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.
<PAGE>
DEFINITIONS
When the following terms are used in the text they will have the meanings
indicated.
Term Meaning
Black Hills Power. . . . . . . . Black Hills Power and Light Company, the
assumed business name of the Company under
which its electric operations are conducted
Basin Electric . . . . . . . . . Basin Electric Power Cooperative, Inc., a
rural electric cooperative engaged in
generating and transmitting electric power
to its member RECs
Company. . . . . . . . . . . . . Black Hills Corporation
DEQ. . . . . . . . . . . . . . . Department of Environmental Quality of the
State of Wyoming
EAFB . . . . . . . . . . . . . . Ellsworth Air Force Base, a military air
force base near Rapid City, South Dakota
FERC . . . . . . . . . . . . . . Federal Energy Regulatory Commission
Indenture. . . . . . . . . . . . Indenture of Mortgage and Deed of Trust of
the Company
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
<PAGE>
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
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL
The Company was incorporated under the laws of South Dakota in 1941 under
the name Black Hills Power and Light Company. In 1986 the Company changed its
name to Black Hills Corporation and now operates its investor-owned electric
public utility operations under the assumed name of Black Hills Power and
Light Company. In addition the Company has diversified into coal mining
through Wyodak Resources and into oil and gas production through Western
Production.
Black Hills Power is engaged in the generation, purchase, transmission,
distribution, and sale of electric power and energy to approximately 53,959
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
<PAGE>
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
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
</TABLE>
Reference is made to the Consolidated Statements of Income and Note 11 of
"Notes to Consolidated Financial Statements" appended hereto.
ELECTRIC POWER SALES AND SERVICE TERRITORY
ELECTRIC POWER SALES--RETAIL. Even though Black Hills' service area
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<TABLE>
Reserve Analysis--Estimated
(1)Net Dependable Capability (kilowatts)--
Summer Rating
<CAPTION>
1995 1995
(without NS#2) (with NS#2)
<S> <C> <C>
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
<FN>
(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.
</TABLE>
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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
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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.
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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
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<PAGE>
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.
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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
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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
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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
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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
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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
<PAGE>
<TABLE>
<CAPTION>
Regular Residential Service
Percentage That
Competitor is Higher (+)
Monthly Cost or Lower (-)
(500 kWh) Than BHP Proposed Rates
<S> <C> <C>
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
<FN>
(1)Approximate cost if Black Hills Power's current rate applications are
granted.
</TABLE>
17
<PAGE>
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:
<TABLE>
<CAPTION>
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
Revenue from Sale % Revenue Derived
of Coal from Tons of Coal Sold
Year (in thousands) Black Hills Power (in thousands)
<S> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C>
1994 $16,887 $ 9,445 $19,149
1993 17,448 10,047 19,775
1992 16,541 9,811 18,485
<FN>
(1) Is not adjusted for refunds under South Dakota rate order. See
RATE REGULATION of this Item 1.
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
Oil and Gas Gas Plant Field
Sales Revenue Services
(in thousands) (in thousands) (in thousands)
<S> <C> <C> <C>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
</TABLE>
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C>
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
<FN>
(a) Nameplate rating is the capacity assigned to the generating unit by the
manufacturer. Actual generating capability depends upon duration of
usage, conditions of operation and other factors. See--ELECTRIC POWER
SUPPLY--RESERVES for an Analysis of the Net Dependable Capability--Summer
Rating for these resources.
(b) These combustion turbines are those referenced by the reserve capacity
integration agreement with Pacific Power. See ELECTRIC POWER SUPPLY
under Item 1 and the PacifiCorp Settlement.
(c) Black Hills Power's 20 percent interest. See Note 6 of "Notes to
Consolidated Financial Statements" appended hereto.
</TABLE>
30
<PAGE>
Black Hills Power owns transmission lines and distribution systems in and
adjoining the communities served consisting of 445 miles of 230 kV, 4 miles of
115 kV, 532 miles of 69 kV, 8 miles of 47 kV, and numerous distribution lines
of less voltage. Black Hills Power owns a service center in Rapid City,
several district office buildings at various locations within its service
area, and an eight-story home office building at Rapid City, South Dakota
housing its home office on four floors, with the balance of the building
rented to three tenants.
MINING PROPERTIES
Wyodak Resources is engaged in mining and processing sub-bituminous coal
near Gillette in Campbell County, Wyoming. The coal averages 8,000 Btus per
pound. Mining rights to the coal are based upon coal owned and five federal
leases. The estimated tons of recoverable coal from each source as of
December 31, 1994 are set forth in the following table:
<TABLE>
<CAPTION>
Estimated Tons of
Recoverable Coal
(in thousands)
<S> <C>
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
</TABLE>
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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
1994 1993
Oil Gas Oil Gas
(in thousands of barrels of oil and MCF of gas)
<S> <C> <C> <C> <C>
Proved developed and
undeveloped resources:
Balance at beginning of year 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
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
*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
<PAGE>
*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
<PAGE>
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
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
BLACK HILLS CORPORATION
By DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman,
President, and Chief Executive
Dated: March 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
<PAGE>
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
<PAGE>
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
<PAGE>
PENSION EQUALIZATION PLAN EXHIBIT 10(ad)
OF BLACK HILLS CORPORATION
This Pension Equalization Plan ("Plan") is hereby amended
and restated by Black Hills Corporation ("Company") effective the
27th day of January, 1995.
1. PURPOSE OF PLAN.
The purpose of the Plan is to provide to Participants
certain retirement and death benefits in addition to those
benefits which the Participants may enjoy from the Company's tax
qualified defined benefit plan in order to equalize total
retirement benefits being paid to persons holding like executive
positions by other companies. The Plan is designed to aid the
Company in attracting and retaining its executive employees,
persons whose abilities, experience and judgment can contribute
to the well-being of the Company.
2. DEFINITIONS.
"Annual Compensation Limitation" shall mean the
limitation on annual compensation for tax
qualified retirement plans as set forth in
Internal Revenue Code Section 401(a)(17) as the
same may be amended hereafter from time to time.
"Average Earnings" shall mean whichever of the
following results in the highest annual average
Earnings: (i) a Participant's average Earnings
for the five (5) consecutive full calendar years
of employment during the ten (10) full calendar
years of employment immediately preceding the
Calculation Date, which results in the highest
such average; or (ii) a Participant's average
Earnings determined by dividing the sum of the
following by five (5): (a) the Participant's
Earnings for the four full calendar years
preceding the year containing his Calculation
Date; (b) the Participant's Earnings for the year
containing his Calculation Date as of the
Calculation Date; and (c) a portion of the
Participant's Earnings for the fifth full calendar
year preceding the year containing his Calculation
Date determined by multiplying his Earnings for
said fifth preceding full calendar year by a
ratio, the numerator of which shall be 365 minus
the number of days in the year containing his
Calculation Date measured from the first day of
said year to his Calculation Date, and the
denominator of which ratio shall be 365. If the
Participant has less than five (5) full calendar
years of employment, the average shall be taken
over his total full calendar years of employment.
"Calculation Date" shall mean the earlier of
(i) the date the Participant's employment with the
Company was terminated, (ii) the date that the
Participant's participation in the Plan was
terminated, or (iii) the date of the Participant's
death.
"Committee" shall mean the Compensation Committee
of the Board of Directors of the Company.
"Earnings" shall mean the compensation paid to a
Participant by the Company during a calendar year,
including any amounts paid to the Participant as
overtime, bonus, commission or incentive
compensation, any Earnings reduction under a cash
or deferred arrangement under Section 401(k) of
the Internal Revenue Code, and any salary
reduction under a flexible benefit program under
Section 125 of the Internal Revenue Code, but
excluding reimbursements and expenses allowances,
fringe benefits, moving expenses, nonqualified
deferred compensation, and welfare benefits.
"Pension Restoration Benefit" shall mean the
benefit payable under paragraph 8.
"PEP Benefits" shall mean the benefits payable
under paragraph 4.
"Salary Level" shall mean the base compensation
paid to a Participant by the Company during a
calendar year, including any compensation
reduction under a cash or deferred arrangement
under Section 401(k) of the Internal Revenue Code
or under a flexible benefit program under Section
125 of the Internal Revenue Code but not including
any amounts paid to the Participant as overtime,
bonus, commission or incentive compensation, nor
reimbursements and expense allowances, fringe
benefits, moving expenses, nonqualified deferred
compensation, or welfare benefits.
"Social Security Wage Base" shall mean the
contribution base as determined under Section
1402(k)(1) of the Internal Revenue Code.
3. PARTICIPANTS.
Those persons eligible for participation in the Plan
("Participants") are those management employees of the Company
whose Salary Level equals or exceeds the Social Security Wage
Base and who are designated by the Board of Directors of the
Company upon recommendation of the Chief Executive Officer of the
Company. The Board of Directors may in its discretion
discontinue the participation of any Participant in the Plan at
any time.
4. PEP BENEFITS.
Benefits payable to Participants ("PEP Benefits") shall
consist of 180 equal monthly payments, each payment in the amount
of one-twelfth of the product of (i) the Participant's Average
Earnings as of the Calculation Date times (ii)(a) 25 percent if
the Participant's Average Earnings as of the Calculation Date is
less than twice the Social Security Wage Base; or (b) 30 percent
if the Participant's Average Earnings equals or exceeds twice the
Social Security Wage Base; times (iii) the applicable vesting
percentages provided in paragraph 7.
5. COMMENCEMENT OF PAYMENT OF PEP BENEFITS.
PEP Benefit payments shall be paid commencing at the
earliest of (i) the time the Participant is 62 years of age or
more and is no longer an employee of the Company; or (ii) upon
the death of the Participant. PEP Benefits shall be paid to the
Participant or, if deceased, to the Participant's designated
beneficiary, or, if none, to his or her estate. If the
Participant's death occurs after commencement of PEP Benefit
payments to the Participant under the Plan, the Participant's
designated beneficiary or estate will continue to receive the
balance of the payments due the Participant under the Plan.
6. DESIGNATION OF BENEFICIARY.
A Participant may designate a beneficiary or beneficiaries
for PEP Benefits which shall be effective upon filing written
notice with the Compensation Committee of the Company on the form
provided for that purpose. If more than one beneficiary
designation has been filed, the beneficiary or beneficiaries
designated in the notice bearing the most recent date will be
deemed the valid beneficiary or beneficiaries.
7. VESTING OF PEP BENEFITS.
PEP Benefits payable under the Plan will vest at the
following rate:
Years of Plan Participation Percent of Benefit
Vested
Less than 3 years 0
3 years but less than 4 20
4 years but less than 5 35
5 years but less than 6 50
6 years but less than 7 65
7 years but less than 8 80
8 or more years 100
No credit for service with the Company prior to the
effective date of the Plan shall be given. The provisions for
vesting set forth in this paragraph are not intended to give any
Participants any rights or claim to any specific assets of the
Company.
8. PENSION RESTORATION BENEFIT.
In the event that at the time of a Participant's retirement
from the Company the Participant's salary level exceeds the
Annual Compensation Limitation, then, the Participant shall
receive an additional benefit ("Pension Restoration Benefit")
which shall be measured by the difference between the monthly
benefit which would have been provided to the Participant under
the Company's tax qualified defined benefit plan ("Pension Plan")
as if there were no Annual Compensation Limitation and the
monthly benefit to be provided to the Participant under the
Pension Plan. The Pension Restoration Benefit shall be
determined using the same factors, actuarial or otherwise, as
used in determining the Participant's Pension Plan benefit and
shall be payable at like times and manner as the Pension Plan
benefit.
9. LOSS OF BENEFITS.
Notwithstanding any other provisions in this Plan, if a
Participant is terminated on account of misconduct or dishonesty,
the Participant shall forfeit all right to any benefits payable
under this Plan, including vested accrued benefits.
10. FUNDING OF PLAN.
All benefit payments under the Plan will be made from the
general assets of the Company. Participants and their
beneficiaries who are entitled to be paid benefits under this
Plan are unsecured general creditors of the Company. The Company
may, but shall not be required to, invest corporate assets in
life insurance or annuity contracts to assure that the Company
will have a source of funds for the payment of benefits required
to be paid under this Plan. Any such insurance or annuity
contract shall constitute assets of the Company and the employee
shall have no right, title or interest in any such insurance or
annuity contract. The Company reserves the right to refuse
participation in the plan to any Participant who, if requested to
do so, declines to supply information or to otherwise cooperate
as necessary to allow the Company to obtain insurance on the
Participant's life.
11. PLAN MAY BE MODIFIED OR DISCONTINUED.
The Company reserves the right to amend, modify or
discontinue the Plan at any time. Any modification or
discontinuance of benefits shall not reduce accrued benefits
which become vested prior thereto.
12. WITHHOLDING.
There shall be deducted from all benefits paid under this
Plan the amount of any taxes required to be withheld by any
federal, state or local government. The Participants and their
beneficiaries, distributees and personal representatives will
bear any and all federal, foreign, state, local or other income
or other taxes imposed on amounts paid under this Plan.
13. ASSIGNABILITY.
No right to receive payments under this Plan shall be
subject to voluntary or involuntary alienation, assignment or
transfer.
14. ADMINISTRATION OF THE PLAN.
The Plan shall be administered by the Committee. The
Committee shall conclusively interpret the provisions of the
Plan, decide all claims, and shall make all determinations under
the Plan. The Committee shall act by vote or written consent of
a majority of its members.
