INCOME PER SHARE
The Company adopted the SFAS No. 128 "Earnings Per Share" in 1997. As a
result, all prior periods presented have been restated to conform to the
provisions of SFAS No. 128, which requires the presentation of basic and
diluted earnings per share. Basic earnings per share is computed by dividing
net income available to common shareholders by the weighted average number of
common shares outstanding during each year. Diluted earnings per share is
computed under the treasury stock method and is calculated to compute the
dilutive effect of outstanding stock options. A reconciliation of these
amounts is as follows (in thousands, except per share data):
1997 1996 1995
Net Income $32,359 $30,252 $25,590
Weighted average
common shares
outstanding-basic 21,692 21,660 21,614
Dilutive effect of
option plan 14 - -
Common and
potential common
shares outstanding-
diluted 21,706 21,660 21,614
Basic and diluted net
income per share $1.49 $1.40 $1.19
COMMON STOCK
The Company has a stock option plan ("the 1996 Stock Option Plan") which allows
for the granting of stock options with exercise prices equal to the stocks'
market value on the date of grant and an employee stock purchase plan ("the
ESPP Plan"). The Company accounts for under Accounting Principles Board
Opinion No. 25, under which no compensation cost has been recognized.
Had compensation cost been determined consistent with SFAS No. 123, the
Company's net income and earnings per share would have been reduced to the
following proforma amounts:
1997 1996
(in thousands)
Net income:
As reported $32,359 $30,252
Proforma $32,308 $30,215
1997 1996
Earnings per share:
As reported (basic and diluted) $1.49 $1.40
Proforma (basic and diluted) $1.49 $1.39
The Company may grant options for up to 300,000 shares of common stock under
the Stock Option Plans The Company has granted options on 182,700 shares and
83,700 shares through December 31, 1997 and 1996, respectively. The option
exercise price equals the fair market value of the stock on the day of the
grant. The options granted have an exercise price range of $16.67 to $22.50.
The options granted vest one-third a year for three years and all expire after
ten years from the grant date. At December 31, 1997, 27,900 options were
available for exercise at an exercise price of $16.67. There were no options
available for exercise at December 31, 1996.
The fair value of each option grant is estimated on the date of grant using the
Black Scholes option pricing model with the following weighted-average
assumptions used for the grants:
1997 1996
Risk free interest rate 6.09% 6.15%
Expected dividend yield 5.00% 5.50%
Expected life 10 years 10 years
Expected volatility 16.71% 17.66%
Weighted average fair value $1.09 $0.49
The Company issued 29,294 and 37,871 shares of common stock under the ESPP Plan
in 1997 and 1996, respectively. At December 31, 1997, 279,959 shares are
reserved and available for issuance under the ESPP Plan. The Company sells the
shares to employees at 90 percent of the stock's market price on the offering
date. The fair value per share of shares sold in 1997 was $15.50.
The Company has a Dividend Reinvestment and Stock Purchase Plan under which
shareholders may purchase additional shares of common stock through dividend
reinvestment and/or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing
the shares on the open market. The Company purchased shares on the open market
in 1997, 1996 and 1995. At December 31, 1997, 1,290,797 shares of unissued
common stock were available for future offerings under the Plan.
ADDITIONAL PAID-IN CAPITAL
Changes in additional paid-in capital for the years indicated were:
1997 1996 1995
(in thousands)
Balance, beginning
of year $46,841 $46,355 $45,740
Stock Dividend for 3-for-2
Common Stock split (7,235) - -
Premium, net of expenses
from sales of stock 389 486 615
Balance, end of year $39,995 $46,841 $46,355
(3) LONG-TERM DEBT
Substantially all of the Company's utility property is subject to the lien of
the Indenture securing its first mortgage bonds. First mortgage bonds of the
Company may be issued in amounts limited by property, earnings and other
provisions of the mortgage indentures. Scheduled maturities of long-term debt
for the next five years are: $1,331,000 in 1998, $1,330,000 in 1999,
$1,330,000 in 2000, $3,029,000 in 2001 and $18,018,000 in 2002.
In 1994 the Company filed a Form S-3, shelf registration for $100,000,000 first
mortgage bonds. Under the filing, the Company issued bonds in the amount of
$45,000,000 on September 1, 1994, $30,000,000 on February 3, 1995 and
$15,000,000 on July 14, 1995. The $30,000,000 bond issue is redeemable at the
option of the holders in integral multiples of $1,000 on February 1, 2002.
These bond issues were used to finance NS #2.
(4) NOTES PAYABLE TO BANKS
The Company had $12,000,000 of unsecured short-term lines of credit at December
31, 1997 and 1996. There were no outstanding borrowings under these lines of
credit at December 31, 1997. Borrowings outstanding under these lines of
credit were $120,000 as of December 31, 1996, at a weighted average interest
rate of 8.0 percent. The Company has no compensating balance requirements
associated with these lines of credit. The lines of credit are subject to
periodic review and renewal during the year by the banks.
In addition to the above lines of credit, Black Hills Energy Resources, Inc.
