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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, 1994
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ___________ to ___________
Commission file Number 1-7978
BLACK HILLS CORPORATION
Incorporated in South Dakota
IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57709
Registrant's telephone number, including area code
(605) 348-1700
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common stock of $1.00 par value New York Stock Exchange
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
State the aggregate market value of the voting stock held by non-affiliates of
the Registrant.
At February 28, 1995 $337,044,567
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 14,399,194 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, 1994, 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 1995 Annual Meeting of Stockholders to be held on May 23, 1995,
is incorporated by reference in Part III.
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
MDU. . . . . . . . . . . . . . . Montana-Dakota Utilities Co., a division of
MDU Resources Group, Inc.
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 and Utah Power
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
TABLE OF CONTENTS
Page
ITEM 1. BUSINESS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
GENERAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ELECTRIC POWER SALES AND SERVICE TERRITORY. . . . . . . . . . . . . 2
ELECTRIC POWER SUPPLY . . . . . . . . . . . . . . . . . . . . . . . 6
RATE REGULATION . . . . . . . . . . . . . . . . . . . . . . . . . . 10
COMPETITION IN ELECTRIC UTILITY BUSINESS. . . . . . . . . . . . . . 14
CONSTRUCTION AND CAPITAL PROGRAMS . . . . . . . . . . . . . . . 18
COAL SALES . . . . . . . . . . . . . . . . . . . . . . . . . . 19
OIL AND GAS OPERATIONS . . . . . . . . . . . . . . . . . . . . 22
EXEMPT WHOLESALE GENERATOR BUSINESS . . . . . . . . . . . . . . 22
ENVIRONMENTAL REGULATION . . . . . . . . . . . . . . . . . . . 23
Air Quality . . . . . . . . . . . . . . . . . . . . . . . . 23
Water Quality . . . . . . . . . . . . . . . . . . . . . . . 26
Land Quality . . . . . . . . . . . . . . . . . . . . . . . 26
General . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Electromagnetic Fields. . . . . . . . . . . . . . . . . . . 29
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . 29
EMPLOYEES . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
ITEM 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
UTILITY PROPERTIES . . . . . . . . . . . . . . . . . . . . . . 30
MINING PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . 31
OIL AND GAS PROPERTIES . . . . . . . . . . . . . . . . . . . . 32
ITEM 3. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . 33
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
EXECUTIVE OFFICERS OF THE COMPANY. . . . . . . . . . . . . . . 34
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . . 34
ITEM 6. SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . 35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . 35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . . . . . . . . 35
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE. . . . . . . . . . . . . . 35
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT . . . . . . . . 35
ITEM 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . 35
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . . . . . 35
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . 36
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
APPENDICES
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 53,959
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
healthcare 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, California, 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 1992-1994 is as follows:
1
1994 1993 1992
(in thousands)
Revenue from sales to
unaffiliated customers:
Electric $104,431 $97,885 $97,232
Coal mining 19,149 19,775 18,485
Oil and gas 12,052 11,396 9,599
Revenue from intercompany
sales:
Electric $ 325 $ 270 $ 216
Coal mining 9,445 10,047 9,811
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
experienced milder than normal winter weather, Black Hills Power's firm
kilowatthour sales increased in 1994 by 2.7 percent over 1993. 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 percent.
During the next ten years the peak system demand for retail sales and to the
City of Gillette, Wyoming, currently at 284 MW for winter peak and 279 MW for
summer peak, is forecasted to increase at an annual compound growth rate of
2.1 percent for summer and 2.4 percent for winter. 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 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.
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 under this Item 1.
At the end of 1994, Black Hills served electric energy to 53,959
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.
Black Hills Power's electric service territory is experiencing modest
business and population growth. South Dakota's unemployment rate in 1994
averaged 2.7 percent. South Dakota experienced a retail sales growth of 8.4
percent in 1994. Over 1,400 new jobs were created in Rapid City during
1994, a 3.5 percent increase. The tourism industry in South Dakota
experienced visitor spending increases of 11 percent in 1994 compared to 1993.
The Company believes that this growth in its electric service territory
will continue; however, the Company can give no assurances.
2
The gold mining industry, including Homestake Mining Company
(representing 11.4 percent of Black Hills' total firm kilowatthour sales in
1994 and 8.0 percent of firm electric sales revenue) depends largely upon the
price of gold and the ability to find economically minable ore reserves. The
Homestake Mine produced almost 400,000 ounces of gold in 1994 and has returned
to profitability after several lean years but still faces questions about its
ability to continue making profits while pursuing ore reserves even deeper in
the earth.
Also experiencing political difficulties is the timber industry, where
administrative appeals are slowing timber sales in the Black Hills National
Forest. About $70 million is generated in the Black Hills annually by the
timber industry, and 1,700 jobs depend on its continuation. A new U. S.
Forest Service Management Plan detailing the multiple uses of the forest is
now under consideration.
A brighter spot is low stakes casino gambling initiated in Deadwood,
South Dakota, in 1989. Since 1989, more than 1,500 jobs have been created in
the 78 gaming establishments where $1.87 billion has been wagered in the past
five years, generating $14.7 million in gaming taxes.
Less dependent on weather and market conditions is the healthcare
industry. Rapid City Regional Hospital, a not-for-profit corporation with 341
beds, serves the area within a 250-mile radius of South Dakota, Wyoming, and
Nebraska. Presently, the hospital has a medical staff of over 200 physicians
representing 42 medical specialties. The hospital's cancer care institute
opened in 1993 and in 1994 proceeded with construction to expand the
emergency, surgery, endoscopy, radiology, nuclear medicine, and ultrasound
facilities. The hospital employs over 2,000 people, making it the largest
employer in the area besides EAFB.
The political climate in South Dakota and Wyoming is pro-business and
industry. Neither state has a corporate or personal income tax.
ELLSWORTH AIR FORCE BASE FUTURE. 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 some of the Air Force's
B-1 bombers. There are now stationed at EAFB 30 of the Defense Department's
total of 95 B-1s.
Black Hills Power does not provide electric service to EAFB. However,
currently EAFB employs approximately 4,616 military and 526 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.
Under the procedures of the Base Closure and Realignment Act of 1990, the
fourth round of military base closures and realignments is in process as of
the date of the publication of this report. The Department of the Air Force,
along with the other services, current evaluations of what military bases
should be closed or their mission realigned began in December of 1993 and
continues into 1994. The military services submitted their recommended closure
list to the Secretary of Defense (Secretary) for consideration in January of
1995. On February 28, 1995 the Secretary submitted a list of the Secretary's
recommendations for military bases to be closed or realigned to the Base
Closure and Realignment Commission (Closure Commission), a commission
3
appointed by the President and confirmed by the United States Senate. EAFB
was not on the Secretary's list for either closure or realignment.