15. CLAIMS PROCEDURE.
All claims for benefits under the Plan shall be made to the
Committee. If the Committee denies a claim, the Committee may
provide notice to the Participant or beneficiary, in writing,
within 90 days after the claim is filed unless special
circumstances require an extension of time for processing the
claim, not to exceed an additional 90 days. If the Committee
does not notify the Participant or beneficiary of the denial of
the claim within the time period specified above, then the claim
shall be deemed denied. The notice of a denial of a claim shall
be written in a manner calculated to be understood by the
claimant and shall set forth (1) specific references to the
pertinent Plan provisions on which the denial is based; (2) a
description of any additional material or information necessary
for the claimant to perfect the claim and an explanation as to
why such information is necessary; and (3) an explanation of the
Plan's claim procedure.
Within 60 days after receipt of the above material, the
claimant shall have a reasonable opportunity to appeal the claim
denial to the Committee for a full and fair review. The claimant
or his duly authorized representative may (1) request a review
upon written notice to the Committee; (2) review pertinent
documents; and (3) submit issues and comments in writing.
A decision on the review by the Committee will be made not
later than 60 days after receipt of a request for review, unless
special circumstances require an extension of time for processing
(such as the need to hold a hearing), in which case a decision
shall be rendered as soon as possible, but not later than 120
days after receipt of a request for review. The decision on
review shall be in writing and shall include specific reasons for
the decision, written in a manner calculated to be understood by
the claimant, as well as specific references to the pertinent
Plan provisions on which the decision is based.
16. GOVERNING LAW.
This agreement shall be governed by and construed in
accordance with the laws of the state of South Dakota.
17. NO EMPLOYMENT CONTRACT.
Neither the action taken by the Company in establishing the
Plan or any action taken by it or by the Committee under the
provisions hereof or any provision of the Plan shall be construed
as giving to any eligible Participant the right to be retained in
the employment of the Company.
18. NONQUALIFIED PLAN.
This Plan is not intended to be a tax qualified plan under
the Internal Revenue Code.
BLACK HILLS CORPORATION
By /s/ Daniel P landguth
Its Chairman, President & CEO
1995 EXHIBIT 10(ae)
EXECUTIVE
GAINSHARING PROGRAM
<PAGE>
1995 EXECUTIVE GAINSHARING PROGRAM
The Executive Gainsharing Program is one of three sections of a Company-wide
gainsharing program. Other work units participating in the Company-wide
program are the Bargaining Unit and a program for the Staff. Each of the
three work units have goals established in which participants can directly
influence the results. The maximum award that any participant may receive is
three percent.
This program is designed for the officers in the following positions:
Chairman, President and CEO; President and COO; Sr. Vice President, Finance;
Vice President, Administration; Vice President, Power Supply;
Secretary/Treasurer, and Controller.
Black Hills Corporation
1995 Executive Gainsharing Program Goals
I. Safety Goal (1%)
This category has a total award value of 1%. The category is comprised
of safety goals dependent on each other. The goals are:
A. Motor Vehicle Accidents
B. OSHA Lost Time Accidents
To receive a 1% award, the Company average must be less than the NCEA
average at year-end in each respective area.
II. O&M Expense Reduction Goal (1%)
This category has a total award value of 1%. For an award to be paid in
this category, a reduction in the O&M budget must occur. A payout to
the participants will be equal to one-third of the average company-wide
participant gainshare payout.
Example: If the average 1995 gainshare award payout per participant
is 2.5%, each participant (officer) in this specific program
would receive a payout equal to .825%.
III. Rate Case Goals (1%)
The goal has a total award value of 1%. Each participant will develop a
goal representing their respective area of responsibility in relation to
successful South Dakota and Wyoming rate cases. At year-end, the CEO
will determine to what degree the goal has been achieved. Awards for
each participant can be made in 1/4% increments not to exceed 1%.
Note: For each MVA, LTA, or public liability an individual employee has, the
equivalent of a 1% award will be deducted from their award as previously
calculated. (An employee could lose the entire 3% potential award should
they incur three of the above mentioned incidents.)
Stop Loss: The basic goal of gainsharing is to reduce costs. Therefore,
employees who have a MVA, LTA, public liability, operations or property
damage loss in excess of $10,000 and are found to be at fault will be
ineligible for any Gainshare Award that year. An incident that occurs in one
year but accumulates expenses in more than one year would affect an
employee's Gainsharing Award in the year expenses reach $10,000. The
Gainsharing Committee will address special situations and determine effect.
GUIDELINES
The program will be comprised of a one year period starting January 1, 1995,
through December 31, 1995. The gainshare program calculations and payout
checks, if awarded, will be issued in the first quarter of the following year.
An individual employee's gainsharing bonus, if any, will be paid on gross pay
as it appears on the employee's W-2. This includes regular, paid time off,
and other forms of compensation.
An employee who transfers between one of the three gainshare programs as
defined in the 1995 Gainsharing Program will have their gainshare bonus, if
awarded, based upon where the greatest amount of time worked occurred. The
maximum gainsharing award an employee may receive is 3%.
Anyone terminated from employment with Black Hills Corporation before the
completion of the program will not be eligible for any gainsharing bonus.
Exceptions would be death, permanent disability or retirement.
Board of Directors Retain Discretion
This Plan is not at any time a contract of employment. The Company reserves
the right to change this Plan whenever and in any manner it deems appro-
priate. Irrespective of changes in the Plan, no rights are vested. All
awards are earned only when and if finally approved by the Board of Directors
notwithstanding anything contained in the Plan that may be construed to be to
the contrary.
The Board of Directors, in its sole and absolute discretion, may decline to
approve any award, though the participant may have achieved or exceeded
threshold and target levels of performance. Setting a threshold or target
of performance for any participant does not constitute a promise to pay an
award even if the participant meets the threshold or target of performance.
In determining whether to make an award and the amount of the award,
the Board of Directors may consider criteria other than or in addition to the
threshold and target performance determined under this Plan. Nothing in this
Plan is a promise by the Company or any of its subsidiaries to continue to
employ any participant for any period of time.
EXHIBIT 10(af)
1995
RESULTS
COMPENSATION
PROGRAM
Black Hills Power and Light Company
Wyodak Resources Development Corp.
Western Production Company
<PAGE>
RESULTS COMPENSATION PROGRAM
In 1995, we are continuing the Results Compensation program which was imple-
mented in 1994. This program has significantly enhanced the Corporation's
compensation philosophy and practice.
The Results Compensation program is designed to recognize and reward the
contribution that group performance makes to corporate success. Results
Compensation can pay financial rewards up to 8 percent of your earnings.
Group Performance
There are several elements that go into determining the success of the
Corporation. Some of these elements include: the contributions employees
make to achieve goals; both on an individual basis and as part of a work
unit, in addition to the market, general economic conditions, quality of
management, strategic plans, and regulatory agencies.
In general, the current merit/base pay system provides individual pay
opportunities that are competitive in our respective industry and geographic
location coupled with each company's ability to pay. The emphasis of the
Results Compensation program is on rewarding group or business unit performance.
Results Compensation Program Objectives
The Results Compensation program is designed to meet the following objectives:
* Enhance and broaden the current compensation philosophy and pay
practice.
* Share the results of the Corporation and the business unit with
the people who contribute to that success.
* Motivate work performance and behavior that supports the Corporate
and business unit financial goals.
* Increase the employee's understanding of the business.
<PAGE>
Results Compensation Guidelines
* The program encompasses a one-year period; January 1, 1995, through
December 31, 1995. Results Compensation awards, if approved, will be
paid out in the first quarter of the following year.
* Regular full-time and regular part-time employees are eligible to
participate in this program.
* An individual employee's Results Compensation award, if any, will
be paid on gross pay as it appears on the employee's W-2 form.
This includes regular, overtime, paid time off and other forms of
premium pay.
* An employee who transfers between one of the three participating
companies (BHP, WRDC, WPC) during the program year will have the
Results Compensation award, if approved, based upon where the
greatest amount of time worked occurred.
* The local union IBEW, 1250, elected not to participate in the 1994
Results Compensation program. It is unknown at this time if they
will elect to participate in the 1995 program.
* If the bargaining unit does not participate, an employee who
transfers to or from a bargaining unit position will receive a
pro-rated Results Compensation award, if approved, relative to the
amount of time worked in the non-bargaining unit position and
gross pay earned in the non-bargaining unit position.
* The maximum Results Compensation bonus and award an employee may
receive is 8 percent.
* In determining the bonus percentage to be paid, calculations will
be rounded to two decimal places (e.g., 1.43%) not rounded to the
nearest whole percentage amount.
* Any participating employee whose employment relationship with the
Corporation is terminated voluntarily or involuntarily prior to
the end of the program year will not be eligible for any Results
Compensation award. Exceptions would be death, permanent
disability or retirement.
<PAGE>
Determining Results Compensation Awards
The Results Compensation program has two key financial goals. The financial
goals consist of a business unit goal and a corporate goal. Whether a
program award is paid and how much any award will be depends on how well and
to what degree the goals were obtained as evaluated by the Board of Directors.
Goal 1. Financial performance of the individual business unit (BHP,
WRDC and WPC) based on operating income.
Operating income is all unit revenue, less operating expense, before
corporate income taxes and interest charges. This measures the
financial results of operations.
Participants can receive up to four percent of their total Results
Compensation award from this goal; specifics are attached. Specific
goals will be determined and communicated to each employee of the
respective business unit upon finalization of the budget process.
Goal 2. Corporate consolidated earnings per share (EPS) goal.
Earnings per share are equal to the total profit divided by the number
of shares of Black Hills Corporation common stock owned by shareholders.
Participants can receive up to four percent of their total Results
Compensation award from the goal. Since this is a consolidated Corp-
orate goal, all employees in the different business units will have the
same goal; specifics are attached. The specific goal will be determined
and communicated to each employee upon finalization of the budget
process.
<PAGE>
Board of Directors Retain Discretion
This program is not at any time a contract of employment. The Company
reserves the right to change this program whenever and in any manner it deems
appropriate. Irrespective of changes in the program, no rights are vested.
All awards are earned only when and if finally approved by the Board of
Directors notwithstanding anything contained in the program that may be
construed to be to the contrary.
The Board of Directors, in its sole and absolute discretion, may decline to
approve any award, though the participant may have achieved or exceeded
threshold and target levels of performance. Setting a threshold or target of
performance for any participants does not constitute a promise to pay an
award even if the participant meets the threshold or target of performance.
In determining whether to make an award and the amount of the award, the
Board of Directors may consider criteria other than or in addition to the
threshold and target performance determined under this program. Nothing in this
program is a promise by the Corporation to continue to employ any participant
for any period of time.
EXHIBIT 13
FINANCIAL DIRECTORY
Management's Discussion and Analysis of
Financial Condition and Results of
Operations . . . . . . . . . . . . . . . .12
Report of Management . . . . . . . . . . . .19
Report of Independent Public Accountants . .19
Consolidated Statements of Income . . . . .20
Consolidated Statements of Retained
Earnings . . . . . . . . . . . . . . . . .20
Consolidated Statements of Cash Flows. . . .21
Consolidated Balance Sheets . . . . . . . .22
Consolidated Statements of Capitalization .23
Notes to Consolidated Financial Statements .24
Financial Statistics . . . . . . . . . . . .30
Electric Operation Statistics . . . . . . .31
Investor Information . . . . . . . . . . . .32
<PAGE>
Management's Discussion and Analysis
of Financial Condition and Results of Operations
Black Hills Corporation (the Company) is an energy services company
primarily consisting of three principal businesses: electric, coal mining,
and oil and gas production. Under the assumed name of Black Hills Power and
Light Company, the Company provides electric service to customers in the
states of South Dakota, Wyoming, and Montana; Wyodak Resources Development
Corp. (WRDC) mines and sells coal via long-term contracts; and Western
Production Company (WPC) explores and produces oil and gas.
Liquidity and Capital Resources
The Company generated cash from operations sufficient to meet operating
needs, pay dividends on common stock and finance a portion of capital
requirements. Except for the Company's current construction of Neil Simpson
Unit #2 (NSS #2), a new power plant, property additions from 1992 through
1994 were primarily for the replacement of equipment, modernization of
facilities, and for oil and gas investments. The primary capital
requirements of the Company for the past three years were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Construction of NSS #2 $73,984 $12,792 $ 2,227
Other electric property
additions 14,187 13,140 15,507
Coal mining additions 5,911 7,425 5,001
Oil and gas investments 8,977 6,933 5,180
Common stock dividends 18,920 17,720 16,977
Maturities and redemptions
of long-term debt 3,542 4,166 3,725
-------- ------- -------
$125,521 $62,176 $48,617
</TABLE>
Capital requirements for projected construction, capital improvements,
and oil and gas investments are estimated to be as follows:
<TABLE>
<CAPTION>
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
NSS #2 $31,100 $ - $ -
Other electric 13,200 15,000 14,500
Coal mining 1,700 2,500 1,100
Oil and gas 9,500 6,000 6,000
------- ------- -------
$55,500 $23,500 $21,600
</TABLE>
Major capital expenditures forecasted for the electric operations
include the completion of NSS #2 in 1995 (See Construction of Neil Simpson
Unit #2). The coal mining operations forecasted expenditures include the
replacement of mining equipment. Forecasted expenditures for the oil and
gas operations is dependent upon future cash flows and include an active
development and exploratory drilling program and acquisition of existing
producing properties. WYGEN, Inc., a newly formed subsidiary in 1994, does
not currently have any forecasted capital expenditures. WYGEN was formed as
an exempt wholesale generator and will not incur substantial costs until and
unless long-term power sale contracts are obtained.