(formerly Wickford Energy Marketing, Inc.), has a $65,000,000, uncommitted,
discretionary credit facility consisting of a $50,000,000 transactional line of
credit and a $15,000,000 overdraft line of credit. The transactional line of
credit provides credit support for the purchases of natural gas and crude oil
of Black Hills Energy Resources. The Company and its subsidiaries provide no
guarantee to the Lender. At December 31, 1997, Black Hills Energy Resources
had letters of credit outstanding of $29,000,000 and no balance outstanding on
the overdraft line of credit.
In addition to the above lines of credit, Wyodak Resources has guaranteed a
$15,000,000 line of credit for Enserco to use to guarantee letters of credit.
Enserco pays a 0.125 percent facility fee on this line of credit. At December
31, 1997 and 1996, there were no balances outstanding on this line of credit.
(5) FAIR VALUE OF FINANCIAL
INSTRUMENTS
Cash of the Company is invested in money market investments such as municipal
put bonds, money market preferreds, commercial paper, Eurodollars and
certificates of deposit. The Company considers all highly liquid investments
with an original maturity of three months or less to be cash equivalents.
The following methods and assumptions were used to estimate the fair value of
each class of the Company's financial instruments.
CASH AND CASH EQUIVALENTS
The carrying amount approximates fair value due to the short maturity of these
instruments.
AVAILABLE FOR SALE SECURITIES
The fair value of the Company's investments equals the quoted market price when
available and a quoted market price for similar securities if a quoted market
price is not available. The Company has classified all of its marketable
securities as available-for-sale as of December 31, 1997 and 1996, and the fair
value approximates cost.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on quoted
market rates for utility debt instruments having similar maturities and similar
debt ratings. The Company's outstanding bonds are either currently not
callable or are subject to make-whole provisions which would eliminate any
economic benefits for the Company to call and refinance the bonds.
The estimated fair values of the Company's financial instruments are as
follows:
1997
(in thousands)
Carrying Fair
Amount Value
Cash and cash equivalents $16,774 $16,774
Securities available for sale:
Corporate debt securities 997 997
Federal, state and local
agency obligations 12,972 12,972
Long-term debt 164,691 189,649
1996
(in thousands)
Carrying Fair
Amount Value
Cash and cash equivalents $13,340 $13,340
Securities available for sale:
State and local agency
obligations 11,458 11,458
Long-term debt 166,225 184,508
(6) WYODAK PLANT
The Company owns a 20 percent interest and Pacific Power an 80 percent
interest in the Wyodak Plant (the Plant), a 330 megawatt coal-fired electric
generating station located in Campbell County, Wyoming. Pacific Power is the
operator of the Plant. The Company receives 20 percent of the Plant's capacity
and is committed to pay 20 percent of its additions, replacements and operating
and maintenance expenses. As of December 31, 1997, the Company's investment in
the Plant included $72,171,000 in electric plant and $25,961,000 in accumulated
depreciation. The Company's share of direct expenses of the Plant was
$5,934,000, $6,458,000 and $6,503,000 for the years ended December 31, 1997,
1996 and 1995, respectively, and is included in the corresponding categories of
operating expenses in the accompanying consolidated statements of income.
Wyodak Resources supplies coal to the Plant under an agreement expiring in 2013
with a Pacific Power option to renew for 10 years. This coal supply agreement
is collateralized by a mortgage on and a security interest in some of Wyodak
Resources' coal reserves. At December 31, 1997, approximately 24,132,000 tons
were covered under this agreement. Wyodak Resources' sales to the Plant were
$22,688,000, $22,643,000 and $20,224,000 for the years ended December 31, 1997,
1996 and 1995, respectively.
(7) COMMITMENTS AND CONTINGENT
LIABILITIES
MDU POWER SALE
On January 1, 1997, the Company began serving a ten year contract to supply up
to 55 megawatts of electric power and associated energy required by MDU for its
Sheridan, Wyoming, service territory. In 1997, MDU's Sheridan service area
experienced a 47 megawatt peak and had a load factor of approximately 57
percent.
COAL OBLIGATIONS
In addition to the 24,132,000 tons of coal reserved under the agreement to
supply coal to the Wyodak Plant, Wyodak Resources has reserved 26,130,000 tons
of coal under existing contracts.
COAL LEASES
Wyodak Resources' mining rights to its coal are based upon four federal leases
and one state lease. The federal leases provide for a royalty of 12.5 percent
of the selling price of the coal. The state lease provides for a royalty, to be
reviewed every five years, currently at 7 percent. Wyodak Resources paid
royalties in the amount of $3,969,000, $3,995,000 and $2,323,000 in 1997, 1996
and 1995, respectively. Each federal lease requires diligent development to
produce at least one percent of all recoverable reserves within either 10 years
from the respective dates of the leases or 10 years from the date of adjustment
of the leases. Each lease further requires a continuing obligation to mine,
thereafter, at an average annual rate of at least one percent of the
recoverable reserves. All of the federal leases constitute one logical mining
unit which is treated as one lease for the purpose of determining diligent
development and continuing operation requirements.