The Closure Commission will review the Secretary's list to insure
fairness in the process, compare bases with the same mission, delete bases
from the list, and add bases to the list until May 17, 1995.
The Closure Commissioners and staff will visit each base considered for
closure and hold regional hearings for communities with a base considered for
closure. The Closure Commission's closure list will go to the President by
July 1, 1995. If the President rejects the list, the Closure Commission will
reconsider the list. If rejected again, the process is over, and nothing
closes. If the list is approved, the President sends the list to Congress.
No Congressional action is required, but Congress may by joint resolution
disapprove the closure list.
The primary criteria that the Department of Defense and Closure
Commission apply to their decisions are military value--that is, the current
and future mission requirements and the impact on Department of Defense
operational readiness; land, facilities, encroachment and airspace
availability; the ability to accommodate contingency, mobilization, and future
force requirements; and cost and manpower implications of closing.
The secondary criteria to be applied consider return on investment--the
extent and timing of potential costs and savings; and impacts, including the
economic impact on the community, the ability of the community to handle the
existing mission, and the environmental impact of base closure.
The Secretary also announced that he will recommend that authority be
extended to permit another base closure round in three or four years.
In 1994 the Air Force conducted a six-month test of the B-1s. The
mandated criteria included operational readiness of 75 percent. The Air Force
reported the results of the test to be an 84.3 percent readiness of the B-1s.
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. President Clinton's 1996
defense budget includes the B-1 program. While management believes that
EAFB will meet the criteria for continuing as a military base and will survive
this round of base closings, management can give no assurances. The political
uncertainties of governmental spending, provincial competition, a shrinking
commitment to military preparedness, and partisan interplay make any
prediction suspect.
ELECTRIC SALES--WHOLESALE TO CITY OF GILLETTE. Black Hills Power sells
electric power and energy to the municipal electric system at Gillette,
Wyoming. Service is rendered under a long-term contract expiring July 1, 2012
wherein Black Hills Power currently 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 percent. Revenue
from sales to Gillette represented 8 percent of revenue from total sales in
1994.
4
Under the current contract, 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 it from 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.
Subject to the approval of Gillette's City Council, Black Hills Power and
the City of Gillette have reached an agreement to substantially amend their
contract. The new agreement will be subject to approval or acceptance for
filing by the FERC.
Under the new agreement, Black Hills Power will continue to have the
obligation to serve the first 23 megawatts of Gillette's load and the
associated energy; however, Gillette will undertake the obligation to provide
resources for all of its loads above 23 megawatts and associated energy. The
new contract will maintain the same level of service furnished by Black Hills
to Gillette at this time. The term of the new contract remains the same.
The new contract will also provide for a rate increase to be paid by
Gillette commencing with the commercial operation of Neil Simpson Unit #2.
See--RATE REGULATION--WHOLESALE--CITY OF GILLETTE under this Item 1.
ELECTRIC SALES--WHOLESALE TO MDU. Black Hills Power and MDU entered into
a Power Integration Agreement, dated as of September 9, 1994, providing for
the sale for a period of 10 years commencing January 1, 1997, by Black Hills
Power to MDU of up to 55 megawatts of power and associated energy to serve
MDU's Sheridan, Wyoming electric service territory. The MDU Sheridan service
territory has experienced a 45 megawatt peak and operates at a 60 percent load
factor. The agreement is subject to approval or acceptance for filing by the
FERC.
The agreement provides for fixed rates for capacity and energy to be paid
by MDU during the 10-year contract term. MDU widely solicited proposals from
several entities, and Black Hills Power's rates under the contract were
accepted by MDU as the most competitive. Black Hills Power and MDU have
agreed not to apply to FERC for any rate changes in the contract for the
entire 10-year term other than increases caused by governmental direct taxes
on electric generation fired by hydrocarbons.
The agreement further provides for Black Hills Power and MDU to equally
share the costs of constructing a combustion turbine of approximately 70
megawatts at such time during the 10-year term that Black Hills Power
determines in its sole discretion that such turbine is required. If the
turbine is built, MDU's 50 percent interest in the combustion turbine will be
utilized by Black Hills Power for the balance of the 10-year term in payment
of a portion of MDU's capacity requirements under the agreement. MDU will
have the option to sell its interest in the combustion turbine to Black Hills
Power at the end of the 10 years from the first date of commercial operation
of the combustion turbine at original cost depreciated.
The sale to MDU is an off-system sale and will be delivered over Pacific
Power's transmission system by scheduling a portion of the power and energy
being purchased from Pacific Power under the Pacific Power Colstrip Contract.
See--ELECTRIC POWER SUPPLY--PACIFIC POWER COLSTRIP CONTRACT under this Item 1.
5
Black Hills Power entered into the agreement with MDU because it was an
opportunity to use energy from its new base load Neil Simpson Unit #2 and
other resources along with purchased peaking capacity to serve MDU resulting
in incremental savings to Black Hills Power's other customers. See--RATE
REGULATION--SOUTH DAKOTA--RETAIL--1995 RATE CASE. Management believes that
the incremental cost of performing its obligations under the MDU agreement
will be less than the revenues and benefits received by Black Hills Power from
the agreement for the entire 10-year term. However, the Company could incur
unexpected costs over the 10-year term which would not be recoverable from
MDU under the fixed rate agreement. Management believes that the MDU
agreement will remain profitable for the 10-year term, but no assurances can
be given.
FUTURE WHOLESALE OPPORTUNITIES. Black Hills Power expects to explore all
possible avenues to sell any surplus power and energy it may have from time to
time. 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 or other entity operating 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 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.
Wyodak Resources has formed a new subsidiary as a Wyoming corporation,
named WYGEN, Inc. to engage in the sole business of selling electric power and
energy at wholesale as an exempt wholesale generator. See--EXEMPT WHOLESALE
GENERATOR BUSINESS under this Item 1.
ELECTRIC POWER SUPPLY
GENERAL. Black Hills Power owns generation with a nameplate rating
totaling 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, SUNFLOWER AGREEMENT,
and RESERVE CAPACITY INTEGRATION AGREEMENT.
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
6
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 megawatts will be Black Hills Power's
largest generation resource when it comes into commercial operation in 1995
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.
