<PAGE>
DRAFT BLACK HILLS CORPORATION
625 NINTH STREET
RAPID CITY, SOUTH DAKOTA 57701
NOTICE OF ANNUAL MEETING OF SHAREHOLDERS
TO BE HELD MAY 24, 1994
To the Shareholders of
Black Hills Corporation
NOTICE IS HEREBY GIVEN that the Annual Meeting of the holders of Common
Stock of BLACK HILLS CORPORATION (herein called the Company) will be held at
the Holiday Inn Rushmore Plaza Hotel, 505 North Fifth Street, Rapid City,
South Dakota, on Tuesday, May 24, 1994, commencing at 9:30 A.M., for the
following purposes:
1. To elect three Class II Directors to serve until the
Annual Meeting of Shareholders in 1997;
2. To consider a proposal to increase the Company's
authorized indebtedness from $200,000,000 to
$500,000,000;
3. To act on a proposal to amend Article Fourth of the
Company's Restated Articles of Incorporation as amended
to provide that the control share provisions of the South
Dakota Takeover Act do not apply to the Company.
4. To ratify the appointment of Arthur Andersen & Co. to
serve as independent auditors of the Company for the year
1994;
5. To transact such other business as may properly come
before the meeting or any adjournment thereof.
Only shareholders of record at the close of business on March 11, 1994,
are entitled to notice of and to vote at the meeting or any adjournment
thereof.
All shareholders are cordially invited to attend the meeting. Please
complete, date, sign, and return the accompanying form of proxy. A return
envelope is enclosed which requires no postage if mailed in the United
States. We appreciate your giving this matter your prompt attention.
By Order of the Board of Directors
ROXANN R. BASHAM
Corporate Secretary
Dated: March 25, 1994
<PAGE>
<PAGE>
BLACK HILLS CORPORATION
625 NINTH STREET
RAPID CITY, SOUTH DAKOTA 57701
PROXY STATEMENT
A proxy in the accompanying form is solicited by the Board of Directors
of Black Hills Corporation, a South Dakota corporation (the Company), to be
voted at the Annual Meeting of Shareholders of the Company to be held
Tuesday, May 24, 1994, and at any adjournment thereof.
The enclosed form of proxy, when executed and returned, will be voted as
set forth therein. Any shareholder signing a proxy has the power to revoke
the same in writing, addressed to the Secretary of the Company, or in person
at the meeting at any time before the proxy is exercised.
All shares represented by valid, unrevoked proxies will be voted at the
Annual Meeting. Shares voted as abstentions on any matter (or as "withhold
authority" as to Directors) will be counted as shares that are present and
entitled to vote for purposes of determining the presence of a quorum at the
meeting and as unvoted, although present and entitled to vote, for purposes
of determining the approval of each matter as to which the shareholder has
abstained. If a broker submits a proxy which indicates that the broker does
not have discretionary authority as to certain shares to vote on one or more
matters, those shares will be counted as shares that are present and entitled
to vote for purposes of determining the presence of a quorum at the meeting,
but will not be considered as present and entitled to vote with respect to
such matters.
The Company will bear all costs of the solicitation. In addition to
solicitation by mail, officers and employees of the Company may solicit
proxies by telephone, telegraph, or in person. Chemical Bank has been
retained by the Company to assist in the solicitation of proxies at an
anticipated cost of $4,500. Also, the Company will, upon request, reimburse
brokers or other persons holding stock in their names or in the names of
their nominees for reasonable expenses in forwarding proxies and proxy
material to the beneficial owners of stock.
This Proxy Statement and the accompanying form of proxy are to be first
mailed on March 25, 1994. The Company's Annual Report for the year 1993 has
been mailed to shareholders.
VOTING RIGHTS AND PRINCIPAL HOLDERS
Only shareholders of record at the close of business on March 11, 1994,
will be entitled to vote at the meeting. The outstanding voting stock of the
Company as of such record date consisted of __________ shares of Common
Stock.
Each outstanding share of Common Stock is entitled to one vote.
Cumulative voting is permitted in the election of directors. Each share is
entitled to three votes, one each for the election of three directors, and
the three votes may be cast for a single person or may be distributed among
two or three persons.
The Company is not aware of any person or group who is the beneficial
owner of more than five percent of the Company's Common Stock.
<PAGE>
ITEM I
ELECTION OF DIRECTORS
In accordance with the Bylaws and Article Fifth of the Restated Articles
of Incorporation, the Company's directors are elected to three classes of
staggered terms consisting of three years each. At this Annual Meeting of
Shareholders, three directors will be elected to Class II of the Board of
Directors to hold office for a term of three years until the Annual Meeting
of Shareholders in 1997 and until their respective successors shall be duly
elected and qualified.