PACIFIC POWER'S POWER SALES AGREEMENT
In 1983 the Company entered into a 40 year power agreement with Pacific Power
providing for the purchase by the Company of 75 megawatts of electric capacity
and energy from Pacific Power's system. The price paid for the capacity and
energy is based on the operating costs of one of Pacific Power's coal-fired
electric generating plants. Costs incurred under this agreement were
$20,251,000, $19,777,000 and $20,689,000 in 1997, 1996 and 1995, respectively.
ACQUISITION OF CLOVIS POINT MINE PROPERTIES
In September 1996 Wyodak Resources entered into an agreement to purchase a
portion of the Clovis Point and East Gillette Mine properties from Kerr-McGee
Coal Corporation. The Clovis Point Mine properties are located adjacent to
Wyodak Resources' current reserves in Campbell County, Wyoming, and consist of
State of Wyoming and federal leased coal reserves.
Acquisition of the property in 1996 increased Wyodak Resources' reserves from
170 million tons to approximately 288 million tons and included a train loadout
facility, maintenance and processing facilities and a developed open pit.
The purchase price consisted of the assumption of the responsibility to reclaim
the existing Clovis Point open pit of which the Company recorded a liability of
$7,957,000 and the payment of overriding royalties to Kerr McGee if and when
coal is produced from the acquired properties. Wyodak Resources is not
obligated to mine the coal.
RECLAMATION
Under its mining permit, Wyodak Resources is required to reclaim all land where
it has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual basis,
much of the reclamation occurs over an extended period after the area is mined.
Approximately $700,000 is charged to operations as reclamation expense
annually. As of December 31, 1997, accrued reclamation costs were
approximately $16,700,000 which includes $7,957,000 for the Clovis Point Mine
Acquisition.
PRICE RISK MANAGEMENT ACTIVITIES
The Company utilizes a variety of financial instruments to hedge the impact of
price fluctuations on its oil and gas production and energy marketing
operations. The Company does not hold or issue derivative financial
instruments for trading purposes.
The Company utilizes deferral (hedge) accounting in conjunction with such
financial instruments; gains or losses from changes in the market value of the
financial instruments are deferred until the gain or loss on the hedged item is
recognized.
Financial instruments are classified as being used for a hedge only if the
instrument reduces the risk of the underlying hedged item and is designated at
the inception as a hedge with respect to the hedged item.
The primary financial instruments the Company uses in managing its price risk
exposure are exchange traded natural gas futures contracts and over-the-counter
natural gas and crude oil swaps, collar and option contracts. The Company
would be exposed to credit losses in the event of nonperformance by the
counterparties that have issued the financial instruments. The Company does
not expect that the counterparties will fail to meet their obligations, based
on the Company's review of the financial condition of the counterparties and/or
their credit ratings.
At December 31, 1997, the Company has fixed rate for floating rate price swaps
to hedge crude oil price risk for 15,000 barrels of oil per month at prices
ranging from $19.00 per barrel to $20.93 per barrel. In addition, the Company
has fixed rate for floating rate price swaps on 3.9 bcf of natural gas to hedge
fixed price sales commitments in a similar quantity.
OTHER
The Company is subject to various legal proceedings and claims which arise in
the ordinary course of operations. In the opinion of management, the amount of
liability, if any, with respect to these actions would not materially affect
the consolidated financial position or results of operations of the Company.
(8) EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the Plan) covering
substantially all employees. The benefits are based on years of service and
compensation levels during the highest five consecutive years of the last ten
years of service. The Company's funding policy is in accordance with the
federal government's funding requirements. The Plan's assets consist primarily
of equity securities and cash equivalents.
Net pension expense for the Plan was as follows:
1997 1996 1995
(in thousands)
Service cost $ 931 $ 874 $ 802
Interest cost 2,383 2,239 2,169
Return on assets:
Actual (10,278) (4,477) (5,204)
Deferred 7,022 1,502 2,603
Net pension expense $ 58 $ 138 $ 370
Actuarial assumptions:
Discount rate 7.5% 7.5% 7.5%
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 each year was as follows:
1997 1996
(in thousands)
Fair value of plan assets $40,435 $31,953
Projected benefit obligation (33,025) (32,722)
7,410 (769)
Unrecognized:
Net loss (gain) (7,579) 659
Prior service cost 618 707
Transition asset (271) (361)
Prepaid pension cost $ 178 $ 236
Accumulated benefit obligation $27,133 $26,376
Vested benefit obligation $25,995 $25,266
The Company has various supplemental retirement plans for outside directors and
key executives of the Company. The plans are nonqualified defined benefit
plans. Expenses recognized under the plans were $94,000, $498,000 and $350,000
in 1997, 1996 and 1995, respectively.
The Company follows the provisions of SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." The standard requires that the
expected cost of these benefits must be charged to expense during the years
that the employees render service. Prior to adopting the standard in 1993, the
Company expensed these benefits as they were paid. The Company is amortizing
the transition obligation of $2,996,000 over a 20 year period.