The following chart illustrates a Black Hills Power estimated summer
rating reserve calculation for 1995 without Neil Simpson Unit #2 as compared
to 1995 when Neil Simpson Unit #2 is expected to be in commercial operation.
Reserve Analysis--Estimated
(1)Net Dependable Capability (kilowatts)--
Summer Rating
1995 1995
(without NS#2) (with NS#2)
Base Load Resources
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) 30,000 -
------- -------
Total Peaking Resources 140,000 110,000
------- -------
Total Base Load Peaking Resources 376,750 398,750
Less: Reserves 71,000 82,000
------- -------
Resources to Serve Load, less reserves 305,750 316,750
(1) See--UTILITY PROPERTIES under Item 2 for the nameplate rating of Black
Hills Power's generating resources.
(2) Black Hills Power will cancel agreement as of December 31, 1995.
(3) Sunflower contract expires September 30, 1996. Tentative agreement has
been reached to extend agreement for 20 megawatts up to 50 megawatts
commencing January 1, 1997 and continuing to July 1, 1999.
(4) Neil Simpson Unit #2 is scheduled for production on September 1, 1995.
7
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
$19,000 per megawatt month and an average of $14.50 per megawatt hour over the
last three years of this agreement. The Company's load factor related to this
contract has been approximately 59 percent over the last three years. The
energy purchased under this agreement in 1994 was approximately 25 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 $8.40 per
kilowatt month and $16 per megawatt hour. Black Hills Power intends to
exercise the option to cancel the Tri-State Contract as of December 31, 1995.
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 not to
exceed 15 percent.
Black Hills Power and Sunflower have reached a tentative agreement to
amend the peaking contract to provide for the purchase by Black Hills Power of
30 megawatts of peaking resource for the 1995 summer season and no purchase
thereafter until January 1, 1997, after which Black Hills will purchase a
minimum of 20 megawatts of peaking resource up to a maximum of 50 megawatts at
Black Hills Power's option until July 1, 1999, for certain but continuing
thereafter until 2006, subject to the right of either party to cancel on three
years' notice. Black Hills' payments for the capacity are $4.41, $4.63, and
$4.75 per kilowatt month for 1995, 1996, and 1997 and thereafter,
respectively. Black Hills Power will further pay any increases caused by WAPA
transmission rate increases or other certain governmental impositions.
The sale is conditioned upon WAPA agreeing to maintain a transmission
path for Sunflower for delivery to Black Hills Power at Stegall, Nebraska.
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
8
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.
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--RETAIL--1995 RATE CASE under this Item 1. Black
Hills Power purchased additional non-firm, short-term power during 1994 from
other electric power suppliers.
NEIL SIMPSON UNIT #2. Neil Simpson Unit #2, an 80 megawatt coal-fired
electric generating plant 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 net utility plant by more than 50
percent. See--RATE REGULATION--GUARANTEE OF THE CONSTRUCTION COSTS OF NEIL
SIMPSON UNIT #2 and SOUTH DAKOTA--RETAIL--1995 RATE CASE 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 REGULATION--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 currently scheduled by September
1, 1995.
The current estimated capital costs of Neil Simpson Unit #2 are
$111,000,000 plus $10,000,000 of allowance for funds used during construction
for a total estimated capital cost of $121,000,000. Allowance for funds used
during construction represents the approximate composite costs of borrowed
funds and a return on capital used to finance construction expenditures.
Whether the SDPUC and WPSC allow the new facility in rates will be
determined through rate cases scheduled during 1995. See--RATE
REGULATION--South Dakota--Retail--1995 Rate Case and Wyoming--Retail--1995
Rate Case 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.
9
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 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 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, and (iii) any
inability to enforce contracts or performance bonds due to any unexpected lack
of financial responsibility of contractors, vendors, or sureties.
As of March 1, 1995, the construction of Neil Simpson Unit #2 is
approximately 85 percent completed and is proceeding ahead of schedule. Based
upon all current contracts and the estimate furnished by the
architect/engineer, the Company expects to complete construction of Neil
10
Simpson Unit #2 by September 1, 1995, and at a cost of not to exceed
$121,000,000. The Guaranteed Construction Cost is $124,889,000.
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 is complying with all of the conditions, such conditions
do not constitute anything more than what Black Hills Power 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 is serving as a communication conduit for Black Hills
Power to keep all regulators advised of its continuing integrated resource
planning process.
SOUTH DAKOTA--RETAIL--1995 RATE CASE. On February 1, 1995, Black Hills
Power filed a general rate case with the SDPUC requesting a rate increase of
$8,338,650 or approximately 9.96 percent for each retail rate class in South
Dakota to take effect on or about September 1, 1995, when Neil Simpson Unit #2
is expected to become commercial. The SDPUC has jurisdiction of the rates
charged all of Black Hills Power's South Dakota retail customers, which
represent approximately 85 percent of the total of Black Hills Power's
electric sales, both retail and wholesale. The South Dakota filing
incorporates all of Neil Simpson Unit #2 in rate base. Based upon traditional
South Dakota ratemaking precedents, management believes that the rate filing
justifies an increase in revenue from South Dakota customers of $13,199,300 or
a 15.58 percent. However, Black Hills Power is requesting only the 9.96
percent conditioned upon the Company retaining the benefits commencing January
1, 1997, of the sale to MDU. See--ELECTRIC POWER SALES AND SERVICE
TERRITORY--ELECTRIC SALES--WHOLESALE TO MDU under this Item 1. This benefit
would be the difference between the revenues to be received from furnishing
the power and energy under the MDU contract and the incremental cost of
fulfilling the contract. The Company further proposes to agree to no further
rate increases to take effect prior to January 1, 1998, except for rate
increases caused by purchased power, increased taxes, or other material new
governmental impositions. The benefits the Company expects to receive from
the MDU sale in 1997 and sales growth are expected to make up the deficiency
in the proposed 9.96 percent rate increase and the 15.58 percent increase
management believes the Company could have justified, but Black Hills Power's
proposal does not restore the revenue deficiency between September 1, 1995 and
December 31, 1996. However, management has made the proposal to the SDPUC in
order to minimize large increases, to present a more phased-in rate increase
approach which would be more acceptable to its customers, and to remain more
competitive. See--COMPETITION IN THE ELECTRIC UTILITY BUSINESS under this
Item 1. Management believes that through good management and cost
containment, if the proposed rate increase is granted, the Company will be
able to maintain its earnings without any decrease through 1997 and with some
modest increases thereafter.