Long-term debt and sinking fund requirements are as follows:
<TABLE>
<CAPTION>
1995 1996 1997
(in thousands)
<S> <C> <C> <C>
Electric $2,136 $2,255 $2,384
Coal mining 8 - -
------ ------ ------
$2,144 $2,255 $2,384
</TABLE>
Under its mining permit, WRDC is required to reclaim all land where it
has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual
basis, much of the reclamation occurs over an extended period after the area
is mined. Approximately $600,000 is charged to operations as reclamation
expense annually. As of December 31, 1994, accrued reclamation costs were
approximately $7,600,000.
The Company's capitalization for the three years ended December 31 was
as follows:
<TABLE>
<CAPTION>
1994 1993 1992
<S> <C> <C> <C>
Long-term debt 42% 34% 37%
Common equity 58 66 63
--- --- ---
100% 100% 100%
</TABLE>
The Company sold 525,000 shares of Common Stock, $1 par value, at a
price of $25-3/8 per share in 1993 through a public stock offering.
Proceeds from the sale were used to finance NSS #2. Net proceeds from the
sale were approximately $12,700,000.
The Company revised its Dividend Reinvestment and Stock Purchase Plan
in 1993, under which shareholders may purchase additional shares of Common
Stock through dividend reinvestment or optional cash payments at 100 percent
of the recent average market price. The Company has the option of issuing
new shares or purchasing the shares on the open market. The Company issued
112,578 new shares under the Plan in 1994 and 26,891 shares in 1993.
Proceeds from the sale of new shares were used to finance capital
expenditures.
The Company filed a Form S-3, shelf registration in 1994 for
$100,000,000 first mortgage bonds. The Company issued $45,000,000 first
mortgage bonds under this filing on September 1, 1994. The bonds have a 30
year life and carry an 8.3 percent rate of interest. The Company issued
$3,000,000 Environmental Improvement Revenue Bonds in 1994. The
environmental bonds carry a variable rate of interest which is currently
reset weekly. The average interest rate applied to the bonds in 1994 was
3.5 percent. The environmental bonds are structured so that the Company can
determine from time to time whether to cause them to be remarketed
periodically on a short-term or long-term basis. The ability to continue
the environmental bonds on a short-term basis to take advantage of lower
interest rates depends on the ability to continue to remarket the bonds.
Proceeds from both bond issues were used to finance NSS #2. These
additional financings increased the debt component of the Company's capital
structure from 34 percent at December 31, 1993 to 42 percent at December 31,
1994.
The Company also completed the refinancing of the $12,200,000, City of
Gillette Pollution Control Revenue Bonds during 1994. During 1992 the
Company entered into a forward refunding agreement on the $12,200,000, 10.5
percent, City of Gillette Pollution Control Revenue Bonds. The new bonds
were issued in July 1994 at 7.5 percent and the Series 1984 bonds were
called and redeemed on August 1, 1994 at 102 percent of par.
Subsequent to year-end, the Company issued $30,000,000 first mortgage
bonds under the shelf registration. The bonds have a 15 year life and carry
an 8.06 percent rate of interest. The bondholders have a one-time option to
cause the Company to redeem the bonds at par on February 1, 2002. Management
believes that this issue will complete the long-term debt financing
associated with NSS #2. The remaining expenditures related to the project
will be financed by existing cash balances, short-term investments, and
short-term lines of credit. (See Construction of Neil Simpson Unit #2).
The Company issued $12,300,000, 6.7 percent, Pollution Control Revenue
Refunding Bonds in 1992 to redeem $12,300,000 Pollution Control and
Industrial Revenue Bonds which were collateralized by first mortgage bonds.
The refunding bonds have no sinking fund requirements and mature in 2010.
The refunding bonds are not secured under the Company's Indenture of
Mortgage.
At December 31, 1994, the Company had $70,000,000 of unsecured short-
term lines of credit which provides for interim borrowings and the
opportunity for timing of permanent financing. Borrowings outstanding under
these lines of credit were $36,975,000 and $11,700,000 as of December 31,
1994 and 1993, respectively. The weighted average interest rate on these
borrowings at December 31, 1994 and 1993 was 6.9 percent and 4.5 percent,
respectively. Average borrowings during 1994, 1993, and 1992 were
$21,070,000, $11,059,000, and $5,616,000, respectively. The increase in
borrowings was directly related to the financing of the construction of NSS
#2. There are no compensating balance requirements associated with these
lines of credit. The Company pays a 0.125 percent facility fee on
$25,000,000 of the existing short-term lines.
In the past the Company has depended upon internally generated funds,
issuance of short and long-term debt, and sales of common stock to finance
its activities.
Credit ratings for the Company's First Mortgage Bonds remained at an A1
level at Moody's Investors Service, Inc. and a 5 (High Single A) at Duff &
Phelps, Inc. in 1994. Standard & Poor's reduced the Company's rating from
an A+ level with a negative outlook in 1993 to an A level with negative
outlook in 1994. These ratings reflect the opinion of the respective
agencies as to the credit quality of the Company's bonds. Standard & Poor's
stated that the downgrade was issued to reflect a burdensome construction
program which will pressure financial results and require supportive rate
treatment to maintain current credit worthiness. They stated the negative
outlook would be removed if the Company receives favorable rate orders on
NSS #2.
(TABLE IN ANNUAL REPORT)
<TABLE>
<CAPTION>
COMMON STOCK DATA
1994 1993 1992
<S> <C> <C> <C>
Net Income $23,805,000 $22,946,000 $23,638,000
Earnings Per Average Share $1.66 $1.66 $1.73
Weighted Average Shares
Outstanding 14,339,095 13,810,912 13,689,105
Dividends Paid Per Share $1.32 $1.28 $1.24
Five-Year Dividend Growth
Rate 5.5% 6.6% 8.4%
Payout Ratio 79.5% 77.1% 71.7%
Book Value $12.19 $11.78 $10.89
Year-end Stock Price $21.38 $22.75 $27.50
Dividend Yield on
Market Value 6.2% 5.6% 4.5%
Price Earnings Ratio 13 14 16
Return on Common Equity
at Year-end 13.6% 13.7% 15.8%
</TABLE>
Construction of Neil Simpson Unit #2
Construction of NSS #2, an 80 MW coal fired generating plant located
adjacent to WRDC's coal mine, commenced in August 1993. Construction of NSS
#2 is proceeding ahead of schedule and costs incurred to date are under the
initial project budget. The construction costs of the plant are currently
budgeted at $121,000,000. NSS #2 will increase net utility plant by more
than 50 percent. Commercial operation is currently estimated to begin in
September 1995. Purchased power is utilized by the Company in the interim
to meet load growth not satisfied by existing resources. As of December 31,
1994, the Company has incurred approximately $89,000,000 of costs related to
the plant. NSS #2 will be fueled by coal from WRDC's mine. The coal
pricing methodology is not expected to increase earnings on coal sales to
the Company because of the Company's agreement to limit coal payments to a
return on its affiliate's investment base. Earnings on coal sales to the
Company could be further limited because the Company has agreed to further
discount the price of coal during a period of time that under prudent
dispatch that power plant would not have been operated if it were not for
the discounted price of coal.
The Company guaranteed to the South Dakota Public Utilities Commission
and the Wyoming Public Service Commission that the Company will never
include in rate base for the determination of electric rates any initial
capital costs of NSS #2 that exceed $124,889,000, including allowance for
funds used during construction. Due to the guarantee, the Company would
likely be forced to write off against earnings any construction costs of NSS
#2 in excess of the guaranteed costs except to the extent that those costs
could be recovered through performance guarantees and damage provisions in
the contracts with the vendors and contractors. Management believes that
the cost of the project will not exceed the amount of the guarantee.
(CHART IN ANNUAL REPORT)
CONSOLIDATED DEBT RATIOS (in percent)
1994 42.4
1993 33.7
1992 37.3
1991 39.6
1990 36.9
1989 38.3
MDU Power Sale
During 1994, the Company entered into a Power Integration Agreement
with Montana-Dakota Utilities Co. (MDU), a division of MDU Resources Group,
Inc. The market-based agreement provides that for a period of 10 years
commencing January 1, 1997, the Company will supply up to 55 MW of the
electric power and energy required by MDU for its electric service area in
and around Sheridan, Wyoming. MDU's Sheridan service area has experienced a
45 MW peak and a load factor of approximately 60 percent. The agreement is
subject to the approval of the Federal Energy Regulatory Commission.
The agreement further provides that the Company and MDU will share
equal ownership in a combustion turbine of approximately 70 MW to be
constructed at such time as the Company determines a new peaking resource is
required. Both companies will receive the benefit of lower unit costs from
a turbine that will be larger than either company could justify on its own.
Rate Applications
On February 1, 1995 the Company filed an application with the South
Dakota Public Utilities Commission requesting authority to increase rates by
an average of 9.96 percent with the condition that rates will not be reduced
when the benefits of the MDU Power Sale are realized commencing January 1,
1997. The Company has requested that the rate increase become effective
when NSS #2 begins commercial operation. The Company plans to file an
application for a rate increase with the Wyoming Public Service Commission
in March 1995.
The Company is seeking a negotiated increase in rates with its only
wholesale customer, the City of Gillette, Wyoming. A tentative agreement
with Gillette, subject to final approval of the parties and the Federal
Energy Regulatory Commission, has been reached that will result an effective
rate increase of 12.3 percent when NSS #2 becomes commercial and reduced to
8.8 percent on January 1, 1997 when the MDU Power Sale becomes effective.
Competition
Management believes the Company's electric rates after the rate
increase will remain favorably competitive with most rural electric
cooperatives serving adjacent to the Company's service territory. However,
this could be affected by many factors beyond the control of the Company.
The electric utility industry can be expected to become increasingly
competitive, due to a variety of regulatory, economic, and technological
changes. The increasing level of competition is being fostered, in part, by
the enactment of the National Energy Policy Act (NEPA) of 1992. NEPA
encourages competition by allowing both utilities and non-utilities to form
non-regulated generation subsidiaries without being restricted by the Public
Utility Holding Company Act of 1935. As a result of competition in electric
generation, wholesale power markets have become increasingly competitive.
Although NEPA specifically bans federal-mandated wheeling of power for
retail customers, several state public utility regulatory commissions are
currently studying retail wheeling. None of the utility commissions in the
Company's service territory have instituted proceedings on retail wheeling
at this time. With the passage of NEPA and the advent of a more competitive
electric utility environment, the Company continues to review its strategic
plan and implement changes to increase its competitiveness.
To assist in the planning for new resources and to minimize the risk of
loss of large loads, the Company endeavors 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 from the Company. The South Dakota
State Cement Plant is under a similar 5-year contract and the City of
Gillette is under a 17-year contract for 23 MW of its base load. These
three customers in 1994 accounted for 29 percent of the Company's total firm
kilowatthour sales and 20 percent of firm electric sales revenue.
Results of Operations:
Consolidated Results
Consolidated net income for 1994 was $23,805,000 compared to
$22,946,000 in 1993 and $23,638,000 in 1992 or $1.66 per average common
share in 1994 and 1993 and $1.73 per average common share in 1992. This
equates to a 13.6 percent return on year-end common equity in 1994, 13.7
percent in 1993, and 15.8 percent in 1992. The Company recognized a non-
recurring $940,000 after-tax non-cash gain in 1992 related to the PacifiCorp
Settlement (see PacifiCorp Settlement) which was equivalent to $0.07 per
share. Without this gain, earnings per share would have been flat for the
three year period with 4 percent and 1 percent more average common shares
outstanding in 1994 and 1993, respectively. Consolidated net income for
1994 includes non-cash earnings of $2,371,000 for allowance for equity funds
used during construction.
Consolidated revenue and income provided by the three businesses as a
percentage of the total were as follows:
<TABLE>
<CAPTION>
Revenue
<C> <S> <S> <S>
1994 1993 1992
Electric 72% 71% 72%
Coal mining 20 21 21
Oil and gas 8 8 7
--- --- ---
100% 100% 100%
Net Income
Electric 54% 49% 47%
Coal mining 41 46 49
Oil and gas 5 5 4
--- --- ---
100% 100% 100%
</TABLE>
Dividends paid on common stock totaled $1.32 per share in 1994. This
reflected increases approved by the Board of Directors from $1.28 per share
in 1993 and $1.24 per share in 1992. Dividends have increased at a 4.1
percent average annual compound growth rate over the last three years. All
dividends were paid out of current earnings.
In January 1995 the Board of Directors increased the quarterly dividend
1.5 percent to 33.5 cents per share. If this dividend is maintained during
1995, the increase will be equivalent to an annual increase of 2 cents per
share.
Wyodak Plant Maintenance Schedule
The Wyodak Plant was out of operation for five weeks in 1994 for
scheduled maintenance. Fiscal 1993 and 1992 represent whole years of
operations from the Wyodak Plant. When the Wyodak Plant is out of service,
replacement power is provided from purchased power and increased generation
from the Company's other generating plants. Additional purchased power
costs are recovered by the utility through the fuel adjustment clauses. The
loss of coal sales to the Wyodak Plant is partially mitigated through
greater coal sales to the Company's other generating plants and reduced
operating costs.