Employees retiring from the Company on or after attaining age 55 who have
rendered at least five years of service to the Company are entitled to
postretirement healthcare benefits coverage. These benefits are subject to
premiums, deductibles, copayment provisions and other limitations. The Company
may amend or change the plan periodically. The Company is not pre-funding its
retiree medical plan.
The net periodic postretirement cost for the Company was as follows:
1997 1996 1995
(in thousands)
Service cost $168 $166 $211
Interest cost 329 304 429
Amortization of transition 150 150 150
obligation
Amortization of (gain) loss (5) (1) 79
$642 $619 $869
Funding information as of October 1 was as follows:
1997 1996
(in thousands)
Accumulated postretirement benefit
obligation:
Retirees $1,588 $1,743
Fully eligible active participants 671 756
Other active participants 1,668 1,941
Unfunded accumulated postretirement
benefit obligation 3,927 4,440
Unrecognized net gain 1,067 173
Unrecognized transition obligation (2,247) (2,397)
$2,747 $2,216
For measurement purposes, a 9.5 percent annual rate of increase in healthcare
benefits was assumed for 1998; the rate was assumed to decrease gradually to 6
percent in 2005 and remain at that level thereafter. The healthcare cost trend
rate assumption has a significant effect on the amounts reported. A one
percent increase in the healthcare cost trend assumption would increase the net
periodic postretirement cost by approximately $130,000 annually or 24.3
percent. The weighted-average discount rate used in determining the
accumulated postretirement benefit obligation was 7.5 percent.
(9) INCOME TAXES
Income tax expense for the years indicated was:
1997 1996 1995
(in thousands)
Current $11,869 $11,706 $ 8,640
Deferred 3,107 2,533 2,600
Tax credits, net (650) (661) (503)
$14,326 $13,578 $10,737
The temporary differences which gave rise to the net deferred tax liability at
December 31, 1997 and 1996 were as follows:
Net Deferred
Income
Tax Asset
December 31, 1997 Assets Liabilities Liability
(in thousands)
Accelerated depreciation and
other plant-related differences $ - $45,508 $(45,508)
Regulatory asset 2,136 - 2,136
Regulatory liability - 1,415 (1,415)
Unamortized investment tax credits 1,405 - 1,405
Mining development and oil exploration 1,417 5,342 (3,925)
Employee benefits 2,426 103 2,323
Other 677 642 35
$ 8,061 $53,010 $(44,949)
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)
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
1997 1996 1995
Federal statutory rate 35.0% 35.0% 35.0%
Regulatory asset recognition (1.3) (1.7) (1.9)
Amortization of investment tax credits (1.1) (1.5) (1.4)
Tax-exempt interest income (0.9) (0.6) (0.8)
Percentage depletion in excess of cost (0.7) (0.5) (0.4)
Other (0.3) 0.2 (0.9)
30.7% 30.9% 29.6%
(10) OIL AND GAS RESERVES (Unaudited)
Western Production has interests in 484 producing oil and gas properties in
eight states. Western Production also holds leases on approximately 42,200 net
undeveloped acres.
The following table summarizes Western Production's quantities of proved
developed and undeveloped oil and natural gas reserves, estimated using
constant year-end product prices, as of December 31, 1997, 1996 and 1995, and a
reconciliation of the changes between these dates. These estimates are based
on reserve reports by Ralph E. Davis Associates, Inc. (an independent
engineering company selected by the Company). Such reserve estimates are based
upon a number of variable factors and assumptions which may cause these
estimates to differ from actual results.
1997 1996 1995
Oil Gas Oil Gas Oil Gas
(in thousands of barrels of oil and MCF of gas)
Proved developed and
undeveloped reserves:
Balance at begin. of year 2,386 10,972 1,612 7,658 1,438 9,080
Production (299) (1,747) (286) (1,718) (266) (1,986)
Additions 1,146 3,498 404 5,098 168 4,106
Property sales (10) (393) (9) (312) (103) (843)
Revisions to previous
estimates (728) (3,278) 665 246 375 (2,699)
Balance at end of year 2,495 9,052 2,386 10,972 1,612 7,658
Proved developed reserves
at end of year included
above 2,035 6,821 2,376 9,633 1,606 6,370
Year-end prices $16.34 $2.32 $24.04 $3.20 $18.50 $ 1.90
(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
The four primary segments of the Company's business are its electric
operations, coal mining operations, oil and gas operations and energy
marketing operations. The following table summarizes certain information
specifically identifiable with each segment as of, or for, the years ended
December 31.