Each of the nominees for director is presently a member of the Board of
Directors of the Company and its subsidiaries, including Wyodak Resources
Development Corp., the Company's coal mining subsidiary, and Western
Production Company, the Company's oil and gas producing company. The proxy
attorneys will vote your stock for the election of the three nominees for
director listed below, unless otherwise instructed, but will, at their
discretion, cumulate votes for any one or more of the nominees. If, at the
time of the meeting, any of such nominees shall be unable to serve in the
capacity for which they are nominated or for good cause will not serve, an
event which the Board of Directors does not anticipate, it is the intention
of the persons designated as Proxy Attorneys to vote, at their discretion,
for nominees to replace those who are unable to serve. The affirmative vote
of a majority of the common shares present and entitled to vote with respect
to the election of directors is required for the election of the nominees to
the Board of Directors.
The following information, including principal occupation or employment
for the past five or more years, is furnished with respect to each of the
following persons who are nominated as Class II directors, each to serve for
a term of three years to expire in 1997.
<PAGE>
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR THE ELECTION OF THE
FOLLOWING NOMINEES:
NOMINEES FOR ELECTION UNTIL
1997 ANNUAL MEETING - CLASS II
NAME, AGE, PRINCIPAL OCCUPATION FOR DIRECTOR
LAST FIVE YEARS AND OTHER DIRECTORSHIPS SINCE
DANIEL P. LANDGUTH, 47 1989
Chairman, President, and Chief Executive
Officer of the Company since January 1,
1991; President and Chief Operating
Officer of Black Hills Corporation from
October 1989; Senior Vice President and
Chief Operating Officer of the Utility
from May 1985 to October 1989
DALE E. CLEMENT, 60 1979
Senior Vice President-Finance of the Company
and subsidiaries since September 1, 1989;
Dean of the School of Business and Professor
of Finance, University of South Dakota,
Vermillion, South Dakota, prior to
September 1989
JOHN R. HOWARD, 53 1977
President, Industrial Products, Inc. (an
industrial parts distributor) since
March 2, 1992; General Manager of Black
Hills Packing Co. (a meat processing
concern), Rapid City, South Dakota, from
December 1978 to June 1, 1991; Director,
Norwest Bank-South Dakota, N.A.
<PAGE>
DIRECTORS WHOSE TERMS EXPIRE AT
1995 ANNUAL MEETING - CLASS III
NAME, AGE, PRINCIPAL OCCUPATION FOR DIRECTOR
LAST FIVE YEARS AND OTHER DIRECTORSHIPS SINCE
MICHAEL B. ENZI, 50 1992
Accounting Manager, Dunbar Well Service,
Inc. (an oil well servicing company),
Gillette, Wyoming; Wyoming State Senator,
Campbell County, Wyoming; President of NZ
Shoes, Inc. (retail shoe store), Gillette,
Wyoming
EVERETT E. HOYT, 54 1991
President and Chief Operating Officer of
Black Hills Power and Light Company from
October 1, 1989; Director since January 1,
1991; Senior Vice President - Legal
and Corporate Secretary of Northwestern
Public Service Company, Huron, South
Dakota, prior to October 1989;
Director-Northwestern Public
Service Company from May 1988 through
September 1989
CHARLES T. UNDLIN, 66 1970
Vice Chairman, Rushmore State Bank,
Rapid City, South Dakota
<PAGE>
DIRECTORS WHOSE TERMS EXPIRE AT
1996 ANNUAL MEETING - CLASS I
NAME, AGE, PRINCIPAL OCCUPATION FOR DIRECTOR
LAST FIVE YEARS AND OTHER DIRECTORSHIPS SINCE
GLENN C. BARBER, 60 1984
President and General Manager, Glenn
C. Barber & Associates Inc. (a general
construction company)
BRUCE B. BRUNDAGE, 58 1986
President and Director, Brundage &
Company (a firm specializing in corporate
financing), Englewood, Colorado; Director,
Vicorp Restaurants, Inc., Denver, Colorado
KAY S. JORGENSEN, 43 1992
Concessionaire, Black Hills Passion Play,
Spearfish, South Dakota; South Dakota
Legislative Representative, Lawrence County,
South Dakota
__________________________
<PAGE>
SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth information, as of December 31, 1993,
with respect to beneficial ownership of Common Stock of the Company for each
Director, each executive officer named in the Summary Compensation table
herein, and all Directors and executive officers of the Company as a group.
NUMBER OF SHARES AND NATURE
NAME OF BENEFICIAL OWNER OF BENEFICIAL OWNERSHIP <F1>
Glenn C. Barber 2,687
Bruce B. Brundage 3,615<F2>
Dale E. Clement 9,597
Michael B. Enzi 998<F3>
John R. Howard 10,420
Everett E. Hoyt 4,048<F4>
Kay S. Jorgensen 343
Daniel P. Landguth 7,988<F4>
Charles T. Undlin 8,356
All Directors and executive
officers as a group 58,246<F4>
<F1> Represents outstanding Common Stock beneficially owned both
directly and indirectly as of December 31, 1993. The Common Stock interest
of each named person and all Directors and executive officers as a group
represents less than one percent of the aggregate amount of Common Stock
issued and outstanding. Except as indicated by footnote below, the
beneficial owner possesses sole voting and investment powers with respect to
the shares shown.