11
The Company expects the staff of the SDPUC and other various entities and
associations, including the Company's major industrial group, to intervene in
the South Dakota rate case and to contest the amount of the rate increase
requested by the Company. Management does believe, however, that the rate
increase is justified and that the evidence will more than justify the rate
increase requested. From contacts with major industrial customers and through
public information meetings concerning the pending South Dakota rate case,
management believes that the proposed rate increase will be acceptable and
substantially approved, but absolutely no assurances can be given.
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. 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
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
12
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.
Management does not believe that Black Hills Power is in a surplus
capacity condition and that it should be successful in getting Neil Simpson
Unit #2 into rate base. 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 capacity
or energy condition at the time Neil Simpson Unit #2 comes into commercial
operation, regulators could disallow a portion of Neil Simpson Unit #2 in rate
base for a period of time.
Based on statutory requirements, the SDPUC is expected to make its
decision on the rate filing prior to September 1, 1995.
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%). Black Hills Power estimates that the return on
equity to be applied in 1994 to determine the refund will be 12.3 percent.
The Company has accrued $760,000 in 1994 in anticipation of what Black Hills
Power estimates the refund to be for 1994 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 1994. See--COAL SALES--CONTRACT TO
SUPPLY COAL TO NEIL SIMPSON UNIT #2 under this Item 1.
WYOMING--RETAIL--1995 RATE CASE. In Wyoming, where revenue from retail
sales represented 7 percent of revenue from total electric sales in 1994,
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.
On March 1, 1995, Black Hills Power filed an application for a general
rate increase with the WPSC requesting that Neil Simpson Unit #2 be
incorporated as a part of the rate base. The application requests a 9.95
percent rate increase.
MONTANA--RETAIL. Black Hills Power's revenue from sales of electric
power in Montana in 1994 represented less than 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.
WHOLESALE--CITY OF GILLETTE. Black Hills Power sells electric power and
energy to the City of Gillette, Wyoming. See--ELECTRIC POWER SALES AND
SERVICE TERRITORY--ELECTRIC SALES--WHOLESALE TO THE CITY OF GILLETTE. Such
sales to Gillette represented approximately 8 percent of electric revenues
received in 1994. The tentative agreement reached between Black Hills Power
and the City of Gillette will provide for a rate increase to take effect on
the first date of commercial operation of Neil Simpson Unit #2, but not
earlier than September 1, 1995, that will yield additional revenues to
Black Hills Power from the Gillette sale of approximately $1 million (an
increase of approximately 15 percent from current rates), and the revenues
13
will be reduced approximately $200,000 (reducing the increase from current
rates to approximately 11.5 percent) per year commencing January 1, 1997, at
the commencement of the sale of wholesale power to MDU. Because the new
agreement will terminate a benefit Black Hills Power received from the use of
WAPA energy, Black Hills Power's cost to serve Gillette will increase
approximately $200,000 per year. Taking this additional cost into account,
the effective rate increase for Gillette commencing September 1, 1995, will be
approximately 12.3 percent and commencing January 1, 1997, approximately 8.8
percent from current rates. In the opinion of management, the agreement with
Gillette to increase rates fully incorporates Neil Simpson Unit #2
into the Company's rate base as far as that sale to Gillette is concerned and
will yield to the Company a rate of return on equity equal to at least the
amount that the FERC would have allowed if the rate case had been contested.
The new tentative Gillette agreement further provides for Gillette's agreement
that the methodology used to determine the price to be paid by Black Hills
Power to its affiliate Wyodak Resources for coal is just and reasonable.
Black Hills Power has further agreed not to apply to the FERC for any change
in rates charged the City of Gillette that would take effect prior to January
1, 1998, unless such increase was caused by unusual events.
The rates paid by Gillette are subject to regulation by the FERC on the
basis of a just and reasonable standard. Either party may apply to the FERC
for rate modifications to take effect on or after January 1, 1998. The
current rates were determined by negotiations between Gillette and Black
Hills Power.
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. Black Hills Power's transmission
system is interconnected to Pacific Power's transmission system near Gillette,
Wyoming. Pacific Power provides electric service at retail to large portions
of Wyoming west of Gillette, Wyoming. WAPA retails electric service to
certain government facilities in and around Black Hills Power's service
territory. 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. Also see--COMPETITION IN ELECTRIC UTILITY
BUSINESS--PUBLIC POWER--MUNICIPALIZATION under this Item 1.
In Wyoming, public utilities operate in service territories assigned by
the WPSC, and a franchise granted by the municipality's governing body is
required to serve within a municipality. Black Hills Power'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 Newcastle'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
14
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 5-year contract and the City of Gillette (See--ELECTRIC POWER
SALES AND SERVICE TERRITORY--ELECTRIC SALES--WHOLESALE TO CITY OF GILLETTE) is
under a 17-year contract for 23 megawatts of its base load. These three
customers together in 1994 accounted for 29 percent of Black Hills' total firm
kilowatthour sales and 20 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.
PUBLIC POWER--MUNICIPALIZATION. Every municipality in Black Hills
Power's service territory has the right upon meeting certain conditions to
acquire or construct a municipally owned electric system and to serve
customers within its city. As a wholesaler of electric power and energy, such
municipality would have the power to demand and receive transmission access
over Black Hills Power's transmission system. See--COMPETITION IN ELECTRIC
UTILITY BUSINESS--TRANSMISSION ACCESS. A municipality would not necessarily
have to form an electric system to serve all of a municipality but could
establish a municipal system to serve certain portions of the municipality for
certain customers, such as industrial customers. To form a city-wide electric
system, a municipality would have to construct an electric distribution system
or acquire the distribution system of the Company. The law is not clear if
the city could force Black Hills Power to grant the city "transmission
service" over the Company's distribution system. The Company would resist any
attempt to do so.
Black Hills Power is not aware of any movement by any municipality in its
service territory which does not already have a municipally owned electric
system to establish one.
COMPETITION IN ELECTRIC GENERATION. Under the Public Utility Regulatory
Policies Act (PURPA), certain small power generators burning waste fuel and
renewable fuel and certain cogenerators that utilize steam for a purpose other
than power generation are deemed to be qualifying facilities under PURPA 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--SOUTH DAKOTA--RETAIL--1995 RATE CASE under this Item 1.
However, major cogeneration facilities that would be qualifying facilities
under PURPA have been announced for construction in the Powder River Basin of
Wyoming near Wyodak Resources' coal mine.