1997 1996 1995
(in thousands)
Assets at year-end:
Electric $385,325 $382,753 $380,256
Coal mining 48,295 55,470 45,224
Oil and gas 31,449 29,131 23,350
Energy marketing 43,672 - -
$508,741 $467,354 $448,830
Depreciation, depletion and amortization:
Electric $ 14,608 $ 16,104 $ 11,943
Coal mining 3,188 2,981 3,575
Oil and gas 4,275 3,709 4,142
Energy marketing 240 - -
$ 22,311 $ 22,794 $ 19,660
Capital expenditures:
NS #2 (includes AFDC) $ - $ - $ 33,219
Other electric 12,583 12,822 11,242
Coal mining 1,527 2,169 1,546
Oil and gas 7,076 9,585 5,888
Energy marketing 7,232 - -
$ 28,418 $ 24,576 $ 51,895
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
Taxes Other than Income Taxes
1997 1996 1995
(in thousands)
Property $ 4,326 $ 4,368 $ 3,696
Production and severance 3,654 4,105 3,385
Payroll 1,332 1,307 1,402
Black lung 1,310 1,320 1,263
Federal reclamation 1,138 1,135 1,027
Other 225 225 208
$11,985 $12,460 $10,981
(13) ACQUISITIONS
In July 1997, Black Hills Capital Group acquired the assets and hired the
operational management of Jomax Partners, L.P. as successor and survivor
of Wickford Energy Marketing, L.C. and Wickford Energy Marketing Canada
Company. In March 1998, Wickford was renamed Black Hills Energy
Resources, Inc. Black Hills Energy Resources is headquartered in
Houston, Texas with a natural gas sales office Calgary, Alberta, Canada
and crude oil sales offices in Tulsa, Oklahoma and Midland, Texas. Black
Hills Energy Resources is a "niche" wholesale natural gas and crude oil
marketing company with expertise in Gulf Coast and Canadian Supply,
targeting natural gas markets in the East Coast and Midwest and crude oil
markets primarily in the Southwest.
The Company accounted for this acquisition using the purchase method.
Results of operations since the acquisition date are included in the
consolidated results.
The Company recorded goodwill and intangible assets resulting from the
acquisition. The Company is amortizing the goodwill and intangible
assets over the expected benefit periods of 15 years and 5 years,
respectively, using the straight-line method.
The following, unaudited proforma financial information assumes the
acquisition occurred at January 1, 1996, in thousands, except per share
amounts:
1997 1996
(unaudited)
Revenues $506,188 $391,618
Net income $ 33,010 $ 32,771
Earnings per share - basic and diluted $ 1.52 $ 1.51
FINANCIAL STATISTICS
Years ended December 31, 1997 1996 1995 1994 1993
TOTAL ASSETS (in thousands) $508,741 $467,354 $448,830 $436,877 $352,853
PROPERTY AND INVESTMENTS
(in thousands)
Total property and
investments $598,306 $581,537 $557,642 $519,296 $433,143
Accumulated depreciation
and depletion 197,179 181,103 164,383 156,046 144,492
Capital expenditures
(includes AFDC) 28,418 24,576 51,895 103,059 40,290
CAPITALIZATION (in thousands)
Long-term debt $163,360 $164,691 $166,069 $128,925 $ 85,274
Common stock equity 205,403 193,175 182,342 175,410 168,089
Total capitalization $368,763 $357,866 $348,411 $304,335 $253,363
CAPITALIZATION RATIOS
Long-term debt 44.3% 46.0% 47.7% 42.4% 33.7%
Common stock equity 55.7 54.0 52.3 57.6 66.3
Total 100.0% 100.0% 100.0% 100.0% 100.0%
AVERAGE INTEREST RATE ON
LONG-TERM DEBT 8.1% 8.1% 8.1% 8.5% 9.0%
NET INCOME AVAILABLE FOR
COMMON STOCK
(in thousands) $32,359 $30,252 $25,590 $23,805 $22,946
DIVIDENDS PAID ON COMMON
STOCK (in thousands) $20,540 $19,930 $19,312 $18,920 $17,720
COMMON STOCK DATA
(in thousands)*
Shares outstanding,
average 21,692 21,660 21,614 21,509 20,717
Shares outstanding,
end of year 21,705 21,675 21,638 21,579 21,405
Earnings per average
share, in dollars $1.49 $1.40 $1.19 $1.11 $1.11
Dividends paid per
share, in dollars 0.95 $0.92 $0.89 $0.88 $0.85
Book value per share,
end of year, in
dollars $9.46 $8.91 $8.43 $8.13 $7.85
RETURN ON COMMON STOCK
EQUITY (year-end) 15.8% 15.7% 14.0% 13.6% 13.7%
ALLOWANCE FOR FUNDS USED
DURING CONSTRUCTION AS
PERCENT OF NET INCOME 0.6% 1.2% 22.9% 16.7% 3.2%
*Common Stock Data has been restated to reflect the 3-for-2 stock split on
March 10, 1998.