(CHART IN ANNUAL REPORT)
FIRM ELECTRIC SALES (Millions of Kwh)
1994 1,638
1993 1,594
1992 1,540
1991 1,532
1990 1,479
PacifiCorp Settlement
In 1987 WRDC and the Company entered into settlement agreements with
PacifiCorp canceling PacifiCorp's obligation to purchase coal commencing in
1990 for a second plant scheduled to be constructed adjacent to the Wyodak
Plant but which had been canceled, and settling a dispute over the quantity
of coal PacifiCorp was required to purchase to operate the Wyodak Plant.
This settlement resulted in an increase in the Company's net income in 1994,
1993, and 1992 of approximately $1,700,000, $1,500,000, and $2,800,000 or
$0.12, $0.11, and $0.20 per share of common stock, respectively. The
settlement provided for, among other things, payments to WRDC of $2,000,000
each on January 2, 1988 through 1991 for an option to purchase 50,000,000
tons of coal if PacifiCorp should construct a second Wyodak power plant and
required PacifiCorp to pay up to $15,000,000, such amount to be adjusted for
inflation and deflation, for the cost of new coal handling facilities.
Construction of the coal handling facilities commenced in 1992 and was
completed in 1994. As a result of a definitive agreement entered into with
PacifiCorp in 1992 regarding the construction of these facilities, the
Company recognized a non-recurring $940,000 after-tax non-cash gain in 1992.
The gain was due to the assumption by PacifiCorp of certain liabilities
related to the existing coal handling facilities that were replaced by the
construction of the new facilities. Other benefits from the PacifiCorp
Settlement will continue to have a positive effect on earnings for the life
of the agreements. The exact amount of earnings each year will depend
largely upon the continued successful operation of the Wyodak Plant.
<TABLE>
<CAPTION>
Electric Operations
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Revenue $104,756 $98,155 $97,448
Operating expenses 79,680 74,173 74,056
-------- ------- -------
Operating income $ 25,076 $23,982 $23,392
======== ======= =======
Net income $ 12,852 $11,171 $11,041
======== ======= =======
</TABLE>
Electric revenue increased 6.7 percent in 1994 compared to a 0.7
percent increase in 1993 and a 0.7 percent decrease in 1992. Firm
kilowatthour sales increased 2.7 percent in 1994 compared to a 3.5 percent
increase in 1993 and a 0.5 percent increase in 1992 and have averaged an
annual 2.2 percent growth rate over the last three years. Sales growth in
1992 was reduced by mild weather conditions.
The increase in revenue in 1994 was due to the 2.7 percent increase in
firm kilowatthour sales and an increase in the fuel and purchased power
adjustment passed on to electric customers. The increase in purchased power
costs was primarily due to replacement power purchased while the Wyodak
Plant was down for maintenance.
The revenue increase in 1993 from additional electric sales was offset
by a decrease in the fuel and purchased power adjustment passed on to
electric customers. The decrease in the purchased power adjustment passed
on to electric customers was due to a $2,000,000 refund received from
PacifiCorp on the 40-year power purchase agreement. Homestake Mining
Company, the Company's largest customer, reduced its energy usage by 22,000
megawatt hours in 1993 by concentrating on more efficient production areas.
Revenue decreased in 1992 due to a decrease in the fuel and purchased
power adjustment passed on to electric customers. This decrease was a
result of a $600,000 increase in the refund accrued for the limitation on
the return allowed on WRDC coal sales to the Company's power plants and a
$600,000 decrease in fuel and purchased power expense. Purchased power
decreased in 1992 compared to 1991 due to a full year of operations at the
Wyodak Plant.
In South Dakota the Company may not include in rates any cost of coal
which allows WRDC to earn a return on equity on sales of coal to the
Company's utility operations in excess of a percentage equal to the rate on
long-term "A" rated utility bonds plus 400 basis points (4 percent). The
investment base on which the return is calculated includes all of WRDC's
investment base except for investments in subsidiary companies and other
non-mining interests. The maximum return on equity to be applied in 1995
for the 1994 adjustment will be approximately 12.3 percent. The returns
applied for the 1993 and 1992 adjustments were 11.6 percent and 12.7
percent, respectively. The Company has recorded an accrual for the 1995
refund for sales in 1994 of approximately $760,000. The 1994 and 1993
refunds were approximately $1,061,000 and $1,538,000, respectively. Tons of
WRDC's coal sold to the Company represent approximately 33 percent of its
total coal sales. The refund decreased in 1994 primarily due to the
increase in long-term "A" rated utility bond interest rates.
The decrease in the allowed return in 1993 was offset by an increase in
WRDC's investment base primarily due to its investment in an electric shovel
and new coal conveying facilities.
Revenue per kilowatt sold was 6.1 cents in 1994 up from 5.9 cents in
1993 and 6.0 cents in 1992. The number of customers in the service area
increased to 53,959 in 1994 from 53,330 in 1993 and 52,535 in 1992. The
increase in revenue per kilowatthour sold in 1994 was due to the increase in
purchased power cost related to replacement power purchased during the
Wyodak Plant maintenance period.
Operating expenses increased substantially in 1994 due to the increase
in purchased power costs, remained relatively flat in 1993 compared to 1992
as a result of the $2,000,000 purchased power refund, and increased 0.7
percent in 1992.
(CHART IN ANNUAL REPORT)
TONS OF COAL SOLD (thousands of tons)
1994 2,796
1993 3,027
1992 2,958
1991 2,742
1990 2,908
<TABLE>
<CAPTION>
Coal Mining Operations
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Revenue $28,594 $29,822 $28,296
Operating expenses 16,772 17,462 16,724
------- ------- -------
Operating income $11,822 $12,360 $11,572
======= ======= =======
Net income $ 9,873 $10,648 $11,695
======= ======= =======
</TABLE>
Revenue decreased 4.1 percent in 1994 and increased 5.4 percent in 1993
and 8.3 percent in 1992 due to a 7.6 percent decrease and a 2.3 percent and
7.9 percent increase, respectively in tons of coal sold. The decrease in
tons of coal sold in 1994 was caused by the Wyodak Plant being out of
service for five weeks of scheduled maintenance. Operating expenses
decreased 4.0 percent in 1994 reflecting the decrease in tons of coal mined
offset by an increase in depreciation expense. Operating expense increased
4.4 percent in 1993 reflecting an increase in depreciation expense as a
result of an increase in capital investments and higher taxes associated
with increased revenues. Operating expenses remained relatively flat in
1992 caused by a decrease in administrative and general expenses offset by
an increase in coal production.
Non-operating income was $1,763,000 in 1994 compared to $2,226,000 in
1993 and $3,894,000 in 1992. Non-operating income includes the PacifiCorp
Settlement, a coal contract settlement from Grand Island, Nebraska, and
interest income from investments. Non-operating income decreased in 1994
and 1993 due to a decrease in interest income attributable to lower interest
rates and a non-recurring $940,000 after-tax non-cash gain recognized in
1992 related to the PacifiCorp Settlement.
WRDC formed two new subsidiaries during 1994, WYGEN, Inc. and DAKSOFT,
Inc. WYGEN is an exempt wholesale generator as authorized by the National
Energy Policy Act of 1992 and will engage exclusively in the business of
owning or operating eligible electric generating facilities and selling
electricity at wholesale. WYGEN plans to seek an air quality permit to
construct the WYGEN Plant, an 80 MW mine-mouth, coal fired, electric
generating plant, to be constructed next to NSS #2. Construction of the
WYGEN Plant will not commence and WYGEN will not incur substantial costs
until and unless long-term power sale contracts are obtained, justifying the
construction. DAKSOFT, Inc. was formed to develop and market internally
generated computer software associated with the Company's business segments.
Neither company has recorded any revenue as of December 31, 1994, and their
expenses are primarily organizational costs. Because of the immaterial
amount of these costs they have been included with coal mining expenses.
<TABLE>
<CAPTION>
Oil and Gas Production
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Revenue $12,052 $11,396 $9,599
Production expenses 10,196 9,952 8,214
------- ------ ------
Operating income $ 1,856 $1,444 $1,385
======= ====== ======
Net income $ 1,080 $1,127 $ 902
======= ====== ======
</TABLE>
The oil and gas operations have not been a significant percent of the
Company's total operations. Net income and assets related to oil and gas
operations have been 7 percent or less of the Company's consolidated amounts
over the last three years.
Revenue is primarily comprised of oil and gas sales and is supplemented
by field services in eastern Wyoming. Equivalent barrels of oil sold
increased approximately 34 percent to 624,000 barrels in 1994 from 465,000
barrels in 1993 and 315,000 barrels in 1992. The average sales price of oil
per barrel was $15.56 in 1994 compared to $16.69 in 1993 and $19.10 in 1992.
The average sales price per mcf of gas was $1.81 in 1994 compared to $2.31
in 1993 and $1.63 in 1992. WPC's production expenses increased 2.5 percent
in 1994 compared to 21 percent in 1993 and 6.4 percent in 1992. Production
expenses increased primarily due to increased depletion expense as a result
of increased oil and gas production and lower oil and gas prices. WPC
recognized $4,450,000, $3,725,000, and $2,291,000 of depletion expense in
1994, 1993, and 1992, respectively.
Low oil and gas prices reduce the cash flow and value of the Company's
oil and gas assets and will cause the Company to increase its depletion
expense.
WPC's proved reserves, and the revenues generated from production, will
decline as production occurs, except to the extent WPC conducts successful
exploration and development activities or acquires additional proved
reserves. WPC has been in an active exploration and development drilling
program during the past three years. Much of WPC's production growth in
1994 and 1993 was the result of its horizontal drilling program in the
Austin Chalk formation in Texas. WPC intends to increase its net proved
reserves by selectively increasing its oil and gas exploration and
development activities and by acquiring producing properties primarily with
the use of internally generated funds.
WPC's reserves are based on reports prepared by Ralph E. Davis
Associates, Inc. Reserves were determined using constant product prices at
the end of the respective years. Estimates of economically recoverable
reserves and future net revenues are based on a number of variables which
may differ from actual results. WPC's unaudited reserves, principally
proved developed and proved undeveloped properties, were estimated to be
1.4, 1.1, and 2.2 million barrels of oil and 9.1, 2.8, and 3.2 billion cubic
feet of natural gas as of December 31, 1994, 1993, and 1992, respectively.
The increase in reserves as of December 31, 1994, was primarily due to the
active drilling program and a production acquisition in South Texas. The
decrease in the reserves in 1993 was caused by price decreases, production
increases, and engineering revisions. WPC has interests in 410 producing
oil and gas properties in seven states. WPC operates a total of 349 wells
in Wyoming and Colorado. WPC's non-operated properties are located in
Texas, Wyoming, Colorado, North Dakota, Montana, Kansas, and California.
(CHART IN ANNUAL REPORT)
EQUIVALENT BARRELS OF OIL SOLD (thousands of barrels)
1994 624
1993 465
1992 315
1991 262
1990 205
Regulatory Accounting
The Company follows Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation, and its
financial statements reflect the effects of the different ratemaking
principles followed by the various jurisdictions regulating the Company. If
rate recovery of generation-related costs become unlikely or uncertain, due
to competition or regulatory action, these accounting standards may no
longer apply to the Company's generation operations. In the event the
Company determines that it no longer meets the criteria for following SFAS
71, the accounting impact to the Company would be an extraordinary non-cash
charge to operations of an amount that could be material. Criteria that
give rise to the discontinuance of SFAS 71 include increasing competition
that could restrict the Company's ability to establish prices to recover
specific costs and a significant change in the manner in which rates are set
by regulators from cost-based regulation to another form of regulation. The
Company periodically reviews these criteria to ensure the continuing
application of SFAS 71 is appropriate.
Accounting for Certain Investments in Debt and Equity Securities
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115, Accounting for Certain Investments in Debt and
Equity Securities, which requires a change in accounting from cost to fair
value. Under the fair value method, investments are classified in three
categories: held to maturity securities, which are reported at amortized
cost; trading securities, which are reported at fair value, with unrealized
gains and losses included in earnings; available-for-sale securities, which
are reported at fair value, with unrealized gains and losses reported as a
separate component of shareholder's investment, net of income taxes.
At December 31, 1994, the Company's short-term and other investments
were classified as held-to-maturity securities and were reported at
amortized cost.
Employers' Accounting for Postretirement Benefits Other than Pensions
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions. This new standard requires that the expected
cost of these benefits must be accrued for during the years employees render
service. The Company prospectively adopted the new standard effective
January 1, 1993, and is amortizing the discounted present value of the
accumulated postretirement benefit obligation of $2,996,000 to expense over
a 20 year period. The net periodic postretirement cost charged to expense
in 1994 and 1993 was $669,000 and $527,000 (pre-tax), respectively. For
measurement purposes, an 11 percent annual rate of increase in healthcare
benefits was assumed for 1995; the rate was assumed to decrease gradually to
6 percent in 2005 and remain at that level thereafter. The healthcare cost
trend rate assumption has a significant effect on the amount reported. A 1
percent increase in the health care cost trend assumption would increase the
net periodic postretirement benefit cost by approximately $192,000 annually
or 22.5 percent.
The South Dakota Public Utilities Commission has continued to treat
postretirement benefits on a "pay as you go" basis for rate making purposes.
Accounting for Income Taxes
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, which requires
the use of the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between
the financial reporting and tax basis of assets and liabilities. Such
temporary differences are the result of provisions in the income tax law
that either require or permit certain items to be reported on the income tax
return in a different period than they are reported in the financial
Statements. The new standard required adjustments to existing balances of
accumulated deferred income taxes to reflect changes in income tax rates.