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. See--EXEMPT WHOLESALE GENERATOR BUSINESS under this Item
1 explaining the Company's intent to engage in this business. The EWGs are
now exempt from the Public Utility Holding Company Act of 1935 (PUHCA). Under
15
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 able to build
new power plants to serve its own load growth.
TRANSMISSION ACCESS. The Energy Policy Act of 1992 provided for
amendments to the Federal Power Act that grant 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 electric energy may apply to FERC for an order
requiring a utility to transmit such energy, including the 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 to
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).
Black Hills Power does now furnish transmission service for competing
RECs and for the City of Gillette, Wyoming. However, the Energy Policy Act
can require Black Hills Power to furnish transmission service for competing
EWGs, qualifying facilities under PURPA, and other electric utilities,
thereby increasing competition for Black Hills Power. As long as the states
in which Black Hills Power operates continue to grant exclusive service
territories, the federal government does not preempt this state jurisdiction,
and municipalities in Black Hills Power's service territory do not establish
municipal electric systems, the increase in transmission access 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, the RECs and Pacific Power
serving around Black Hills Power's 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 from these entities.
16
Regular Residential Service
Percentage That
Competitor is Higher (+)
Monthly Cost or Lower (-)
(500 kWh) Than BHP Proposed Rates
SD - Black Hills Power $43.54 ---
(1)Proposed $47.25 ---
SD - Black Hills Electric (REC) $55.70 +18
SD - Butte Electric (REC) $57.64 +22
SD - West River Electric (REC) $52.50 +11
WY - Black Hills Power $39.58 ---
(1)Proposed $42.90 ---
WY - Tri-County Electric (REC) $34.37 -20
WY - Pacific Power $30.03 -30
Small Commercial Service
Monthly Cost
(6,000 kWh, 30 kW)
SD - Black Hills Power $529.11 ---
(1)Proposed $583.10 ---
SD - Black Hills Electric (REC) $381.40 -35
SD - Butte Electric (REC) $389.70 -33
SD - West River Electric (REC) $442.80 -24
WY - Black Hills Power $468.24 ---
(1)Proposed $501.25 ---
WY - Tri-County Electric (REC) $288.44 -42
WY - Pacific Power $328.32 -34
Large Commercial/Industrial Service
Monthly Cost
(120,000 kWh, 300 kW)
SD - Black Hills Power $6,776.45 ---
(1)Proposed $7,391.73 ---
SD - Black Hills Electric (REC) $7,053.00 - 5
SD - Butte Electric (REC) $8,283.00 +12
SD - West River Electric (REC) $7,645.30 + 3
WY - Black Hills Power $7,100.40 ---
(1)Proposed $7,674.81 ---
WY - Tri-County Electric (REC) $6,291.10 -18
WY - Pacific Power $4,485.40 -42
(1)Approximate cost if Black Hills Power's current rate applications are
granted.
17
Of the group, Black Hills Power, Tri-County Electric, and Pacific Power
have their rates established by commission order. The South Dakota RECs are
not under rate regulation and therefore have 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.
Management is cognizant of the competitive ramifications of the previous
rate comparability table in view of the movement toward more competition in
the electric industry. Black Hills Power's competitors also have construction
requirements and inflationary pressures which may require rate increases from
time to time. Pacific Power and the cooperatives through Basin Electric have
developed markets for their electric power and energy throughout the western
United States. Therefore, price competition is likely to be based on a wider
area than just in and around Black Hills Power's service territory. The cost
of electric power along the west coast of the United States is substantially
higher than Black Hills Power's rates. Management believes that through
prudent management and utilizing its coal supply, it will be able to compete
effectively.
Black Hills Power's management forecasts that its construction program
and anticipated load growth will result in rate increases higher than
inflation during 1995 but will be lower than inflation when averaged over ten
years. However, 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 1994 for its electric, mining, and
oil and gas production operations were $88,171,000, $5,911,000, and
$8,977,000, respectively.
The Company reviews its construction and capital program annually.
Current estimates of construction and capital expenditures for 1995 through
1997 are as follows:
1995 1996 1997
(in thousands)
Electric
Neil Simpson Unit #2 $31,100 $ - $ -
Other Production 1,100 1,200 1,800
Transmission 3,000 4,400 2,700
Distribution 8,000 7,000 7,700
General 1,100 2,400 2,300
------- ------- -------
Total $44,300 $15,000 $14,500
======= ======= =======
Coal mining $ 1,700 $ 2,500 $ 1,100
======= ======= =======
Oil and gas production $ 9,500 $ 6,000 $ 6,000
======= ======= =======
Total $55,500 $23,500 $21,600
======= ======= =======
BLACK HILLS POWER. The 1994 construction costs for the Company excluding
Neil Simpson Unit #2 were financed primarily with internally generated funds.
The above capital budget includes approximately $31,100,000 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.
18
FINANCING NEIL SIMPSON UNIT #2. The Company is financing the
construction of Neil Simpson Unit #2 and its other construction program with
the sale of additional shares of common stock, short-term borrowing, 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 per share. 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 raised an additional $2.4 million of equity
capital from the dividend reinvestment program in 1994.
To complete the equity portion of the capital budget, the Company plans
to cause Wyodak Resources to upstream $40 million of dividends during 1995.
To finance the debt portion of the construction program, the Company
filed a Form S-3, shelf registration in 1994 for $100 million first mortgage
bonds. The Company issued $45 million 30-year first mortgage bonds on
September 1, 1994, at an effective interest rate of 8.33 percent and $30
million 15-year first mortgage bonds on February 3, 1995, at an interest rate
of 8.06 percent. The 15-year first mortgage bonds are subject to a one-time
option of the holder to cause the Company to redeem the 15-year first mortgage
bonds in 2002. The Company also issued $3 million environmental improvement
revenue bonds in 1994 which the Company continues to remarket on a short-term
basis at variable interest rates.
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.
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.
WESTERN PRODUCTION. Western Production's capital program is planned to
be devoted primarily to oil and gas development drilling in Texas, California,
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 $3.5 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 all
coal sales to Black Hills Power (including the 20 percent share on the Wyodak
Plant and all sales to Black Hills Power's other plants) will be limited to a
return on Wyodak Resources' original cost, depreciated investment base. The
return is 4 percent (400 basis points) above A-rated utility bonds to be
applied to a new investment base each year. In addition, Wyodak Resources
19
committed to further reduce the coal price for coal to be used in any of Black
Hills Power's 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 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.