ELECTRIC OPERATION STATISTICS
Years ended December 31, 1997 1996 1995 1994 1993
ELECTRIC ENERGY GENERATED
AND PURCHASED
(megawatt hours)
Generated, net station
output 1,803,350 1,659,671 1,320,630 1,108,530 1,227,084
Purchased and net
interchange 503,242 380,106 473,175 595,872 435,990
Total generated and
purchased 2,306,592 2,039,777 1,793,805 1,704,402 1,663,074
Company use and losses (94,633) (80,106) (87,512) (65,651) (61,336)
Total electric energy
sales 2,211,959 1,959,671 1,706,293 1,638,751 1,601,738
ELECTRIC ENERGY SALES
(megawatt hours)
Residential 392,059 406,658 383,929 368,953 370,736
General and commercial 547,624 541,463 513,854 495,909 469,496
Industrial 556,554 555,601 552,829 583,258 568,316
Public authorities 22,583 25,083 23,164 23,051 22,621
Sales for resale 413,527 181,766 171,942 166,580 162,789
Total firm electric
energy sales 1,932,347 1,710,571 1,645,718 1,637,751 1,593,958
Non-firm sales 279,612 249,100 60,575 1,000 7,780
Total electric energy
sales 2,211,959 1,959,671 1,706,293 1,638,751 1,601,738
ELECTRIC REVENUE
(in thousands)
Residential $ 32,178 $ 33,230 $ 30,433 $ 28,574 $ 27,064
General and commercial 41,452 41,307 37,663 35,390 32,295
Industrial 26,802 26,915 26,495 27,318 25,901
Public authorities 1,843 1,970 1,775 1,718 1,537
Sales for resale 16,181 8,189 7,625 7,460 7,122
Total firm electric
revenue 118,456 111,611 103,991 100,460 93,919
Non-firm electric revenue 3,760 2,985 741 - 202
Other electric revenue 4,281 4,122 4,051 4,296 4,034
Total electric revenue $126,497 $118,718 $108,783 $104,756 $ 98,155
ELECTRIC CUSTOMERS
(end of year)
Residential 46,656 46,146 45,886 45,060 44,657
General and commercial 9,431 9,280 8,958 8,732 8,507
Industrial 39 37 35 36 41
Public authorities 141 137 138 130 124
Other electric utilities 2 1 1 1 1
Total electric customers 56,269 55,601 55,018 53,959 53,330
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 19, 1998.
EXECUTIVE OFFICERS OF THE COMPANY
The following is a list of all executive officers of the Company. There are no
family relationships among them. Officers are normally elected annually.
Daniel P. Landguth, 51, Chairman, President and Chief Executive Officer of
Black Hills Corporation
Mr. Landguth was elected to his present position in January 1991.
Roxann R. Basham, 36, Vice President - Finance and Secretary/Treasurer
Ms. Basham was elected to her present position on December 9, 1997. She had
served as Secretary/Treasurer since 1993. She had served as Assistant
Secretary/Treasurer since May 1991.
David R. Emery, 35, Vice President - Fuel Resources
Mr. Emery was elected to his present position in January 1997. He had served
as General Manager of Western Production Company since June 1993 and
Petroleum Engineer since 1989.
Gary R. Fish, 39, Vice President - Corporate Development
Mr. Fish was elected to his present position in October 1996. He had served
as Controller since 1988.
Everett E. Hoyt, 58, President and Chief Operating Officer of Black Hills Power
Mr. Hoyt was elected to his present position in October 1989.
James M. Mattern, 43, Vice President - Corporate Administration and Assistant
to the CEO
Mr. Mattern was elected to his present position in September 1997. He had
served as Vice President - Corporate Administration since January 1994 and
had served as Director of Human Resources since 1991.
Thomas M. Ohlmacher, 46, Vice President - Power Supply
Mr. Ohlmacher was elected to his present position on August 1, 1994. He had
served as Director of Power Generation since 1993 and Director of Electric
Operations since 1991.
Mark T. Thies, 34, Controller
Mr. Thies was elected to his present position on May 1, 1997. Previously,
Mr. Thies had served in a number of accounting positions, most recently as
Assistant Controller, at InterCoast Energy Company, a wholly owned
subsidiary of MidAmerican Energy Holdings Company since 1990.
Kyle D. White, 38, Vice President - Energy Services
Mr. White was elected to his present position on January 29, 1998. He had
served as Director of Strategic Marketing and Sales since 1993. He had
served as Manager, Rates and Regulatory Affairs since 1991.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding management remuneration and transactions is incorporated
herein by reference to the Proxy Statement for the Annual Shareholders' Meeting
to be held May 19, 1998.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the security ownership of certain beneficial owners and
management is incorporated herein by reference to the Proxy statement for the
Annual Shareholders' Meeting to be held May 19, 1998.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions is
incorporated herein by reference to the Proxy Statement for the Annual
Shareholders' Meeting to be held May 19, 1998.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
Financial statements required by Item 14 are listed in the index
included in Item 8 of Part II.
2. Schedules
All schedules have been omitted because of the absence of the
conditions under which they are required or because the required
information is included elsewhere in the financial statements
incorporated by reference in the Form 10-K.
3. Exhibits
*3(a) Restated Articles of Incorporation dated May 24, 1984 (Exhibit
3(I) to Form 8-K dated June 7, 1994, File No. 1-7978).
*3(b) Bylaws dated January 30, 1997. (Exhibit 3(b) to Form 10-K for
1997.)
