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