To the extent such income taxes are recoverable or payable through future
rates, a $6,925,000 net regulatory liability has been recorded in the
accompanying consolidated balance sheets. Initial application of the
statement had no material impact on the Company's results of operations.
Inflation
Inflation may have a significant impact on replacement of property and
capital improvements in the future due to the capital intensive nature of
the utility business. The rate making process gives no recognition to the
fair value of existing plant; however, in the past, the Company has been
allowed to recover and earn on the increased cost of its net investment when
the addition to or replacement of facilities occurred. The majority of the
mining operations' coal contracts provide for the adjustment over time of
components of the sales price through indexes, formulas, or direct
pass-through of costs.
<PAGE>
REPORT OF MANAGEMENT
Management of Black Hills Corporation is responsible for the
preparation, integrity, and objectivity of the consolidated financial
statements of the Company and its subsidiaries. The consolidated financial
statements are prepared in conformity with generally accepted accounting
principles and reflect management's informed judgments and best estimates
incorporating accounting policies that are reasonable and prudent for the
Company's business environment. Information contained elsewhere in the
Annual Report is consistent with the consolidated financial statements.
The Company's system of internal controls is designed to provide
reasonable assurance, on a cost-effective basis, that assets are
safeguarded, transactions are executed in accordance with management's
authorization, and the consolidated financial statements are prepared in
accordance with generally accepted accounting principles. The internal
controls are continually reviewed and evaluated for effectiveness. No
internal control system can prevent the occurrence of errors and
irregularities with absolute assurance due to the inherent limitations of
any system.
The Audit Committee, composed exclusively of outside directors, is
responsible for overseeing the Company's financial reporting process and
reporting the results of its activities to the Board of Directors. This
committee, management, and the internal auditor periodically review matters
associated with financial reporting, audit activities, and internal
controls. As part of their audit of the Company's 1994 consolidated
financial statements, the Company's independent auditors, Arthur Andersen
LLP, considered the Company's system of internal controls to the extent they
deemed necessary to determine the nature, timing, and extent of their audit
tests. The independent and internal auditors have free access to the Audit
Committee to discuss the results of their audits without the presence of
management.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Black Hills Corporation:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of BLACK HILLS CORPORATION AND SUBSIDIARIES as
of December 31, 1994 and 1993, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 1994. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Black Hills
Corporation and Subsidiaries as of December 31, 1994 and 1993, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1994, in conformity with generally accepted
accounting principles.
As discussed in Notes 8 and 9 to the consolidated financial statements,
effective January 1, 1993, the Company changed its method of accounting for
postretirement benefits other than pensions and its method of accounting for
income taxes.
ARTHUR ANDERSEN LLP
Minneapolis, Minnesota,
January 27, 1995
<PAGE>
<TABLE>
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
Years ended December 31 1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Operating revenues:
Electric . . . . . . . . . . . . . $104,756 $ 98,155 $ 97,448
Coal mining . . . . . . . . . . . 28,594 29,822 28,296
Oil and gas . . . . . . . . . . . 12,052 11,396 9,599
------- ------- -------
145,402 139,373 135,343
------- ------- -------
Operating expenses:
Fuel and purchased power . . . . . 41,970 36,946 38,209
Operations and maintenance . . . . 28,713 30,237 29,850
Administrative and general . . . . 7,921 8,144 7,811
Depreciation, depletion, and
amortization . . . . . . . . . . 17,676 16,051 13,860
Taxes, other than income
taxes (Note 12) . . . . . . . . . 10,368 10,209 9,264
------- ------- -------
106,648 101,587 98,994
------- ------- -------
Operating income:
Electric . . . . . . . . . . . . . 25,076 23,982 23,392
Coal mining . . . . . . . . . . . 11,822 12,360 11,572
Oil and gas . . . . . . . . . . . 1,856 1,444 1,385
------- ------- -------
38,754 37,786 36,349
------- ------- -------
Other income (expense):
Interest expense . . . . . . . . . (10,339) (8,817) (8,965)
Investment income . . . . . . . . 1,631 1,739 3,149
Allowance for funds used during
construction . . . . . . . . . 3,983 729 378
Other, net . . . . . . . . . . . . 171 474 1,233
------- ------- -------
(4,554) (5,875) (4,205)
------- ------- -------
Income before income taxes . . . . . 34,200 31,911 32,144
Income taxes (Note 9) . . . . . . . . (10,395) (8,965) (8,506)
------- ------- -------
Net income . . . . . . . . . . . $ 23,805 $ 22,946 $ 23,638
======= ======= =======
Weighted average common shares
outstanding . . . . . . . . . . . . 14,339 13,811 13,689
Earnings per share of common
stock . . . . . . . . . . . . . . . $ 1.66 $ 1.66 $ 1.73
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
Years ended December 31 1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Balance, beginning of year . . . . . . . . . . $110,399 $105,173 $ 98,512
Net income . . . . . . . . . . . . . . . . . . 23,805 22,946 23,638
Cash dividends on common stock ($1.32,
$1.28, and $1.24 per share, respectively) . . (18,920) (17,720) (16,977)
-------- -------- --------
Balance, end of year . . . . . . . . . . . . . $115,284 $110,399 $105,173
======== ======== ========
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Years ended December 31 1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Operating activities:
Net income . . . . . . . . . . . . . . . . . $ 23,805 $22,946 $23,638
Principal non-cash items-
Depreciation, depletion, and
amortization . . . . . . . . . . . . . . 17,676 16,051 13,860
Deferred income taxes and
investment tax credits. . . . . . . . . . 2,470 1,042 761
Gain on coal settlement . . . . . . . . . . - - (940)
Allowance for other funds used during
construction . . . . . . . . . . . . . . (2,371) (333) (94)
(Increase) decrease in receivables,
inventories, and other current assets . . . (3,438) (1,556) 1,378
Increase (decrease) in current liabilities . 5,054 (2,562) 4,814
Other, net . . . . . . . . . . . . . . . . . 5,740 4,259 1,091
------- ------- -------
48,936 39,847 44,508
------- ------- -------
Investing activities:
Neil Simpson Unit #2 construction costs,
excluding allowance for other funds
used during construction (Note 7) . . . . . (71,956) (12,675) (2,227)
Other property additions, excluding
allowance for other funds used
during construction . . . . . . . . . . . . (28,732) (27,282) (25,594)
Short-term investments purchased . . . . . . (41,923) (33,622) (33,938)
Short-term investments sold . . . . . . . . . 42,006 25,504 32,610
Proceeds from sale of long-term investments . 4,958 14,724 -
------- ------- -------
(95,647) (33,351) (29,149)
------- ------- -------
Financing activities:
Dividends paid . . . . . . . . . . . . . . . (18,920) (17,720) (16,977)
Common stock issued . . . . . . . . . . . . . 2,436 13,705 534
Net short-term borrowings . . . . . . . . . . 25,250 3,784 900
Long-term debt issued . . . . . . . . . . . . 45,795 - -
Long-term debt retired . . . . . . . . . . . (3,542) (4,166) (3,725)
------- ------- -------
51,019 (4,397) (19,268)
------- ------- -------
Increase (decrease) in cash and
cash equivalents. . . . . . . . . . . . . 4,308 2,099 (3,909)
Cash and cash equivalents:
Beginning of year . . . . . . . . . . . . . . 7,866 5,767 9,676
------- ------ ------
End of year . . . . . . . . . . . . . . . . . $ 12,174 $ 7,866 $ 5,767
======= ====== ======
Supplemental disclosure of cash flow
information:
Cash paid during the period for -
Interest . . . . . . . . . . . . . . . . . $ 9,244 $ 9,283 $ 9,296
Income taxes. . . . . . . . . . . . . . . . $ 7,290 $ 8,000 $ 7,440
Non-cash activities (Note 3)
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31 1994 1993
(in thousands)
ASSETS
<S> <C> <C>
Current assets:
Cash and cash equivalents . . . . . . . . $ 12,174 $ 7,866
Short-term investments . . . . . . . . . . 24,134 24,217
Receivables, net
Customers . . . . . . . . . . . . . . . 12,409 12,415
Other . . . . . . . . . . . . . . . . . 4,045 901
Materials, supplies, and fuel . . . . . . 7,139 6,765
Prepaid expenses . . . . . . . . . . . . . 1,564 1,638
------- -------
Total current assets . . . . . . . . 61,465 53,802
------- -------
Property and investments:
Electric . . . . . . . . . . . . . . . . . 425,690 341,852
Coal mining. . . . . . . . . . . . . . . . 52,267 51,670
Oil and gas . . . . . . . . . . . . . . . 38,842 32,371
Investments . . . . . . . . . . . . . . . 2,785 7,250
------- -------
519,584 433,143
Less accumulated depreciation
and depletion. . . . . . . . . . . . . . (156,046) (144,492)
------- -------
Net property and investments. . . . . 363,538 288,651
------- -------
Deferred charges:
Federal income taxes . . . . . . . . . . . 7,505 7,271
Other . . . . . . . . . . . . . . . . . . 4,369 3,129
------- -------
11,874 10,400
------- -------
$436,877 $352,853
======= =======
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of long-term debt. . . . $ 2,144 $ 3,542
Notes payable (Note 4). . . . . . . . . . . 37,018 11,768
Accounts payable . . . . . . . . . . . . . 12,018 9,535
Accrued liabilities-
Taxes . . . . . . . . . . . . . . . . . . 6,331 5,583
Fuel and purchased power refunds . . . . 1,025 1,375
Interest . . . . . . . . . . . . . . . . 2,795 1,700
Other . . . . . . . . . . . . . . . . . . 7,101 6,023
------- -------
Total current liabilities . . . . . . 68,432 39,526
------- -------
Deferred credits:
Federal income taxes . . . . . . . . . . . 39,953 36,705
Investment tax credits . . . . . . . . . . 5,521 6,027
Reclamation costs . . . . . . . . . . . . . 7,618 7,290
Regulatory liability . . . . . . . . . . . 6,925 6,912
Other . . . . . . . . . . . . . . . . . . . 4,093 3,030
------- -------
Total deferred credits . . . . . . . . 64,110 59,964
------- -------
Commitments and contingent liabilities
(Notes 7 and 8) . . . . . . . . . . . . . .
Capitalization, per accompanying statements:
Common stock equity . . . . . . . . . . . . 175,410 168,089
Long-term debt. . . . . . . . . . . . . . . 128,925 85,274
------- -------
Total capitalization . . . . . . . . . 304,335 253,363
------- -------
$436,877 $352,853
======= =======
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated balance sheets.
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
December 31 1994 1993
(in thousands)
<S> <C> <C>
Common stock equity (Note 2):
Common stock, $1 par value; 50,000,000
shares authorized; 14,386,353 and
14,269,580 shares outstanding,
respectively . . . . . . . . . . . . . . . . . $ 14,386 $ 14,270
Additional paid-in capital . . . . . . . . . . . 45,740 43,420
Retained earnings . . . . . . . . . . . . . . . . 115,284 110,399
------- -------
Total common stock equity . . . . . . . . . 175,410 168,089
------- -------
Cumulative preferred stock:
No par value; 400,000 shares authorized;
no shares outstanding . . . . . . . . . . . . . - -
$100 par value; 270,000 shares
authorized; no shares outstanding . . . . . . . - -
Long-term debt (Note 3):
First mortgage bonds-
8.375% due 1998 . . . . . . . . . . . . . . . . 2,675 3,340
8.05% due 1999. . . . . . . . . . . . . . . . . 4,850 4,875
6.625% pollution control and
industrial development revenue
bonds, collateralized with first
mortgage bonds, due 2007 . . . . . . . . . . 1,680 1,840
9.00% due 2003. . . . . . . . . . . . . . . . . 10,561 11,739
9.49% due 2018. . . . . . . . . . . . . . . . . 6,000 6,000
9.35% due 2021. . . . . . . . . . . . . . . . . 35,000 35,000
8.30% due 2024. . . . . . . . . . . . . . . . . 45,000 -
------- -------
105,766 62,794
------- -------
Other-
6.7% pollution control revenue bonds, due 2010 . 12,300 12,300
10.50% pollution control revenue
bonds, due 2014. . . . . . . . . . . . . . . . - 12,200
7.50% pollution control revenue bonds, due 2024. 12,200 -
$3,000,000, variable rate, environmental
improvement bonds, due 2024, less $2,204,832
in construction fund . . . . . . . . . . . . . 795 -
Other long-term obligations . . . . . . . . . . 8 1,522
------- -------
25,303 26,022
------- -------
Total long-term debt 131,069 88,816
Current maturities . . . . . . . . . . . . . . . (2,144) (3,542)
------- -------
Net long-term debt . . . . . . . . . . . . . 128,925 85,274
------- -------
Total capitalization . . . . . . . . . . . . $304,335 $253,363
======= =======
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1994, 1993, and 1992
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation and its Subsidiaries (the Company) operate in three
primary business segments: electric, coal mining, and oil and gas
production. The Company's electric utility operation is engaged in the
generation, purchase, transmission, distribution, and sale of electric power
and energy in western South Dakota, northeastern Wyoming, and southeastern
Montana. Sales of electric power to the three largest electric customers
represented 20 percent of the Company's electric revenue in 1994 and 1993,
and 22 percent in 1992.
The coal mining operation of the Company, located in northeastern Wyoming,
mines and sells sub-bituminous coal primarily under long-term coal supply
agreements. As discussed in Note 6, 70 percent of the coal mining
operation's sales are to the Wyodak Plant. Sales of coal to the Company and
to PacifiCorp represent 89 percent of total coal sales.