*4(a) Reference is made to Article Fourth (7) of the Restated
Articles of Incorporation of the Company (Exhibit 3(a)
hereto).
*4(b) Indemnification Agreement and Company and Directors' and
Officers' indemnification insurance (Exhibit 4(b) to Form 10-K
for 1987).
*4(c) Indenture of Mortgage and Deed of
Trust, dated September 1, 1941, and as amended by supplemental
indentures (Exhibit B to Form A-2, File No. 2-4832); (Exhibit
7-B to Form S-1, File No. 2-6576); (Exhibit 7-C to Form S-1,
File No. 2-7695); (Exhibit 7-D to Form S-1, File No. 2-8157);
(Exhibit 4.05(e) to Form S-3, File No. 33-54329); (Exhibit 4-I
to Form S-1, File No. 2-9433); (Exhibit 4-H to Form S-1, File
No. 2-13140); (Exhibit 4-I to Form S-1, File No. 2-14829);
(Exhibits 4-J and 4-K to Form S-1, File No. 2-16756);
(Exhibits 4-L, 4-M, and 4-N to Form S-1, File No. 2-21024);
(Exhibits 2(q), 2(r), 2(s), 2(t), 2(u), and 2(v) to Form S-7,
File No. 2-57661); (Exhibit 4.05(t), 4.05(u) and 4.05(v) to
Form S-3, File No. 33-54329); (Exhibit 4(b) to Form S-3, File
No. 2-81643); (Exhibit 4.05(x), 4.05(y), and 4.05(z) to Form
S-3, File No. 33-54329); (Exhibit 4(d) and 4(e) to Post-
Effective Amendment No. 1 to Form S-8, File No. 33-15868); and
(Exhibit 4.05(ac), 4.05(ad), and 4.05(ae) to Form S-3, File
No. 33-54329).
*4(d) Indentures of Trust dated as of
June 1, 1992, City of Gillette, Campbell County, Wyoming;
Lawrence County, South Dakota; Pennington County, South
Dakota; Weston County Wyoming; and Campbell County, Wyoming;
to Norwest Bank Minnesota, National Association, as Trustee
(Exhibits 10(n), 10(q), 10(s), 10(u), and 10(w), to Form 10-K
for 1992).
*10(a) Agreement for Transmission Service
and The Common Use of Transmission Systems dated January 1,
1986, among the Company, Basin Electric Power Cooperative,
Rushmore Electric Power Cooperative, Inc., Tri-County Electric
Association, Inc., Black Hills Electric Cooperative, Inc. and
Butte Electric Cooperative, Inc. (Exhibit 10(d) to Form 10-K
for 1987).
*10(b) Restated and Amended Coal Supply
Agreement for NS #2 dated February 12, 1993 (Exhibit 10(c) to
Form 10-K for 1992).
*10(c) Coal Leases between Wyodak
Resources Development Corp. and the Federal Government
-Dated May 1, 1959, (Exhibit 5(i) to Form S-7, File
No.2-60755)
-Modified January 22, 1990 (Exhibit 10(h) to Form 10-K for
1989)
-Dated April 1, 1961 (Exhibit 5(j) to Form S-7, File
No.2-60755)
-Modified January 22, 1990 (Exhibit 10(i) to Form 10-K for
1989)
-Dated October 1, 1965 (Exhibit 5(k) to Form S-7, File
No.2-60755)
-Modified January 22, 1990 (Exhibit 10(j) to Form 10-K for
1989)
*10(d) Further Restated and Amended Coal
Supply Agreement dated May 5, 1987 between Wyodak Resources
Development Corp. and Pacific Power & Light Company (Exhibit
10(k) to Form 10-K for 1987).
10(e) Second Restated and Amended Power
Sales Agreement dated September 29, 1997, between PacifiCorp
and the Company.
*10(f) Coal Supply Agreement for Wyodak
Unit #2 dated February 3, 1983, and Ancillary Agreement dated
February 3, 1982, between Wyodak Resources Development Corp.
and Pacific Power & Light Company and the Company (Exhibit
10(o) to Form 10-K for 1983). Amendment to Agreement for
Coal Supply for Wyodak #2 dated May 5, 1987 (Exhibit 10(o) to
Form 10-K for 1987).
10(g) Third Restated Electric Power and
Energy Supply and Transmission Agreement dated January 1,
1998, by and between the Company and the City of Gillette,
Wyoming.
*10(h) Reserve Capacity Integration
Agreement dated May 5, 1987, between Pacific Power & Light
Company and the Company (Exhibit 10(u) to Form 10-K for 1987).
*10(i) Compensation Plan for Outside
Directors (Exhibit 10(bb) to Form 10-K for 1992).
*10(j) The Amended and Restated Pension
Equalization Plan of Black Hills Corporation dated January 27,
1995 (Exhibit 10 (ad) to Form 10-K for 1994).
*10(k) The Amended and Restated Pension
Plan of Black Hills Corporation (Exhibit 10 (ad) to Form 10-K
for 1994).