Sales and production statistics for the last five calendar years are as
follows:
Revenue from Sale % Revenue Derived
of Coal from Tons of Coal Sold
Year (in thousands) Black Hills Power (in thousands)
1994 $28,594 33% 2,796
1993 29,822 34 3,027
1992 28,296 35 2,958
1991 26,138 35 2,742
1990 26,528 36 2,908
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.
20
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 1994 Annual Report to
Shareholders of the Company on pages 12 through 18, incorporated herein by
reference.
Revenue from coal sales to the Wyodak Plant totaled $20,671,000 in 1994
or 72 percent of revenue for all coal sold by Wyodak Resources. The quantity
of coal sold in 1994 for the Wyodak Plant was 1,956,000 tons, as compared to
2,118,000 tons sold in 1993. 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 19 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 to continue to consume
approximately the same quantity of coal as in 1994 unless unexpected
mechanical failures occur. Of the 2,796,000 tons of coal sold by Wyodak
Resources in 1994, 915,000 tons were sold to Black Hills Power, 1,565,000 tons
were sold to Pacific Power, and 316,000 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 Revenue from Revenue from All Sales
Sales to Sales to Black Unaffiliated Customers
Pacific Power Hills Power (1) (includes Pacific Power)
Year (in thousands)
1994 $16,887 $ 9,445 $19,149
1993 17,448 10,047 19,775
1992 16,541 9,811 18,485
(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 249,000 tons under this contract in 1994. 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.
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.
21
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) (in thousands) (in thousands)
1994 $8,325 $729 $2,998
1993 7,489 759 3,148
1992 5,640 701 3,258
1991 4,780 693 3,595
1990 4,240 876 3,480
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.
PRODUCTION. Western Production produced approximately 609,000 equivalent
barrels of oil in 1994. Approximately 32 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 25
wells in 1994. Western Production's average working interest in such wells
was 19.6 percent, or 4.91 net wells. Approximately 84 percent of the wells
were classified as development wells and 16 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.
EXEMPT WHOLESALE GENERATOR BUSINESS
In 1995 Wyodak Resources formed a wholly owned subsidiary as a Wyoming
corporation named WYGEN, Inc. WYGEN applied for and received from the FERC a
determination that WYGEN has exempt wholesale generator status under Section
32 of the Public Utility Holding Company Act. WYGEN was formed for the sole
purpose of engaging in the generating and selling of electric power and energy
at wholesale. At this time WYGEN is proposing to build an 80 megawatt
coal-fired electric generating plant to be known as the Wygen Plant adjacent
to Neil Simpson Unit #2. WYGEN has filed with the Wyoming Department of
22
Environmental Quality an application for a prevention of significant
deterioration air quality construction permit. WYGEN has received commitments
from contractors which would supply the major components of the Wygen Plant to
furnish those components if WYGEN is able to commit the construction of the
Wygen Plant by the end of 1995. Based upon the commitments of these major
contractors, management believes that WYGEN would be able to construct the
Wygen Plant for approximately the same cost of construction as Neil Simpson
Unit #2.
WYGEN would not be able to finance and therefore would not commence
construction of the Wygen Plant until such time that WYGEN received power
purchase contracts from responsible entities. Financing would be obtained
through assignments of the power purchase contracts. The holders of the
debt to finance the Wygen Plant would have no recourse against the Company.
To date, WYGEN has not obtained the power purchase contracts that would be
required for the financing and construction of the Wygen Plant, and until such
contracts are obtained, WYGEN will not construct the Wygen Plant. The
wholesale electric market at this time trends toward short-term purchases. A
long-term contract would be required to finance the Wygen Plant. Unless the
wholesale electric market moves toward long-term commitments, it is not likely
that WYGEN will be able to construct the plant.
WYGEN's intent is to not sell electric power and energy to its affiliate,
the Company, but to sell electric power and energy to other electric utilities
and entities engaged in some facet of the electric power business. The
independent power producer business is highly competitive, and the Company
can give no assurances that WYGEN will be successful in obtaining the
purchased power contracts necessary to cause the Wygen Plant to be
constructed.
Markets for the electric power and energy from the Wygen Plant would
depend upon the ability of WYGEN to obtain transmission rights to cause
electric power and energy to be delivered over transmitting utilities'
transmission systems. While the Energy Policy Act of 1992 grants WYGEN the
rights to force transmission access through an application to the FERC, the
transmission of such power along with other new electric power generators
planned by qualifying facilities in the Wyoming area of the location of the
Wygen Plant may require the addition of major new transmission improvements.
The responsibility for the construction of such new transmission facilities is
uncertain, and if transmission improvements and access are not obtained
through negotiations, the time involved in completing a proceeding before the
FERC and in constructing any new transmission facilities can in effect delay
the time that WYGEN could make contractual commitments to deliver electric
power and energy to the market.
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.
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.
23
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.
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 have been submitted for the approval of the South Dakota
Department of Environment and Natural Resources ("DENR") and have been pending
for some time. The DENR has issued a permit for the operation of the Ben
French Plant.
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. The Company
continues to monitor proposed regulations and the preparation of EPA
24
guidelines that may require Black Hills Power to retrofit its plants under 25
megawatts to permit enhanced monitoring of air emissions. If such requirement
is imposed, management is unable at this time to determine the capital cost
and increased operating costs from such monitoring.
All facilities 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 the Ben French and Kirk plants in South
Dakota are estimated to be $25,000 for 1994; and for Neil Simpson Unit #1 and
Osage Plants in Wyoming, fees are estimated at $63,000 for 1994.
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 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. The Company is required 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.
25
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
NPDES PERMITS. All of the power plants operated by Black Hills Power
require permits under the National Pollutant Discharge Elimination System.
The permit for the continued discharge at the Ben French power plant has been
issued with decreased monitoring requirements, and the permits for the
other facilities are current, including authorizations for storm water
discharge. Renewal applications for the permits for the Ben French and the
Kirk power plants have been submitted to the DENR and have been pending for
some time. The permits for the other facilities are current, including
authorizations for storm water discharge.
In 1993 the Osage plant 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 have been the source of the high pH values.
Black Hills Power has applied for and received a modified permit and installed
a sulfuric acid treatment. Effluent at the Osage Plant has now been returned
to an acceptable pH level.
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.
SPCC PLANS. Pollution prevention plans are in place for the plant
facilities, and the current Spill Prevention Control and Countermeasures plans
have been updated and include hazardous materials contingency plans.