The Company's oil and gas exploration and production business operates and
has working interests in oil wells principally located in the Rocky Mountain
region and Texas.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills
Corporation and its wholly owned subsidiaries. All significant inter-
company balances and transactions have been eliminated in consolidation
except for revenues and expenses associated with intercompany coal sales
in accordance with the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation." Total intercompany coal sales not eliminated were $9,445,000,
$10,047,000, and $9,811,000 in 1994, 1993, and 1992, respectively.
Property
Property is recorded at cost which includes an allowance for funds used
during construction where applicable. The cost of electric property
retired, together with removal cost less salvage, is charged to accumulated
depreciation. Repairs and maintenance of property are charged to operations
as incurred.
Depreciation and Depletion
Depreciation is computed using the straight-line method over the estimated
useful lives of the related assets. Depreciation provisions for the
electric property were equivalent to annual composite rates of 3.1 percent
in 1994 and 3.2 percent in 1993 and 1992. Composite depreciation rates for
other property were 10.3 percent, 9.6 percent, and 7.5 percent in 1994,
1993, and 1992, respectively.
Depletion of coal and oil and gas properties is computed using the cost
method for financial reporting and the gross income method or cost method,
whichever is applicable, for federal income tax reporting.
Cash Equivalents and Short-term Investments
Cash of the Company is invested in money market investments such as
municipal put bonds, money market preferreds, commercial paper,
Euro-dollars, and certificates of deposit. The Company considers all highly
liquid investments with an original maturity of three months or less to be
cash equivalents. Cash equivalents and short-term investments are stated at
cost which approximates market.
Revenue Recognition
Revenue from sales of electric energy is based on rates filed with
applicable regulatory authorities. Electric revenue includes an accrual for
estimated unbilled revenue for services provided through year-end.
Revenue from other business segments is recognized at the time the products
are delivered or the services are rendered.
Oil and Gas Exploration
The Company accounts for its oil and gas exploration activities under the
full cost method. Capitalized costs associated with unsuccessful wells are
amortized over future periods as the reserves from successful wells are
produced.
Allowance for Funds Used During Construction
Allowance for funds used during construction (AFDC) represents the
approximate composite cost of borrowed funds and a return on capital used to
finance construction expenditures and is capitalized as a component of the
electric property. The AFDC was computed at an annual composite rate of 8.7
percent in 1994, 7.7 percent in 1993, and 10.5 percent in 1992.
Income Taxes
Deferred taxes are provided on all significant temporary differences,
principally depreciation. Investment tax credits have been deferred in the
electric operation and the accumulated balance is amortized as a reduction
of income tax expense over the useful lives of the related electric property
which gave rise to the credits.
(2) CAPITAL STOCK
Common Stock
Common shares issued at $1.00 par value during the years indicated were:
<TABLE>
<CAPTION>
1994 1993 1992
<S> <C> <C> <C>
Public offering - 525,000 -
Employee Stock
Purchase Plan 4,195 16,402 24,332
Dividend Reinvestment
and Stock Purchase Plan 112,578 26,891 -
------- ------- ------
116,773 568,293 24,332
</TABLE>
At December 31, 1994, 70,014 shares of unissued common stock were available
for future offerings under the Employee Stock Purchase Plan.
The Board of Directors adopted a new Dividend Reinvestment and Stock
Purchase Plan in 1993, under which shareholders may purchase additional
shares of common stock through dividend reinvestment and/or optional cash
payments at 100 percent of the recent average market price. The Company has
the option of issuing new shares or purchasing the shares on the open
market. At December 31, 1994, 860,531 shares of unissued common stock were
available for future offerings under the Plan.
Additional Paid-in Capital
Changes in additional paid-in capital for the years indicated were:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Balance, beginning of year $43,420 $30,284 $29,776
Premium, net of expenses,
received from sales of
common stock 2,320 13,136 508
------ ------ ------
Balance, end of year $45,740 $43,420 $30,284
</TABLE>
(3) LONG-TERM DEBT
Substantially all of the Company's utility property is subject to the lien
of the Indenture securing its first mortgage bonds. First mortgage bonds of
the Company may be issued in amounts limited by property, earnings, and
other provisions of the mortgage indentures.
In 1994 the Company filed a Form S-3, shelf registration for $100,000,000
first mortgage bonds. The Company issued $45,000,000 first mortgage bonds
under this filing on September 1, 1994. The bonds have a 30 year life and
carry an 8.3 percent rate of interest. Subsequent to year-end, the Company
sold an additional $30,000,000 first mortgage bonds under the shelf
registration. The bonds have a 15 year life and carry an 8.06 percent rate
of interest. The Company also issued $3,000,000 Environmental Improvement
Revenue Bonds in 1994. The bonds carry a variable rate of interest which is
currently reset weekly. The average interest rate applied to the bonds in
1994 was 3.5 percent. These bond issues were used to finance Neil Simpson
Unit #2 (NSS #2).
The Company also completed the refinancing of the $12,200,000, City of
Gillette Pollution Control Revenue Bonds during 1994. In 1992 the Company
entered into a forward refunding on the $12,200,000, 10.5 percent, City of
Gillette Pollution Control Revenue Bonds. The new bonds were issued in July
1994 at 7.5 percent, due 2024.
In 1992 the Company issued $12,300,000, 6.7 percent Unsecured Pollution
Control Refunding Revenue Bonds, due 2010. The proceeds were used to redeem
$12,300,000 of 6.625 percent and 6.85 percent, Pollution Control Revenue
Bonds, due 2007.
Scheduled maturities of long-term debt for the next five years are:
$2,144,000 in 1995, $2,255,000 in 1996, $2,384,000 in 1997, $2,196,000 in
1998, and $6,240,000 in 1999.
(4) NOTES PAYABLE TO BANKS
At December 31, 1994, the Company had $70,000,000 of unsecured short-term
lines of credit. Borrowings outstanding under these lines of credit were
$36,975,000 and $11,700,000 as of December 31, 1994 and 1993, respectively.
The weighted average interest rate on these borrowings at December 31, 1994
and 1993 was 6.9 percent and 4.5 percent, respectively. Average borrowings
during 1994, 1993, and 1992 were $21,070,000, $11,059,000, and $5,616,000,
respectively. The Company has no compensating balance requirements
associated with these lines of credit. The Company pays a 0.125 percent
facility fee on $25,000,000 of the existing short-term lines. The lines of
credit are subject to periodic review and renewal during the year by the
banks.
(5) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of the Company's financial instruments.
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of
these instruments.
Short-Term and Other Investments
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 115, Accounting for Certain Investments in
Debt and Equity Securities, which requires a change in accounting for
certain investments from cost to fair value. Under the fair value method,
investments are classified in three categories: held-to-maturity
securities, which are reported at amortized cost; trading securities, which
are reported at fair value, with unrealized gains and losses included in
earnings; available-for-sale securities, which are reported at fair value,
with unrealized gains and losses reported as a separate component of
shareholders' investment, net of income taxes.
At December 31, 1994, all of the Company's short-term and other investments
were classified as held-to-maturity securities under SFAS No. 115, and
reported at amortized cost with $24,134,000 maturing within one year. The
classification of the Company's short-term and other investments by major
security type at December 31, 1994, was as follows:
<TABLE>
<CAPTION>
Net Unrealized
Amortized Cost Fair Value Holding Losses
(in thousands)
<S> <C> <C> <C>
Corporate debt securities $12,197 $12,200 $ 3
Debt securities issued by states
of the United States and
municipalities of the states 12,246 12,222 (24)
------ ------ ---
$24,443 $24,422 $(21)
</TABLE>
Long-Term Debt
The fair value of the Company's long-term debt is estimated based on quoted
market rates for utility debt instruments having similar maturities and
similar debt ratings, with an exception for debt associated with the federal
coal lease modifications. The fair value of the bonus payments for the
federal coal lease modifications equals the discounted future cash flows
using the prime rate as the discount rate. The final federal bonus payment
was made February 1, 1994.
The estimated fair values of the Company's financial instruments are as
follows:
<TABLE>
<CAPTION>
1994
(in thousands)
Carrying Fair
Amount Value
<S> <C> <C>
Cash and cash equivalents $ 12,174 $ 12,174
Short-term investments 24,134 24,114
Other investments 2,785 2,784
Long-term debt 131,069 133,313
</TABLE>
<TABLE>
<CAPTION>
1993
(in thousands)
Carrying Fair
Amount Value
<S> <C> <C>
Cash and cash equivalents $ 7,866 $ 7,866
Short-term investments 24,217 24,217
Other investments 7,250 7,257
Long-term debt 88,816 105,639
</TABLE>
The majority of the Company's outstanding bonds are currently subject to
make-whole provisions which would eliminate any economic benefits for the
Company to call and refinance the bonds.
(6) WYODAK PLANT
The Company owns a 20 percent interest and PacifiCorp an 80 percent interest
in the Wyodak Plant (the Plant), a 330 MW coal-fired electric generating
station located in Campbell County, Wyoming. PacifiCorp is the operator of
the Plant. The Company receives 20 percent of the Plant's capacity and is
committed to pay 20 percent of its additions, replacements, and operating
and maintenance expenses. As of December 31, 1994, the Company's investment
in the Plant included $71,531,000 in electric plant and $20,956,000 in
accumulated depreciation. The Company's share of direct expenses of the
Plant is included in the corresponding categories of operating expenses in
the accompanying consolidated statements of income.
Wyodak Resources Development Corp. (WRDC) supplies coal to the Plant under
an agreement expiring in 2013 with a PacifiCorp option to renew for 10
years. This coal supply agreement is collateralized by a mortgage on and a
security interest in some of WRDC's coal reserves. At December 31, 1994,
approximately 30,292,000 tons were covered under this agreement. WRDC's
sales to the Plant were $20,671,000, $21,438,000, and $20,317,000 for the
years ended December 31, 1994, 1993, and 1992, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
New Power Plant
Construction of NSS #2, an 80 MW coal fired generating plant located
adjacent to the Wyodak coal mine, commenced in August 1993 and is proceeding
ahead of schedule and under the $124,889,000 budget. The Company committed
to the South Dakota Public Utilities Commission and the Wyoming Public
Service Commission to construct NSS #2 at a capital cost not to exceed
$124,889,000 including AFDC and to not include in rate base any capital
costs in excess thereof. On February 1, 1995, the Company filed an
application with the South Dakota Public Utilities Commission requesting
authority to increase rates by an average of 9.96 percent. The Company
requested the increase become effective when NSS #2 begins commercial
operation. Commercial operation is currently estimated to begin in
September 1995. The Company has incurred approximately $89,000,000 of costs
related to the plant as of December 31, 1994.
WRDC has committed to supply all of the coal requirements for the life of
NSS #2. The coal pricing methodology is not expected to have a material
effect on WRDC's earnings because earnings from coal sales to the Company
are limited to a return on WRDC's investment base. WRDC has committed to
further reduce the price for coal to be used in any of the Company's power
plants during a period of time that under prudent dispatch that power plant
would not have been operated if it were not for the discounted price of
coal.
MDU Power Sale
During 1994, the Company entered into a Power Integration Agreement with
Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc. (MDU).
The agreement provides that for a period of 10 years commencing January 1,
1997, the Company will supply up to 55 MW of electric power and associated
energy required by MDU for its Sheridan, Wyoming, service territory. MDU's
Sheridan service area has experienced a 45 MW peak and a load factor of
approximately 60 percent. The agreement is subject to the approval of the
Federal Energy Regulatory Commission.
Coal Obligations
In addition to the 30,292,000 tons of coal reserved under the agreement to
supply coal to the Wyodak Plant, WRDC has reserved 29,075,000 tons of coal
under existing contracts and 51,000,000 tons of coal under future purchase
options. None of the purchase options are expected to be exercised because
the option price is substantially higher than the market price. An option
for 50,000,000 tons can be exercised only if WRDC has not committed the coal
reserves to other buyers prior to the exercise of the option.
PacifiCorp Purchase Power Agreement
In 1983 the Company entered into a 40 year power agreement with PacifiCorp
providing for the purchase of 75 megawatts of electric capacity and energy.
Although the price paid for the capacity and energy is based on the
operating costs of one of PacifiCorp's coal-fired electric generating
plants, PacifiCorp's obligation is to provide power from its system. Costs
incurred under this agreement were $23,132,000, $21,106,000, and $21,507,000
in 1994, 1993, and 1992, respectively.
Reclamation
Under its mining permit, WRDC is required to reclaim all land where it has
mined coal reserves. The cost of reclaiming the land is accrued as the coal
is mined. While the reclamation process takes place on a continual basis,
much of the reclamation occurs over an extended period after the area is
mined. Approximately $600,000 is charged to operations as reclamation
expense annually. As of December 31, 1994, accrued reclamation costs were
approximately $7,600,000.
Other
The Company is subject to various legal proceedings and claims which arise
in the ordinary course of operations. In the opinion of management, the
amount of liability, if any, with respect to these actions would not
materially affect the consolidated financial position or results of
operations of the Company.
(8) EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the Plan) covering
substantially all employees. The benefits are based on years of service and
compensation levels during the highest five consecutive years of the last
ten years of service. The Company's funding policy is in accordance with
the federal government's funding requirements. The Plan's assets consist
primarily of equity securities and cash equivalents.