<F2> Includes 3,600 shares owned by Brundage & Co. Pension Plan and
Trust which Mr. Brundage is the Trustee and has sole voting and investment
power.
<F3> Includes 100 shares owned jointly with Mr. Enzi's son as to which
he shares voting and investment power and 100 shares for which Mr. Enzi is
custodian of his minor daughter.
<F4> Includes Common Stock held by the Trustee of the Company's
Retirement Savings Plan (401K) of which the Trustee has sole voting and
investment power as follows: Mr. Hoyt 3,711 shares, Mr. Landguth 2,593
shares, and all Directors and executive officers as a group 10,880 shares.
<PAGE>
THE BOARD AND COMMITTEES
The Executive Committee is comprised of Glenn C. Barber, Bruce B.
Brundage, John R. Howard, Daniel P. Landguth, and Charles T. Undlin, with Mr.
Landguth serving as Chairman. The Committee exercises the authority of the
Board of Directors in the interval between meetings of the Board, recommends
to the Board of Directors persons to be elected as officers, and recommends
persons to be appointed to Board Committees. The Executive Committee held
two meetings during 1993.
The Compensation Committee is comprised of Glenn C. Barber, Bruce B.
Brundage, Michael B. Enzi, John R. Howard, Kay S. Jorgensen, and Charles T.
Undlin, with Mr. Barber serving as Chairman. The Committee performs
functions required by the Board of Directors in the administration of all
federal and state statutes relating to employment and compensation,
recommends to the Board of Directors compensation for officers, and considers
and approves the Company's compensation program including benefits and stock
ownership plans. The Compensation Committee held three meetings in 1993.
The Audit Committee is comprised of Bruce B. Brundage, Michael B. Enzi,
John R. Howard, and Kay S. Jorgensen, with Mr. Howard serving as Chairman.
The Committee annually recommends to the Board of Directors an independent
accounting firm to be appointed by the Board for ratification by the
shareholders, reviews the scope and results of the annual audit including
reports and recommendations of the firm, reviews the Company's internal audit
function, and periodically confers with the internal audit group, management
of the Company, and its independent accountants. The Audit Committee held
three meetings in 1993.
The Nominating Committee is comprised of Glenn C. Barber, John R.
Howard, Daniel P. Landguth, and Charles T. Undlin, with Mr. Howard serving as
Chairman. The Committee recommends to the Board of Directors persons to be
nominated as directors or to be elected to fill vacancies on the Board. The
Bylaws require that an outside director serve as Chairman of the Committee.
The Nominating Committee held one meeting in 1993.
Pursuant to the Company's Bylaws, nominations from shareholders for
Board membership will be considered by the Nominating Committee.
Shareholders who wish to submit names for future consideration for Board
membership should do so in writing prior to November 26, 1994, addressed to
Nominating Committee, c/o Corporate Secretary, Black Hills Corporation, P.O.
Box 1400, Rapid City, South Dakota 57709.
Members of the Committees referred to herein are designated by the Board
of Directors upon recommendation of the Executive Committee each year at a
meeting held following the Annual Meeting of Shareholders.
The Board of Directors held twelve meetings during 1993. During 1993
Bruce B. Brundage only attended 70 percent of the aggregate of the total
number of Board meetings and Committee meetings on which he served due to his
recuperation from an accident.
<PAGE>
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation Committee is solely comprised of the following outside
directors, Glenn C. Barber, Bruce B. Brundage, Michael B. Enzi, John R.
Howard, Kay S. Jorgensen, and Charles T. Undlin.
Mr. Howard is also a director of Norwest Bank - South Dakota, N.A. of
which the Company has a $15 million line of credit. During 1993, Norwest
Bank - South Dakota, N.A. participated in short-term loans to the Company of
up to $10 million at an interest rate of 1/8 percent less than the prime
rate.
DIRECTORS' FEES
Directors who are not officers of the Company receive an annual fee of
$12,000 plus a fee of $600 for each board meeting and committee meeting
attended providing such committee meetings are substantive in nature and
content.
DIRECTORS' RETIREMENT PLAN
The Company has a Retirement Plan for those directors who are not
otherwise employed by the Company (outside directors). The monthly benefit
is $1,000 payable for a period of time equal to the number of months the
outside director served or for 120 months, whichever is less. The monthly
benefits commence at the earliest of (1) the first full complete month the
outside director is 60 years of age or more and is no longer a director of
the Company or (2) the first full month after the death of the outside
director or former outside director. The Board of Directors may withdraw
retirement benefits for any outside director dismissed for cause. The
monthly benefit is paid to the participating director, or if deceased, the
director's designated beneficiary, and if none, his or her estate.
EXECUTIVE COMPENSATION
Compensation Committee Report on Executive Compensation
The Compensation Committee of the Board of Directors is responsible for
developing and making recommendations to the Board on executive compensation.
The components of the Company's executive compensation program consists of a
base salary and an incentive gainsharing bonus. The mix of base salary and
incentive bonus reflects the Company's goals of attracting and retaining
highly qualified and motivated managers, recognizing and rewarding
outstanding performance, and fostering a cohesive management team.