*10(l) Agreement for Supplemental Pension
Benefit for Everett E. Hoyt dated January 20, 1992 (Exhibit
10(gg) to Form 10-K for 1992).
*10(m) Power Integration Agreement, dated
September 9, 1994, between the Company and Montana-Dakota
Utilities Co., a Division of MDU Resources Group, Inc.
(Exhibit 10(gg) to Form 8-K dated September 12, 1994, File No.
1-7978).
*10(n) Change in Control Agreements dated
January 30, 1996 for Daniel P. Landguth, Everett E. Hoyt,
Thomas M. Ohlmacher, James M. Mattern, Roxann R. Basham and
Gary R. Fish (Exhibit 10(af) to Form 10-K for 1995).
*10(o) Marketing, Capacity and Storage
Service Agreement between Black Hills Corporation and
PacifiCorp dated September 1, 1995 (Exhibit 10(ag) to Form 10-
K for 1995).
10(p) Change in Control Agreement dated
February 1, 1997 for David R. Emery.
10(q) Change in Control Agreement dated
May 1, 1997 for Mark T. Thies.
10(r) Change in Control Agreement dated
December 31, 1997 for Kyle D. White.
10(s) Black Hills Corporation 1996 Stock Option Plan.
10(t) The Outside Directors Stock Based Compensation Plan.
10(u) Assignment of Mining Leases and
Related Agreement effective May 27, 1997, between Wyodak
Resources Development Corp. and Kerr-McGee Coal Corporation.
Included in this Agreement are coal leases between Wyodak
Resources Development Corp. and the Federal Government and the
State of Wyoming, as modified by the decision dated May 27,
1997 from the U.S. Department of the Interior - Bureau of Land
Management.
21 Subsidiaries of the Registrant.
23a Consent of Independent Public Accountants with respect to Annual
Report on Form 10-K.
23b Consent of Independent Public Accountants with respect to Annual
Report on Form 11-K.
27 Financial Data Schedule.
99 Annual Report on Form 11-K of the Black Hills Corporation Employee
Stock Purchase Plan for the year ended December 31, 1997.
* Exhibits incorporated by reference.
(b) The Company filed a report on Form 8-K on October 10, 1997 relating to the
renegotiated Power Sales Agreement with Pacific Power.
(c) See (a) 3. above.
(d) See (a) 2. above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
BLACK HILLS CORPORATION
By /s/ DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman,
President and Chief Executive
Officer
Dated: March 9, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
/s/ DANIEL P. LANDGUTH Director and Principal March 9, 1998
Daniel P. Landguth, Chairman, Executive Officer
President, and Chief Executive Officer
/s/ ROXANN R. BASHAM Principal Financial Officer March 9, 1998
Roxann R. Basham, Vice President-Finance,
and Corporate Secretary/Treasurer
/s/ MARK T. THIES Principal Accounting Officer March 9, 1998
Mark T. Thies, Controller
/s/ ADIL M. AMEER Director March 9, 1998
Adil M. Ameer
/s/ GLENN C. BARBE Director March 9, 1998
Glenn C. Barber
/s/ BRUCE B. BRUNDAGE Director March 9, 1998
Bruce B. Brundage
/s/ JOHN R. HOWARD Director March 9, 1998
John R. Howard
/s/ EVERETT E. HOYT Director and Officer March 9, 1998
Everett E. Hoyt (President and Chief
Operating Officer of Black Hills Power)
/s/ KAY S. JORGENSEN Director March 9, 1998
Kay S. Jorgensen
/s/ THOMAS J. ZELL Director March 9, 1998
Thomas J. Zeller
BOARD OF DIRECTORS AND OFFICERS
BOARD OF DIRECTORS OFFICERS
Daniel P. Landguth Daniel P. Landguth
Chairman of the Board, President and Chairman of the Board,President
Chief Executive Officer of the Company and Chief Executive Officer
Adil M. Ameer Roxann R. Basham
President and Chief Executive Officer Vice President - Finance and
Rapid City Regional Hospital Corporate Secretary/Treasurer
Glenn C. Barber David R. Emery
President and Chief Executive Officer Vice President - Fuel Resources
Glenn C. Barber & Associates, Inc.
Bruce B. Brundage Gary R. Fish
President and Director Vice President - Corporate
Brundage & Company Development
John R. Howard Everett E. Hoyt
President President and Chief Operating
Industrial Products, Inc. Officer of Black Hills Power
and Light Company
Everett E. Hoyt James M. Mattern
President and Chief Operating Officer Vice President-Corporate
Black Hills Power and Light Company Administration and Assistant
to the CEO
Kay S. Jorgensen Thomas M. Ohlmacher
Owner - Jorgensen-Thompson Vice President-Power Supply
Creative Broadcast Services; and
South Dakota Legislative Representative
Lawrence County, South Dakota
Thomas J. Zeller Mark T. Thies
President Controller
RE/SPEC Inc.
Kyle D. White
Vice President-Energy Services
Black Hills Power and Light
Company