A random inspection by a contractor and representative of the
Environmental Protection Agency (EPA) took place in 1993 at the Ben French
power plant. The inspection occurred prior to the implementation of the
updated plan at that facility. On April 28, 1994, the EPA, Region VIII,
notified Black Hills Power of alleged deficiencies in compliance with the Oil
Pollution Prevention Regulations promulgated under the Clean Water Act. On
August 3, 1994, Black Hills Power responded to the EPA letter of deficiency
and submitted for review an updated SPCC Plan for the Ben French station.
Management disagrees with many of the EPA's alleged deficiencies and
interpretation of the applicable regulations. To date the EPA has not
responded to the Black Hills Power response. The deficiencies alleged by the
EPA may result in civil penalties being imposed. No opinion can be provided
at this time as to the amount of the penalties.
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. A
five-year permit for the expansion of the current ash disposal site for the
Ben French power plant has been received from the DENR. A permit for
reclamation of a historic disposal site at Osage has been obtained, and the
closure of the old ash dam has been approved. The application for renewal and
26
expansion of the landfill permit at Osage is pending. 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.
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 $600,000 was charged to operations as reclamation expense in
1994. As of December 31, 1994, accrued reclamation costs were approximately
$7,600,000.
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 fourth year of a
27
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.
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. Three unauthorized oil releases occurred in 1994 as a
result of equipment owned by Black Hills Power. Two of the releases, one of
which was in excess of 1,600 gallons of diesel fuel, occurred to earthen berms
adjacent to storage tanks. The other involved a small amount of petroleum
product, and all releases were located on Black Hills Power property. 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 1994 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. Although based on samples
from monitoring wells management does not believe the fuel oil has migrated to
waterways, the fuel oil has the potential of 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, a duct-bank remediation system is currently in place. This system
is designed to channel the oil to a recovery location.
Additional monitoring wells were installed in the area during 1993, and
very minimal amounts of fuel oil as a free product continues to be removed
from the site on a monthly basis. No time frame for the completion of the
remediation work has been established.
Costs for the cleanup are currently approximately $350,000. Black Hills
Power has applied for reimbursement of these costs from the South Dakota
Petroleum Release Compensation Fund. The initial request for the sum of
$46,700 has been considered and reimbursed to the extent of $27,700, which
includes the reduction for the $10,000 deductible amount. The Company's
additional requests for reimbursement are still under consideration. Apart
from the application of a second deductible amount of $10,000, no estimation
of the reimbursement amount can be made at this time. To date, no penalties,
28
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 voluntarily undertook the
clean-up of an unpermitted oil disposal site located near its facilities
outside Newcastle, Wyoming. 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 has completed the remediation and reclamation of the
site with the approval of the DENR.
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 the State of Florida 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, 1994, the number of employees of the Company (including
Black Hills Power), Wyodak Resources, and Western Production were 356, 55, and
41, respectively, for a total of 452 employees.
29
ITEM 2. PROPERTIES
UTILITY PROPERTIES
The following table provides information on the generating plants of
Black Hills Power. During 1994, 99 percent of the fuel used in electric
generation, measured in Btus (British thermal units), was coal.
Generating Units Plant Totals
---------------- ------------
Net Generation
Twelve Months
Name Plate Ended
Year of Rating Principal December 31, 1994
Installation (Kilowatts)(a) Fuel (thousands of KWH)
Osage Plant 1948 11,500 Coal
(Osage, Wyoming) 1950 11,500 Coal
1952 11,500 Coal 213,123
Kirk Plant 1956 18,750 Coal 104,720
(Lead, South Dakota)
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 163,289
Neil Simpson Unit #1 1969 21,760 Coal 103,818
(Wyodak, Wyoming)
Wyodak Plant 1978(c) 72,400(c) Coal 523,580
(Wyodak, Wyoming)
------- ---------
Total 283,210 1,108,530
(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.
30
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, 1994 are set forth in the following table:
Estimated Tons of
Recoverable Coal
(in thousands)
Fee coal 1,079
Federal lease dated May 1, 1959 17,914
Federal lease dated April 1, 1961 6,987
Federal lease dated October 1, 1965 117,534
Federal lease dated September 28, 1983 20,355
Federal lease dated March 1, 1983 22,604
-------
186,473
Coal reserves are estimated at 186,473,000 tons of which approximately
30,292,000 tons are committed to be sold to the Wyodak Plant, approximately
9,000,000 tons to Black Hills Power's other plants, and 20,000,000 tons for
Neil Simpson Unit #2. Purchase options are granted on 51,000,000 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.
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.
31
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 30,292,000 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.
These facilities were substantially completed in 1995. 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 were $23,812,000, of which Pacific
Power paid $19,168,000 and Wyodak Resources $4,644,000. The reason for the
large amount 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 operates the in-pit system, the conveyor to
Neil Simpson Unit #1, and the truck load-out system, and PacifiCorp operates
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 349 wells as of December 31, 1994. 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 and two are located in
Washakie County, Wyoming. Western Production does not operate but owns a
working interest in 61 producing properties located in Wyoming, Kansas,
Colorado, Montana, North Dakota, Texas, and California. 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, 1994 and 1993, and a reconciliation of the changes between these dates
using constant product prices for the respective years. These estimates are
32
based on reserve reports prepared 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.
1994 1993
Oil Gas Oil Gas
(in thousands of barrels of oil and MCF of gas)
Proved developed and
undeveloped resources:
Balance at beginning of year 1,116 2,759 2,199 3,243
Production (321) (1,731) (327) (777)
Additions 107 7,582 259 1,847
Revisions to previous
estimates due to changed
economic conditions 536 470 (1,015) (1,554)
----- ----- ----- -----
Balance at end of year 1,438 9,080 1,116 2,759
===== ===== ===== =====
Proved developed reserves at
end of year included above 1,436 6,246 1,116 2,759
===== ===== ===== =====
Year-end prices $15.75 $1.72 $13.00 $2.35
Western Production has approximately 141,000 gross and 64,000 net acres
of oil and gas leases, out of which 27,000 gross and 15,000 net acres are
producing and 114,000 gross and 49,000 net acres are undeveloped. Approxi-
mately 45 percent of the undeveloped acres are held by production
or through paid-up leases 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.
33
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 1994.
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
Mr. Landguth was elected to his present position in January 1991. He had
served as President of Black Hills Corporation since October 1989.
Dale E. Clement, born August 1, 1933, Senior Vice President - Finance
Mr. Clement was elected to his present position in September 1989.
Roxann R. Basham, born August 6, 1961, Secretary and Treasurer
Ms. Basham was elected to her present position January 1, 1993. She had
served as Assistant Secretary/Treasurer since May 1991 and as Financial
Analyst since February 1985.