The Committee makes annual recommendations to the Board concerning the
base salary and incentive gainsharing bonus for the Chief Executive Officer
and each of the other executive officers of the Company. Recognizing a
market based compensation structure, the Committee strives to ensure that
competitive salary ranges and base salaries are being maintained. In the
later part of 1992, the Compensation Committee had hired Hewitt Associates,
an internationally recognized compensation consultant firm, to review the
executive and director compensation being paid at the Company. Data
collected for that 1992 review was again utilized. Hewitt Associates
confirmed that their data, if aged for the few months that had passed, would
be adequate as a basis for 1993.
Utilizing the data from the Hewitt Associates study and comparing it to
data from the Edison Electric Institute, the trade association of investor-
owned electric utilities, the Committee recommended to the Board the base
salary for the Chief Executive Officer as well as for the other executive
officers. The salaries were not only based upon comparable market salary
information but also on the accomplishments of key corporate and individual
performance objectives.
The Company's position is to establish a market salary level for each
salary range that is at or near the median (50th percentile) of the range of
salaries of comparable companies surveyed. A performance matrix system is
used in determining the percentage of salary increase taking into account the
performance rating for the individual officer and the relationship of the
officers current salary to market. An outstanding performance rating is
given when there is extraordinary and exceptional accomplishment, results are
far in excess of requirements, and demanding objectives are attained. A
superior performance rating indicates results are well above the expected
level and the individual was successful in accomplishing challenging
objectives. Competent performance ratings are given when all position
requirements are met, the individual consistently performs the job in a
satisfactory manner, and realistic objectives are obtained. All executive
officers received either a superior or outstanding performance rating.
The Compensation Committee granted the Chief Executive Officer a
superior rating based on the Company's performance and obtaining successful
regulatory approval and all permits to construct the new power plant.
Overall corporate results were very positive in 1992, corporate earnings
increased 4 percent, and dividends increased by 6 percent over 1991. The
Compensation Committee approved a 6 percent base salary increase and a one-
time $4,900 performance bonus for the Chief Executive Officer. The increase
to the base salary brings the Chief Executive Officer's base salary to 95.8
percent of market as determined by wage surveys.
The Company currently maintains a variety of employee benefit plans and
programs in which its executive officers may participate, including the
gainsharing program, the retirement savings (401k) plan, the pension plan,
and the pension equalization plan. With the exception of the Pension
Equalization Plan (PEP), these benefit plans and programs are generally
available to all employees within the Company.
The Executive Gainsharing Program is one of three sections of a Company
wide program. The goals of the Executive Gainsharing Program support the
interests of the ratepayer and stockholder by increasing net income. This is
accomplished through increased cost containment and operating efficiencies
which in the end result reduce costs and increase earnings. The program for
1992 which paid a 3 percent gainshare award in 1993 specifically consisted of
a net income goal. The Company's actual net income in 1993 exceeded budgeted
net income by more than 109 percent resulting in a maximum 3 percent
gainshare award.
It is the objective of the Company to pay its executives a fair salary,
based on the comparable pay of similar types of companies in relation to
achieving corporate, business unit, and individual performance objectives.
The Company does not offer any restricted stock awards, stock options, or
other long-term incentive compensation plans. Furthermore, officers are not
permitted to serve on the Board of Directors of any other corporation
operating for profit. The intent of the latter is that if the executives are
paid fairly, the Company and its shareholders should demand their full
attention and, therefore, their efforts are totally directed toward the
Company and not interrupted by the obligations of serving as a director for
other for profit corporations.
COMPENSATION COMMITTEE
Glenn C. Barber, Chairman Bruce B. Brundage Michael B. Enzi
John R. Howard Kay S. Jorgensen Charles T. Undlin
____________________
<PAGE>
The following table is furnished for the fiscal year ended December 31,
1993, with respect to the Chief Executive Officer of the Company and the
executive officers whose salary and bonus compensation for 1993 exceeded
$100,000.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
NAME AND PRINCIPAL
POSITION YEAR SALARY BONUS<F1> OTHER
ANNUAL
COMPENSATION<F2>
Daniel P. Landguth
Chairman, President, 1993 $178,466 $10,761 -
and Chief Executive 1992 173,134 4,400 $13,850
Officer of the Company 1991 169,866 - -
and subsidiaries
Dale E. Clement
Senior Vice President- 1993 $124,266 $ 3,966 -
Finance of the Company 1992 122,430 3,163 $ 2,449
and subsidiaries 1991 116,865 - -
Everett E. Hoyt
President and Chief 1993 $123,566 $ 3,906 -
Operating Officer of 1992 121,008 3,245 $ 2,546
Black Hills Power 1991 121,008 - 3,630
and Light Company
<F1> Bonus is the amount received under the Incentive Gainshare
Program, a cash bonus program for all Company employees based on the
attainment of predetermined profitability measures.