<PAGE>
Net pension expense (income) for the Plan was as follows:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Service cost $ 865 $ 651 $ 535
Interest cost 2,074 1,899 1,687
Return on assets:
Actual (1,819) (2,852) (2,224)
Deferred (793) 333 (215)
------ ------ ------
Net pension expense (income) $ 327 $ 31 $ (217)
</TABLE>
Funding information for the Plan as of October 1 of each year was as
follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Fair value of plan
assets $25,584 $25,186
Projected benefit
obligation 27,931 28,367
------ ------
(2,347) (3,181)
Unrecognized:
Net loss 2,747 3,779
Prior service cost 885 1,105
Transition asset (541) (631)
------ ------
Prepaid pension cost $ 744 $ 1,072
====== ======
Accumulated benefit
obligation $22,649 $22,464
Vested benefit obligation $21,749 $21,507
Actuarial assumptions:
Discount rate 8.0% 7.5%
Expected long-term rate of
return on assets 10.5% 11%
Rate of increase in
compensation levels 5% 5%
</TABLE>
The change in the assumed discount rate from 7.5 percent in 1993 to 8.0
percent in 1994 resulted in a decrease in the accumulated benefit obligation
and projected benefit obligation of $1,260,000 and $2,086,000, respectively.
The Company has various supplemental retirement plans for outside directors
and key executives of the Company. The plans are nonqualified defined
benefit plans. Costs incurred under the plans were $401,000, $633,000, and
$735,000 in 1994, 1993, and 1992, respectively.
On January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions. The new standard requires that the expected cost of these
benefits must be charged to expense during the years that the employees
render service. Prior to adopting the standard the Company expensed these
benefits as they were paid. The Company is amortizing the transition
obligation of $2,996,000 over a 20 year period.
Employees retiring from the Company on or after attaining age 55 who have
rendered at least five years of service to the Company are entitled to
postretirement healthcare benefits coverage. These benefits are subject to
premiums, deductibles, copayment provisions, and other limitations. The
Company may amend or change the plan periodically. The Company is not pre-
funding its retiree medical plan.
The net periodic postretirement cost for the Company was as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Service cost $188 $127
Interest cost 303 250
Amortization of transition
obligation 150 150
Amortization of loss 28 -
--- ---
Net periodic postretirement
benefit cost $669 $527
</TABLE>
Funding information as of October 1 was as follows:
<TABLE>
<CAPTION>
1994 1993
(in thousands)
<S> <C> <C>
Accumulated postretirement benefit
obligation:
Retirees $1,805 $1,316
Fully eligible active participants 1,246 865
Other active participants 2,400 1,921
Unfunded accumulated postretirement
benefit obligation 5,451 4,102
Unrecognized net loss (1,838) (892)
Unrecognized transition obligation (2,696) (2,846)
----- -----
Accrued postretirement benefit cost $ 917 $ 364
</TABLE>
For measurement purposes, an 11 percent annual rate of increase in
healthcare benefits was assumed for 1995; the rate was assumed to decrease
gradually to 6 percent in 2005 and remain at that level thereafter. The
healthcare cost trend rate assumption has a significant effect on the
amounts reported. A 1 percent increase in the healthcare cost trend
assumption would increase the net periodic postretirement cost by
approximately $192,000 annually or 22.5 percent. The weighted-average
discount rate used in determining the accumulated postretirement benefit
obligation was 8 percent.
(9) INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, which requires
the use of the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between
the financial reporting and tax basis of assets and liabilities. Such
temporary differences are the result of provisions in the income tax law
that either require or permit certain items to be reported on the income tax
return in a different period than they are reported in the financial
statements. To implement the statement, certain adjustments were made to
accumulated deferred income taxes. To the extent such income taxes are
recoverable or payable through future rates, regulatory assets and
liabilities have been recorded in the accompanying consolidated balance
sheets. Initial application of the statement had no material impact on the
Company's results of operations.
Income tax expense for the years indicated was:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Current $ 7,925 $7,923 $7,745
Deferred 2,975 1,547 1,273
Investment tax credits, net (505) (505) (512)
------ ----- -----
$10,395 $8,965 $8,506
</TABLE>
The sources of temporary differences and the tax effect of each are
summarized as follows:
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Tax in excess of book depreciation $1,885 $ 662 $ 566
AFDC-equity 830 - -
Inventory accounting method (82) (184) (179)
Mining development and oil
exploration costs 196 1,315 848
Other 146 (246) 38
----- ----- -----
$2,975 $1,547 $1,273
</TABLE>
The temporary differences which gave rise to the net deferred tax liability
at December 31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
Net Deferred
Income
Tax Asset
December 31, 1994 Assets Liabilities (Liability)
(in thousands)
<S> <C> <C> <C>
Accelerated depreciation and
other plant-related differences $ - $33,649 $(33,649)
AFDC-equity - 1,291 (1,291)
Regulatory asset 2,350 - 2,350
Unamortized investment tax credits 2,109 - 2,109
Mining development and oil
exploration 678 2,896 (2,218)
Employee benefits 1,521 278 1,243
Other 847 1,839 (992)
----- ------ -------
$7,505 $39,953 $(32,448)
</TABLE>
<TABLE>
<CAPTION>
Net Deferred
Income
Tax Asset
December 31, 1993 Assets Liabilities (Liability)
(in thousands)
<S> <C> <C> <C>
Accelerated depreciation and
other plant-related differences $ - $32,507 $(32,507)
AFDC-equity - 461 (461)
Regulatory asset 2,350 - 2,350
Unamortized investment tax credits 2,109 - 2,109
Mining development and oil
exploration 746 2,383 (1,637)
Employee benefits 1,227 455 772
Other 839 899 (60)
----- ------ -------
$7,271 $36,705 $(29,434)
</TABLE>
The effective tax rate differs from the federal statutory rate for the years
ended December 31, as follows:
<TABLE>
<CAPTION>
1994 1993 1992
<S> <C> <C> <C>
Federal statutory rate 35.0% 35.0% 34.0%
Percentage depletion in
excess of cost (1.7) (2.8) (2.3)
Amortization of investment
tax credits (1.5) (1.6) (1.5)
Tax exempt interest income (1.1) (1.7) (2.3)
Other (0.3) (0.8) (1.4)
---- ---- ----
30.4% 28.1% 26.5%
</TABLE>
(10) OIL AND GAS RESERVES (Unaudited)
The following table summarizes Western Production Company's (WPC) estimated
quantities of proved developed and undeveloped oil and natural gas reserves
at December 31, 1994 and 1993, and a reconciliation of the changes between
these dates using constant product prices for the respective years. These
estimates are based on reserve reports by an independent engineering company
selected by the Company. Such reserve estimates are based upon a number of
variable factors and assumptions which may cause these estimates to differ
from actual results.
<TABLE>
<CAPTION>
1994 1993
Oil Gas Oil Gas
(in thousands of barrels of oil and MCF of gas)
<S> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Balance at beginning of year 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
</TABLE>
WPC has interests in 410 producing oil and gas properties in seven states.
WPC operates a total of 349 wells in Wyoming and Colorado. WPC's non-
operated properties are located in Texas, Wyoming, Colorado, North Dakota,
Montana, Kansas, and California. WPC also holds leases on approximately
64,000 net undeveloped acres.
<PAGE>
(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
The three primary segments of the Company's business are its electric, coal
mining, and oil and gas production operations. The following table
summarizes certain information specifically identifiable with each segment
as of or for the years ended December 31.
<TABLE>
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Assets at year end:
Electric $340,042 $259,680 $238,378
Coal mining 72,851 72,328 71,194
Oil and gas 23,984 20,845 20,630
------- ------- -------
$436,877 $352,853 $330,202
======= ======= =======
Depreciation, depletion, and
amortization:
Electric $ 10,314 $ 9,952 $ 9,614
Coal mining 2,502 1,953 1,482
Oil and gas 4,860 4,146 2,764
------- ------- -------
$ 17,676 $ 16,051 $ 13,860
======= ======= =======
Capital expenditures:
NSS #2 (includes AFDC) $ 73,984 $ 12,792 $ 2,227
Other electric 14,187 13,140 15,507
Coal mining 5,911 7,425 5,001
Oil and gas 8,977 6,933 5,180
------- ------- -------
$103,059 $ 40,290 $ 27,915
======= ======= =======
</TABLE>
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
PacifiCorp Coal Settlement
In 1987 WRDC entered into an agreement with PacifiCorp which (a) settled
PacifiCorp's obligation to purchase coal commencing in 1990 for a second
plant to be located at Wyodak, the construction of which had been canceled,
(b) provided for, among other things, increases in the coal price and
minimum coal purchase obligations by PacifiCorp for the Wyodak Plant, and
(c) provided for payments to WRDC of $2,000,000 each on January 2, 1988
through 1991 for an option to purchase additional coal. These settlements
resulted in an increase in the Company's net income in 1994, 1993, and 1992
of approximately $1,700,000, $1,500,000, and $2,800,000 or $0.12, $0.11, and
$0.20 per share of common stock, respectively.
<TABLE>
Taxes Other Than Income Taxes
<CAPTION>
1994 1993 1992
(in thousands)
<S> <C> <C> <C>
Property $ 3,637 $ 3,549 $2,996
Production and severance 2,995 2,982 2,622
Payroll 1,334 1,195 1,225
Black lung 1,205 1,256 1,191
Federal reclamation 979 1,060 1,035
Other 218 167 195
------ ------ ------
$10,368 $10,209 $ 9,264
</TABLE>
<PAGE>
(13) QUARTERLY FINANCIAL DATA (Unaudited)
Quarterly financial data for the years indicated are summarized as follows:
<TABLE>
<CAPTION>
First Second Third Fourth
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Year ended December 31, 1994
Operating revenues $35,660 $34,491 $38,589 $36,662
Operating income 9,679 7,511 11,347 10,217
Net income 5,800 4,383 6,979 6,643
Earnings per share of common
stock 0.41 0.31 0.49 0.45
Common stock prices
High $22-3/4 $22-1/8 $20-3/4 $22-1/4
Low $20-3/4 $18-1/4 $17-7/8 $17-3/4
Dividends paid per share
of common stock $ 0.33 $ 0.33 $ 0.33 $ 0.33
Year ended December 31, 1993
Operating revenues $34,375 $32,924 $36,304 $35,770
Operating income 9,980 7,793 10,087 9,926
Net income 6,103 4,575 6,011 6,257
Earnings per share of common
stock 0.45 0.33 0.44 0.44
Common stock prices
High $28-1/4 $27-1/4 $27-1/8 $26-1/8
Low $24-7/8 $24-5/8 $25-1/8 $21-7/8
Dividends paid per share
of common stock $ 0.32 $ 0.32 $ 0.32 $ 0.32
</TABLE>
<PAGE>
<TABLE>
SELECTED FINANCIAL DATA
(unaudited)
<CAPTION>
Years ended December 31 1994 1993 1992 1991 1990
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Operating revenues $145,402 $139,373 $135,343 $133,373 $127,498
Net income 23,805 22,946 23,638 22,681 22,938
Per share of common stock:
Earnings 1.66 1.66 1.73 1.66 1.68
Dividends paid 1.32 1.28 1.24 1.17 1.09
Total assets 436,877 352,853 330,202 319,895 294,929
Total long-term
debt 128,925 85,274 88,816 92,982 78,978
</TABLE>
<PAGE>
<TABLE>
FINANCIAL STATISTICS
<CAPTION>
Years ended December 31 1994 1993 1992
<S> <C> <C> <C>
TOTAL ASSETS (in thousands) $436,877 $352,853 $330,202
PROPERTY AND INVESTMENTS (in thousands)
Total property and investments . . . $519,584 $433,143 $413,192
Accumulated depreciation
and depletion. . . . . . . . . . . 156,046 144,492 132,890
Capital expenditures
(includes AFDC) . . . . . . . . . . 103,059 40,290 27,915
CAPITALIZATION (in thousands)
Long-term debt . . . . . . . . . . . $128,925 $ 85,274 $ 88,816
Common stock equity . . . . . . . . . 175,410 168,089 149,158
------- ------- -------
Total . . . . . . . . . . . . . $304,335 $253,363 $237,974
======= ======= =======
CAPITALIZATION RATIOS
Long-term debt . . . . . . . . . . . 42.4% 33.7% 37.3%
Common stock equity . . . . . . . . . 57.6 66.3 62.7
----- ----- -----
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0%
===== ===== =====
AVERAGE INTEREST RATE ON LONG-TERM DEBT 8.5% 9.0% 8.9%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) . . . . . $23,805 $22,946 $23,638
DIVIDENDS PAID ON COMMON STOCK
(in thousands) . . . . . . . . . . . . $18,920 $17,720 $16,977
COMMON STOCK DATA (in thousands)*
Shares outstanding, average . . . . . 14,339 13,811 13,689
Shares outstanding, end of year . . . 14,386 14,270 13,701
Earnings per average share,
in dollars . . . . . . . . . . . . $1.66 $1.66 $1.73
Dividends paid per share, in dollars. $1.32 $1.28 $1.24
Book value per share, end of
year, in dollars . . . . . . . . . $12.19 $11.78 $10.89
RETURN ON COMMON STOCK EQUITY . . . . 13.6% 13.7% 15.8%
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
AS PERCENT OF NET INCOME . . . . . . 16.7% 3.2% 1.6%
(continued)
<CAPTION>
Years ended December 31 1991 1990 1989
<S> <C> <C> <C>
TOTAL ASSETS (in thousands) $319,895 $294,929 $272,523
PROPERTY AND INVESTMENTS (in thousands)
Total property and investments . . . $390,766 $355,276 $331,310
Accumulated depreciation
and depletion. . . . . . . . . . . 122,574 111,111 101,591
Capital expenditures
(includes AFDC) . . . . . . . . . . 36,981 22,336 10,176
CAPITALIZATION (in thousands)
Long-term debt . . . . . . . . . . . $ 92,982 $ 78,978 $ 78,939
Common stock equity . . . . . . . . . 141,963 135,329 127,338
------- ------- -------
Total . . . . . . . . . . . . . $234,945 $214,307 $206,277
======= ======= =======
CAPITALIZATION RATIOS
Long-term debt . . . . . . . . . . . 39.6% 36.9% 38.3%
Common stock equity . . . . . . . . . 60.4 63.1 61.7
----- ----- -----
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0%
===== ===== =====
AVERAGE INTEREST RATE ON LONG-TERM DEBT 8.9% 8.6% 8.5%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) . . . . . $22,681 $22,938 $21,096
DIVIDENDS PAID ON COMMON STOCK
(in thousands) . . . . . . . . . . . . $16,045 $14,947 $13,858
COMMON STOCK DATA (in thousands)*
Shares outstanding, average . . . . . 13,675 13,675 13,675
Shares outstanding, end of year . . . 13,675 13,675 13,675
Earnings per average share,
in dollars . . . . . . . . . . . . $1.66 $1.68 $1.54
Dividends paid per share, in dollars. $1.17 $1.09 $1.01
Book value per share, end of
year, in dollars . . . . . . . . . $10.38 $9.90 $ 9.31
RETURN ON COMMON STOCK EQUITY . . . . 16.0% 16.9% 16.6%
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
AS PERCENT OF NET INCOME . . . . . . 0.8% 1.2% 0.5%
<FN>
* Common stock data have been adjusted retroactively to reflect the
three-for-two stock split in March 1992.