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.
Thomas M. Ohlmacher, born September 18, 1951, Vice President - Power Supply
Mr. Ohlmacher was elected to his present position on August 1, 1994. He
had served as Director of Power Generation since 1993, Director of
Electric Operations since 1991, and Manager of Planning since 1987.
James M. Mattern, born June 26, 1954, Vice President - Administration
Mr. Mattern was elected to his present position on August 1, 1994. He
had served as Rapid City Area Manager since January 1994, Director of
Human Resources since 1991, and Manager of Human Resources since 1987.
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, 1994, 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, 1994, appended
hereto.
34
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, 1994, 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, 1994, on pages 12 through 18 appended hereto.
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, 1994, 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, 1994, 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 23, 1995.
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 23, 1995.
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 23, 1995.
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 23, 1995.
35
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, 1994 . . . . 20
Consolidated Statements of Cash Flows for
the three years ended December 31, 1994 . . . . . . 21
Consolidated Balance Sheets at December 31, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . 22
Consolidated Statements of Capitalization at
December 31, 1994 and 1993 . . . . . . . . . . . . . 23
Notes to Consolidated Financial Statements . . . . .24-29
* Page References are to the incorporated portion of the Annual
Report to Shareholders of the Company for the year ended
December 31, 1994.
2. Schedules
All schedules have been omitted because of the absence of the
conditions under which they are required or because the required
information is included elsewhere in the financial statements
incorporated by reference in the Form 10-K.
3. Exhibits
*3(a) Restated Articles of Incorporation dated May 24,1994 (Exhibit
3(i) to Form 8-K dated June 7, 1994, File No. 1-7978).
*3(b) Bylaws dated December 10, 1991 (Exhibit 3(a) to Form 10-K for
1991).
*4(a) Reference is made to Article Fourth (7) of the Restated
Articles of Incorporation of the Company (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 A-2, File No. 2-4832); (Exhibit 7-B to Form S-1, File No.
2-6576); (Exhibit 7-C to Form S-1, File No. 2-7695); (Exhibit
7-D to Form S-1, File No. 2-8157); (Exhibit 4.05(e) to Form
S-3, File No. 33-54329); (Exhibit 4-I to Form S-1, File No.
2-9433); (Exhibit 4-H to Form S-1, File No. 2-13140); (Exhibit
4-I to Form S-1, File No. 2-14829); (Exhibits 4-J and 4-K to
Form S-1, File No. 2-16756); (Exhibits 4-L, 4-M, and 4-N to
Form S-1, File No. 2-21024); (Exhibits 2(q), 2(r), 2(s),
2(t), 2(u), and 2(v) to Form S-7, File No. 2-57661); (Exhibit
36
4.05(t), 4.05(u) and 4.05(v) to Form S-3, File No. 33-54329);
(Exhibit 4(b) to Form S-3, File No. 2-81643); (Exhibit
4.05(x), 4.05(y), and 4.05(z) to Form S-3, File No. 33-54329);
(Exhibit 4(d) and 4(e) to Post-Effective Amendment No. 1 to
Form S-8, File No. 33-15868); (Exhibit 4.05(ac) to Form S-3,
File No. 33-54329); and (Exhibit 4.05(ad) to Form S-3, File
No. 33-54329).
*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
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).
37
*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 Agreement 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).
*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 10-K 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).
38
*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.
*10(ab) Compensation Plan for Outside Directors (Exhibit 10(bb) to
Form 10-K for 1992).
*10(ac) Retirement Plan for Outside Directors dated January 1, 1993
(Exhibit 10(cc) to Form 10-K for 1992).
10(ad) The Amended and Restated Pension Equalization Plan of Black
Hills Corporation dated January 27, 1995.
10(ae) Black Hills Corporation 1995 Executive Gainsharing Program.
10(af) Black Hills Corporation 1995 Results Compensation Program.
*10(ag) 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(ah) Agreement for Supplemental Pension Benefit for Everett E. Hoyt
dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for 1992).
*10(ai) Agreement for Supplemental Pension Benefit for Dale E. Clement
dated December 19, 1991 (Exhibit 10(hh) to Form 10-K for
1992).
*10(aj) Power Integration Agreement, dated September 9, 1994, between
the Company and Montana-Dakota Utilities Co., a Division of
MDU Resources Group, Inc. (Exhibit 10(gg) to Form 8-K dated
September 12, 1994, File No. 1-7978).
13 Annual Report to Shareholders of the Registrant for the year
ended December 31, 1994.
21 Subsidiaries of the Registrant.
39
23 Consent of Independent Public Accountants.
27 Financial Data Schedule.
* Exhibits incorporated by reference.
(b) No reports on Form 8-K have been filed in the quarter ended
December 31, 1994.
(c) See (a) 3. above.
(d) See (a) 2. above.
40
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 15, 1995
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 15, 1995
Daniel P. Landguth (Chairman, Executive Officer
President, and Chief Executive)
DALE E. CLEMENT Director and Principal March 15, 1995
Dale E. Clement (Senior Vice Financial Officer
President - Finance)
GARY R. FISH Principal Accounting March 15, 1995
Gary R. Fish (Controller) Officer
GLENN C. BARBER Director March 15, 1995
Glenn C. Barber
BRUCE B. BRUNDAGE Director March 15, 1995
Bruce B. Brundage
MICHAEL B. ENZI Director March 15, 1995
Michael B. Enzi
JOHN R. HOWARD Director March 15, 1995
John R. Howard
EVERETT E. HOYT Director and Officer March 15, 1995
Everett E. Hoyt (President
and Chief Operating Officer
of Black Hills Power)
KAY S. JORGENSEN Director March 15, 1995
Kay S. Jorgensen
CHARLES T. UNDLIN Director March 15, 1995
Charles T. Undlin
41
APPENDIX
BLACK HILLS CORPORATION
The following items, appended hereto, are incorporated into the Form
10-K from the 1994 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
42
EXHIBIT INDEX
EX-10(ad) The Amended and Restated Pension Equalization Plan of Black
Hills Corporation dated January 27, 1995
EX-10(ae) Black Hills Corporation 1995 Executive Gainsharing Program
EX-10(af) Black Hills Corporation 1995 Results Compensation Program
EX-13 Annual Report to Shareholders of the Registrant for the
year ended December 31, 1994
EX-21 Subsidiaries of the Registrant
EX-23 Consent of Independent Public Accountants
EX-27 Financial Data Schedule