Mr. Landguth's bonus in 1993 includes both his Gainshare bonus and a one-time
performance bonus of $4,900.
<F2> Other Annual Compensation is the amount of lump sum payments
received in lieu of base salary increases in 1992. Mr. Hoyt also received a
lump sum payment in 1991 in lieu of an increase in his base salary.
RETIREMENT PLANS
The Company has a defined benefit retirement plan (Retirement Plan) for
its employees. The Retirement Plan provides benefits at retirement based on
length of employment service and average monthly pay in the five consecutive
calendar years of highest earnings out of the last ten years. Employees do
not contribute to the Retirement Plan. The amount of annual contribution by
the employers to the Retirement Plan is based on an actuarial determination.
Accrued benefits become 100 percent vested after an employee completes five
years of service.
The Company also has a Pension Equalization Plan (the PEP), a
nonqualified supplemental plan, which is designed to provide the higher paid
executive employee a retirement benefit which, when added to social security
benefits and the pension to be received from the Retirement Plan, will
approximate retirement benefits being paid by other employers to its
employees with like executive positions. The employee's pension from the
qualified pension plan is limited under the current law to not exceed
$118,800 annually and the compensation taken into account in determining
contributions and benefits cannot exceed $150,000. The amounts of deferred
compensation paid under nonqualified plans such as the PEP are not subject to
the limits. A participant under the PEP does not qualify for benefits until
the benefits become vested under a vesting schedule - 20 percent after three
years of employment under the plan increasing up to 100 percent vesting after
eight years of employment under the plan. No credit for past service is
granted under the PEP. The annual benefit is 25 percent of the employee's
average earnings (if salary was less than two times the Social Security Wage
Base) or 30 percent (if salary was more than two times the Social Security
Wage Base) times the vesting percentage. Average earnings are normally an
employees average earnings for the five highest consecutive full years of
employment during the ten full years of employment immediately preceding the
year of calculation. The annual PEP benefit is paid on a monthly basis for
15 years to each participating employee and if deceased to the employee's
designated beneficiary or estate, commencing at the earliest of death or when
the employee is both retired and 62 years of age or more.
Participants in the PEP are designated by the Board of Directors upon
recommendation of the Chief Executive Officer. Selection is based on key
employees as determined by management and consideration of performance rather
than salary based only. The minimum salary component applied in the
selection process is the maximum annual Social Security taxable wage base
which is presently at $60,600. Four officers of the Company were initially
excluded because the period of time up to the date of their likely retirement
would not result in vested benefits as intended by the PEP. The Company
extended to those four individuals certain benefits paid at retirement which
would approximate 50 percent of the present value of the PEP. Since then,
arrangements have been made with three of those persons who retired.
<PAGE>
RETIREMENT BENEFITS
The following table illustrates estimated annual benefits, as of January
1, 1994, payable under the Retirement Plan and the PEP to employees who
retire at the normal retirement date.
Years of Service
Annual 15 20 25 30 35
Pay Years Years Years Years Years
$ 60,000 $ 27,945 $ 32,260 $ 36,575 $ 40,890 $ 45,205
75,000 35,295 40,810 46,325 51,840 57,355
90,000 42,645 49,360 56,075 62,790 69,505
110,000 52,445 60,760 69,075 77,390 85,705
125,000 66,045 75,560 85,075 94,550 104,105
150,000 79,545 91,060 102,575 114,090 125,605
175,000 87,045 98,560 110,075 121,590 133,105
200,000 94,545 106,060 117,575 129,090 140,605
225,000 102,045 113,560 125,075 136,590 148,105
Estimated annual benefits payable to officers named below at age 65 from
all sources are as follows: Daniel P. Landguth, 35 yrs. - $134,991; Dale E.
Clement, 33 yrs. - $88,235<F1>; Everett E. Hoyt, 31 yrs. - $81,393<F1>.
The benefits in the foregoing table were calculated as a straight life
annuity. Amounts shown are exclusive of Social Security benefits and include
benefits from both the Retirement Plan and from the PEP assuming a 100
percent vested interest in the PEP.
_________________________
<F1> Such amounts are adjusted for benefits applicable to service for
prior employment.
<PAGE>
EMPLOYEES' STOCK PURCHASE PLAN
Employees of the Company and its subsidiaries are eligible to
participate in the Employees' Stock Purchase Plan, as approved by the
shareholders at the 1987 Annual Meeting under which offerings of the
Company's Common Stock, at the discretion of the Board, are made to employees
at a price equal to 90 percent of the closing sale price on the New York
Stock Exchange on the date of the offering. An offering was extended to
employees in 1993 and officers subscribed to 350 shares at a price of $24.08
per share. Shares are held in nominee name until subscriptions are paid for
in full.
RETIREMENT SAVINGS PLAN
The Company has a Retirement Savings Plan under Section 401(k) of the
Internal Revenue Code of 1954, as amended, which permits employees of the
Company and its subsidiaries, including officers, to elect to invest up to 15
percent of their eligible earnings on a pre-tax basis into an investment fund
subject to limitations imposed by the Internal Revenue Code. The Company
makes no contributions to the Plan.