</TABLE>
<PAGE>
<TABLE>
ELECTRIC OPERATION STATISTICS
<CAPTION>
Years ended December 31 1994 1993 1992
<S> <C> <C> <C>
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt hours)
Generated, net station output . . . . 1,108,530 1,227,084 1,226,153
Purchased and net interchange . . . . 595,872 435,990 397,478
--------- --------- ---------
Total generated and purchased . . 1,704,402 1,663,074 1,623,631
Non-firm sales . . . . . . . . . . . . (1,000) (7,780) (10,405)
Company use and losses . . . . . . . . (65,651) (61,336) (73,627)
--------- --------- ---------
Total electric energy sales . . . 1,637,751 1,593,958 1,539,599
========= ========= =========
ELECTRIC ENERGY SALES (megawatt hours)
Residential . . . . . . . . . . . . . 368,953 370,736 339,341
General and commercial . . . . . . . . 495,909 469,496 446,036
Industrial . . . . . . . . . . . . . . 583,258 568,316 572,244
Public authorities . . . . . . . . . . 23,051 22,621 21,798
Sales for resale . . . . . . . . . . . 166,580 162,789 160,180
--------- --------- ---------
Total electric energy sales . . . 1,637,751 1,593,958 1,539,599
========= ========= =========
ELECTRIC REVENUE (in thousands)
Residential . . . . . . . . . . . . . $ 28,574 $ 27,064 $ 25,366
General and commercial . . . . . . . . 35,390 32,295 30,742
Industrial . . . . . . . . . . . . . . 27,318 25,901 27,106
Public authorities . . . . . . . . . . 1,718 1,537 1,586
Sales for resale . . . . . . . . . . . 7,460 7,122 7,002
-------- --------- --------
Total electric revenue . . . . . 100,460 93,919 91,802
Other revenue . . . . . . . . . . . . 4,296 4,236 5,646
--------- --------- ---------
Total revenue $ 104,756 $ 98,155 $ 97,448
========= ========= =========
ELECTRIC CUSTOMERS (end of year)
Residential . . . . . . . . . . . . . 45,060 44,657 44,100
General and commercial . . . . . . . . 8,732 8,507 8,279
Industrial . . . . . . . . . . . . . . 36 41 38
Public authorities . . . . . . . . . . 130 124 117
Other electric utilities . . . . . . . 1 1 1
------ ------ ------
Total . . . . . . . . . . . . . . 53,959 53,330 52,535
====== ====== ======
RESIDENTIAL STATISTICS
Average annual KWH usage:
With electric heating. . . . . . . . 16,369 17,601 15,380
Without electric heating . . . . . . 6,488 6,428 6,172
All residential. . . . . . . . . . . 8,198 8,351 7,743
Average price per KWH, in cents . . . 7.7 7.3 7.5
AVERAGE PRICE PER KWH, ALL CUSTOMERS
(in cents). . . . . . . . . . . . . . 6.1 5.9 6.0
(continued)
<CAPTION>
Years ended December 31 1991 1990 1989
<S> <C> <C> <C>
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt hours)
Generated, net station output . . . . 1,148,259 1,169,054 1,046,971
Purchased and net interchange . . . . 444,848 379,268 468,768
--------- --------- ---------
Total generated and purchased . . 1,593,107 1,548,322 1,515,739
Non-firm sales . . . . . . . . . . . . (1,040) (5,576) (29,087)
Company use and losses . . . . . . . . (59,896) (64,031) (53,282)
--------- --------- ---------
Total electric energy sales . . . 1,532,171 1,478,715 1,433,370
========= ========= =========
ELECTRIC ENERGY SALES (megawatt hours)
Residential . . . . . . . . . . . . . 355,691 338,391 343,645
General and commercial . . . . . . . . 440,043 415,635 395,712
Industrial . . . . . . . . . . . . . . 550,999 542,312 529,703
Public authorities . . . . . . . . . . 21,347 20,819 20,980
Sales for resale . . . . . . . . . . . 164,091 161,558 143,330
--------- --------- ---------
Total electric energy sales . . . 1,532,171 1,478,715 1,433,370
========= ========= =========
ELECTRIC REVENUE (in thousands)
Residential . . . . . . . . . . . . . $ 27,053 $ 25,498 $ 25,456
General and commercial . . . . . . . . 31,227 29,027 27,815
Industrial . . . . . . . . . . . . . . 26,812 25,917 25,153
Public authorities . . . . . . . . . . 1,593 1,540 1,563
Sales for resale . . . . . . . . . . . 7,223 6,532 5,745
--------- --------- ---------
Total electric revenue . . . . . 93,908 88,514 85,732
Other revenue . . . . . . . 4,250 3,762 4,650
--------- --------- ---------
Total revenue $ 98,158 $ 92,276 $ 90,382
========= ========= =========
ELECTRIC CUSTOMERS (end of year)
Residential . . . . . . . . . . . . . 43,539 43,020 42,505
General and commercial . . . . . . . . 8,083 7,866 7,703
Industrial . . . . . . . . . . . . . . 40 44 40
Public authorities . . . . . . . . . . 112 114 111
Other electric utilities . . . . . . . 1 1 1
------ ------ ------
Total . . . . . . . . . . . . . . 51,775 51,045 50,360
====== ====== ======
RESIDENTIAL STATISTICS
Average annual KWH usage:
With electric heating. . . . . . . . 16,773 15,978 16,881
Without electric heating . . . . . . 6,502 6,288 6,421
All residential. . . . . . . . . . . 8,218 7,897 8,171
Average price per KWH, in cents . . . 7.6 7.5 7.4
AVERAGE PRICE PER KWH, ALL CUSTOMERS
(in cents). . . . . . . . . . . . . . 6.1 6.0 6.0
<PAGE>
DIRECTORY
Common Stock
Transfer Agent, Registrar, and Dividend Disbursing Agent
Chemical Bank
450 West 33rd Street
New York, New York 10001
First Mortgage Bonds
Trustee and Paying Agent
Chemical Bank
450 West 33rd Street
New York, New York 10001
Pollution Control and Industrial Development Revenue Bonds
Trustee and Paying Agent
Norwest Bank Minnesota, N.A.
Eighth Street and Marquette Avenue
Minneapolis, Minnesota 55479
Environmental Improvement Revenue Bonds
Trustee and Paying Agent
First National Bank of Chicago
One First National Plaza
Chicago, Illinois 60670
General Counsel
Morrill Brown & Thomas
P.O. Box 8108
Rapid City, South Dakota 57709
Corporate Offices
Black Hills Corporation
P.O. Box 1400
Rapid City, South Dakota 57709
(605) 348-1700
The Company's common stock ($1 par value) is traded on The New York Stock
Exchange. Quotations for the common stock are reported under the symbol BKH.
At year-end the Company had 7,141 common shareholders of record. All fifty
states and the District of Columbia plus twelve foreign countries are
represented.
The continued interest and support of equity owners is appreciated. The Company
has declared common stock dividends payable in cash in each year since its
incorporation in 1941. At its January 1995 meeting the Board of Directors
raised the quarterly dividend to 33.5 cents per share, equivalent to an annual
increase of 2 cents per share. This regular quarterly dividend is payable
March 1, 1995. All dividends are reportable for federal income tax purposes as
ordinary dividend income.
The Annual Report is mailed to each shareholder in accordance with government
rules. Dividend payment dates are normally March 1, June 1, September 1, and
December 1. You may receive more than one copy of the Annual Report if there
are variations in your name or address in which your stock is registered.
Duplicate mailings of annual and interim reports can be eliminated upon written
request of the shareholder.
A copy of the Company's Annual Report on Form 10-K, filed with the Securities
and Exchange Commission, is available to shareholders without charge upon writ-
ten request to Roxann R. Basham, Secretary, P.O. Box 1400, Rapid City, South
Dakota 57709.
1995 ANNUAL MEETING
The Annual Meeting of Shareholders will be held at the Holiday Inn - Rushmore
Plaza Hotel, 505 North Fifth Street, Rapid City, South Dakota, at 9:30 A.M.,
on May 23, 1995. Prior to the meeting, formal notice, proxy statement, and
proxy will be mailed to shareholders.
DIRECT DEPOSIT OF DIVIDENDS
The Company encourages you to consider the direct deposit of your dividends.
With direct deposit, your quarterly dividend payment can be automatically
transferred on the dividend payment date to the bank, savings and loan, or
credit union of your choice. Direct deposit assures payments are credited to
shareholders' accounts without delay. A form is attached to your dividend check
where you can request information about this method of payment. Questions
regarding direct deposit should be directed to Chemical Bank, Security Holder
Relations, P. O. Box 24935, Church Street Station, New York, New York 10249.
DIVIDEND REINVESTMENT PLAN
A Dividend Reinvestment and Stock Purchase Plan (the Plan) is available to
common shareholders. The Plan provides a method of investing common stock
dividends and optional cash payments in additional shares of common stock of the
Company at 100 percent of the recent average market price. The participant may
elect to continue to receive cash dividends on shares registered in their names
and invest by making optional cash payments only. Questions regarding the Plan
should be directed to the Secretary of the Company or Chemical Bank, Dividend
Reinvestment Department, J.A.F. Building, P.O. Box 3069, New York, New York
10116-3069 or by calling the Bank toll free at 1-800-279-1246.
<PAGE>
</TABLE>
Exhibit 21
BLACK HILLS CORPORATION
SUBSIDIARY OF REGISTRANT
Wyodak Resources Development Corp.,
a Delaware corporation.
SUBSIDIARIES OF WYODAK RESOURCES DEVELOPMENT CORP.
DAKSOFT, Inc.
a South Dakota corporation.
Landrica Development Company,
a South Dakota corporation.
Western Production Company,
a Wyoming corporation.
WYGEN, Inc.
a Wyoming corporation.
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our reports included or incorporated by reference in this Form 10-K, into the
Company's previously filed Registration Statements, File Numbers 33-71130,
33-15868, and 33-54329.
Arthur Andersen LLP
Minneapolis, Minnesota,
March 13, 1995
<TABLE> <S> <C>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 309,192,000
<OTHER-PROPERTY-AND-INVEST> 54,346,000
<TOTAL-CURRENT-ASSETS> 61,465,000
<TOTAL-DEFERRED-CHARGES> 11,874,000
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 436,877,000
<COMMON> 14,386,000
<CAPITAL-SURPLUS-PAID-IN> 45,740,000
<RETAINED-EARNINGS> 115,284,000
<TOTAL-COMMON-STOCKHOLDERS-EQ> 175,410,000
0
0
<LONG-TERM-DEBT-NET> 128,925,000
<SHORT-TERM-NOTES> 37,018,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 2,144,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 93,380,000
<TOT-CAPITALIZATION-AND-LIAB> 436,877,000
<GROSS-OPERATING-REVENUE> 145,402,000
<INCOME-TAX-EXPENSE> 10,395,000
<OTHER-OPERATING-EXPENSES> 106,648,000
<TOTAL-OPERATING-EXPENSES> 117,043,000
<OPERATING-INCOME-LOSS> 28,359,000
<OTHER-INCOME-NET> 5,785,000
<INCOME-BEFORE-INTEREST-EXPEN> 34,144,000
<TOTAL-INTEREST-EXPENSE> 10,339,000
<NET-INCOME> 23,805,000
0
<EARNINGS-AVAILABLE-FOR-COMM> 23,805,000
<COMMON-STOCK-DIVIDENDS> 18,920,000
<TOTAL-INTEREST-ON-BONDS> 8,920,000
<CASH-FLOW-OPERATIONS> 48,936,000
<EPS-PRIMARY> 1.66
<EPS-DILUTED> 0
</TABLE>