Distribution from the fund will be made to employees at termination of
employment, retirement, death, or in case of hardship. No amounts were paid
or distributed pursuant to the Retirement Savings Plan to the individuals
named herein nor to the officers as a group.
The Trustee for the Retirement Savings Plan (401(k) Plan) has voting
power with respect to shares held in the name of the Trustee of the Plan.
STOCK PERFORMANCE GRAPH
The graph below compares the cumulative shareholder return on the
Company's Common Shares for the last five fiscal years with the cumulative
total return of the Duff & Phelps Quality II Electrics and the S&P 500 Index
over the same period (assuming the investment of $100 on January 1, 1989, and
the reinvestment of all dividends). The Company changed its broad market
index this year from the Edison Electric Institute Investor-Owned Electric
Utility Index to the S&P 500 Index because the Securities and Exchange
Commission notified the Company that they do not accept the Edison Electric
Institute Investor-Owned Electric Utility Index as a published broad market
index.
1989 1990 1991 1992 1993
Black Hills Corporation 120 135 194 202 176
Duff & Phelps Quality
II Electric Companies 127 131 173 186 204
S&P 500 Index 132 128 166 179 197
<PAGE>
ITEM II
AUTHORIZATION OF INCREASE IN INDEBTEDNESS
Under the provisions of Article XVII, Section 8 of the Constitution of
the State of South Dakota, the maximum amount of indebtedness which the
Company is authorized to issue may not be increased without the consent of
the shareholders. Pursuant to this provision, the shareholders in 1992, on
the recommendation of the Board of Directors, approved and authorized an
increase in the maximum amount of the Company's authorized indebtedness to
$200,000,000. As of February 28, 1994, the Company's outstanding
indebtedness was as follows:
First Mortgage Bonds . . . . . . . . . . . $ 62,794,000
Other Long Term Debt . . . . . . . . . . . . 24,500,000
Notes Payable. . . . . . . . . . . . . . . 14,468,000
$101,762,000
The Company's construction expenditures for the next three years are
estimated as follows:
<TABLE>
<CAPTION>
1994 1995 1996
(in thousands)
<S> <C> <C> <C>
Neil Simpson Unit #2
(new power plant) $65,113 $45,035 $ -
Other Production Plant 2,283 859 897
Transmission Plant 4,228 1,617 8,478
Distribution Plant 6,511 6,503 6,876
General Plant 1,448 814 2,354
$79,583 $54,828 $18,605
</TABLE>
These and future construction requirements of the Company will require
additional debt financing. The Company has not entered into agreements with
respect to the issuance of any additional debt securities. It is expected,
however, that the Company will issue and sell additional debt securities from
time to time. The timing and amount of such issuance will depend on market
conditions and other factors existing at the time. Under the terms of the
proposed resolution, the Board of Directors, subject to the approval of
regulatory authorities, can, at the opportune time without further
authorization of the shareholders, determine and fix the amount and terms of
the debt securities to be issued including interest rates, maturity dates,
call provisions, sinking fund requirements, and similar matters.
Accordingly, the following resolution will be presented at the meeting:
RESOLVED, That the consent of the shareholders be, and it is
hereby given to an increase in the Company's authorized
indebtedness to not exceed $500,000,000 at any one time
outstanding; that for the purpose of effecting such increase,
bonds, debentures, notes, and other instruments evidencing
indebtedness of the Company may be issued from time to time in such
form and of such character as seems desirable to the Board of
Directors; and that for the purpose of consenting to an increase of
authorized indebtedness of the Company, it is the intention of this
resolution that bonds, debentures, notes, and other instruments
evidencing indebtedness are authorized to be issued whenever the
maximum indebtedness by this resolution is not thereby exceeded;
said bonds, debentures, notes and other evidences of indebtedness
to be issued when and as the Board of Directors shall deem
advantageous for the Company's interest and upon such terms and
conditions as shall be approved by the Board.
VOTE REQUIRED
An affirmative vote of the holders of the majority of all issued and
outstanding shares of common stock is required to adopt the foregoing
resolution.
While the current debt limitation is believed to be sufficient to
complete the above construction expenditures, the Board of Directors is of
the opinion that the debt limitation should be set high enough so as to give
the Board the flexibility to determine from time to time on short notice the
borrowing requirements and terms of those borrowings and to be able to close
those borrowings without the necessity of calling frequent shareholder
meetings.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR
ADOPTION OF THE RESOLUTION
<PAGE>
ITEM III
AMENDMENT TO ARTICLE FOURTH OF THE RESTATED ARTICLES
OF INCORPORATION TO PROVIDE THAT THE
CONTROL SHARE ACQUISITION PROVISIONS OF THE SOUTH DAKOTA
TAKEOVER ACT DO NOT APPLY TO THE COMPANY
The Board of Directors unanimously adopted a resolution to submit to the
shareholders for their consideration an amendment, as described herein, to
Article Fourth of the Restated Articles of Incorporation, as amended, that if
adopted will add paragraph 8 to Article Fourth providing that the Control
Share Acquisition (hereinafter defined) provisions of the South Dakota
Domestic Public Corporation Takeover Act ("Takeover Act") do not apply to the
Company.
The Takeover Act, found at Chapter 47-33 of the South Dakota Codified
Laws ("SDCL"), was adopted by the South Dakota Legislature in 1990 and became
effective July 1, 1990. The Control Share Acquisition provisions along with
other provisions of the Takeover Act became applicable to domestic public
corporations, including the Company, on the effective date of the Takeover
Act. However, the Takeover Act provides that a corporation through its
articles of incorporation may elect not to have the Control Share Acquisition
provisions apply to that corporation.
The Control Share Acquisition provisions and other provisions of the
Takeover Act are summarized in the Proxy Statement. However, the summary
does not include each and every provision of the act. A full understanding
of the Takeover Act would require a thorough reading of the act at
SDCL 47-33.
If the proposed amendment to Article Fourth is adopted by the
shareholders, the Control Share Acquisition provisions of the Takeover Act
shall not apply to any Control Share Acquisition occurring after such
adoption.
Control Share Acquisition Provisions Explained
Definition. A "Control Share Acquisition" as defined by the Takeover
Act at SDCL Section 47-33-3(l) is generally, subject to certain exceptions,
an acquisition, directly or indirectly, by an acquiring person of beneficial
ownership of shares of a domestic public corporation that when added to all
other shares beneficially owned by the acquiring person would allow that
person to exercise certain ranges of voting power. Acquisition of shares as
a result of a merger first approved by the Board of Directors followed by
approval of the shareholders is not a Control Share Acquisition.
Shareholder Election Required to Give Voting Rights. The Control Share
Acquisition provisions of the Takeover Act provides generally that a Control
Share Acquisition that exceeds certain thresholds of voting power (described
below) shall have the same voting rights as other shares of the same class or
series only if approved by the affirmative vote of the majority of all
outstanding shares entitled to vote, including all shares held by the
acquiring person, and by the affirmative vote of the holders of the majority
of the voting power of all outstanding shares entitled to vote, excluding all
interested shares. The thresholds which would require shareholder approval
before voting powers are obtained with respect to shares acquired in excess
of such thresholds are 20 percent, 33 2/3 percent and 50 percent,
respectively. Each time an acquiring person reaches a threshold, an election
must be held as described above before the acquiring person will have any
voting rights with respect to shares in excess of such threshold.
The Control Share Acquisition provisions of the Takeover Act further
provides that any person who proposes to make or has made a Control Share
Acquisition may at that person's election cause an informational statement to
be furnished the Company and, if an undertaking is furnished to pay the costs
of the meeting, may request a special meeting of the shareholders to be
called for the sole purpose of considering the voting rights to be accorded
the shares acquired or to be acquired pursuant to the Control Share
Acquisition. If such informational statement, request and undertaking are
furnished, the Takeover Act provides that a special meeting of shareholders
be called for such purpose be held no later than 50 days after receipt of the
informational statement. If the informational statement is furnished but a
special meeting of shareholders is not requested, consideration of the voting
rights to be accorded shares pursuant to the Control Share Acquisition is to
be submitted to the shareholders at the next special or annual meeting of
shareholders.
Redemption of Shares. The Control Share Acquisition provision of the
Takeover Act further provides that the Company may redeem at the market value
as of the time of redemption those shares that were acquired in a Control
Share Acquisition if (i) an informational statement was not furnished the
Company within the tenth day after the Control Share Acquisition or (ii) an
informational statement was furnished but the shareholders voted not to
accord voting rights.
Purpose of Takeover Act
The Takeover Act provides that the purpose of the Control Share
Acquisition provisions and other anti-takeover provisions of the Takeover Act
generally, among other things, is to provide the stable, long-term growth of
South Dakota's domestic public corporations, to prevent the impairment of
local employment conditions and disruption of local commercial activity and
stable relationship of corporations and to protect shareholders from forced
mergers and other coercive devices adopting short-term business strategies
that deprive shareholders of value.
Reasons for Board's Recommendation
The Board of Directors does not have any knowledge of any effort to
accumulate the Company's common stock or to obtain control of the Company.
Notwithstanding lack of those efforts at this time, the Board believes that
for the reasons in the following paragraph, it should be prepared for such
possibility. Once a Control Share Acquisition is proposed, it would be too
late to amend the Articles of Incorporation.
The reasons why the Board of Directors is recommending to the
shareholders to elect to not have the Control Share Acquisition provisions
apply to the Company is that the provisions could allow a person to force the
Board of Directors to call a shareholder meeting to consider voting rights of
the acquiring person within only 50 days from the time the Board first
discovers that the person is interested in acquiring the Company. In the
opinion of the Board of Directors, this period of time does not give the
Board an ample opportunity to study the proposal and to act in the best long-
term interests of the shareholders. The Board further believes that the
issue of granting or not granting voting rights for shares that may not even
have been acquired at the time of the shareholder meeting would be confusing
to shareholders, and the results of such vote would, in the opinion of the
Board of Directors, be of little guidance in determining what action the
Board should take to protect shareholders' interests. The Board believes
this to be especially true because the Company is an electric public utility,
and under current law any acquisition by a person of 10 percent or more of
its shares must be first approved by the South Dakota Public Utilities
Commission, and any acquisition over 50 percent by the Wyoming Public Service
Commission. The Federal Energy Regulatory Commission would also be required
to approve any merger, and the Securities and Exchange Commission may become
involved if a holding company is created under the Public Utilities Holding
Company Act. The Board of Directors believes that any future acquisition of
the Company whether supported or opposed by the Board will largely depend
upon the decisions of some or all of these regulatory commissions which will
apply public interests standards to any such proposed mergers. In view of
these regulatory requirements, the Board of Directors believes that forced
shareholder meetings to consider voting rights to be given to a proposed
acquiring person before regulatory proceedings are held would be premature
and would interfere with strategies to be undertaken by the Board of
Directors to protect the interests of shareholders.
The Board of Directors has no intention at this time to propose any
additional anti-takeover measures or modify or remove any of those other
defenses disclosed under "Other Takeover Defenses Not Affected by Proposal"
following.
Overall Effect of the Proposal--Advantages and Disadvantages
The Control Share Acquisition provisions are designed to discourage any
change of control of the Company that the Board of Directors does not
approve. Since the acquiring person must get permission from the other
shareholders to be able to vote the shares at the 20, 33 1/3 and 50 percent
thresholds, and if approval is not given, the Company would have the right to
redeem those shares, an acquiring person would obviously be discouraged from
investing in the shares. Conceivably an acquiring person could own over 50
percent of the shares but be denied any right to vote those shares.
Therefore, the effect of the proposal to amend the articles to not have the
Control Share Acquisition provisions apply is to make it easier for
shareholders to obtain control and remove management.
On the other hand, the Control Share Acquisition provisions do allow an
acquiring person an opportunity to force a reluctant Board of Directors to
call a shareholder meeting. While the shareholder vote would be whether to
grant voting rights to the stock of the acquiring person, the vote could be
perceived as a referendum of the shareholders on the acquiring person's
proposal to acquire the Company. Granting voting rights would be a clear
signal to the acquiring person to acquire additional stock. To that extent,
the Control Share Acquisition provisions would encourage shareholder
participation in a takeover proposal, and the proposed amendment discourages
shareholder participation.
However, the Board of Directors believes that for all the reasons stated
above under "Reasons for Board's Recommendations" and especially in view of
the regulatory approvals required for any change in control, forced
shareholder meetings to vote on granting voting rights would be premature and
confusing to the regulatory process and undermine the Board's strategy in
protecting the shareholder interest in that regulatory process.
Other Takeover Defenses Not Affected by Proposal
The Takeover Act and the Company's Restated Articles of Incorporation
contain other provisions hereafter described that would not be affected by
the adoption of the proposed Amendment but would discourage or make more
difficult a change in control of the Company without approval of the Board of
Directors. The Board of Directors believes that these remaining provisions
are adequate without the Control Share Acquisition provisions to protect the
Company's shareholders against coercive, unfair or inadequate tender offers
and other abusive takeover tactics and to encourage any person contemplating
a business combination with the Company to negotiate with its Board of
Directors for the fair and equitable treatment of all of the Company's
shareholders.
Election of Directors. In electing directors, shareholders may
cumulate their votes as provided by Article XVII, Section 5 of the South
Dakota Constitution and SDCL Section 47-5-6. Article Fifth of the Company's
Restated Articles of Incorporation provides that the Board of Directors is
divided into three classes as nearly equal in number as possible with
staggered terms of office so that only approximately one-third of the
directors are elected at each annual meeting of shareholders. The existence
of a classified Board along with cumulative voting rights may make it more
difficult for a group owning a significant amount of the Company's voting
securities to effect a change in the majority of the Board than would be the
case if a classified Board and cumulative voting did not exist. Article
Fifth cannot be amended or repealed without the affirmative vote of the
holders of at least 80 percent of the Common Stock of the Company and 66 2/3
percent of the Cumulative Preferred Stock of the Company.
Fair Price Article. Article Sixth of the Company's Restated Articles
of Incorporation provides that the affirmative vote of the holders of not
less than 80 percent of the outstanding shares of voting stock of the Company
is required for the approval of any Business Transaction (a merger or similar
transaction) with any Related Person (a beneficial owner of 10 percent or
more of the outstanding voting stock of the Company) or any Business
Transaction in which a Related Person has an interest; provided, that the 80
percent voting requirement is not applicable if the Continuing Directors
(Directors who are unaffiliated with, and are not nominees of, the Related
Person involved in the Business Transaction) of the Company by at least a
majority vote thereof have (i) expressly approved in advance the acquisition
of the outstanding shares of voting stock that caused such Related Person to
become a Related Person, or (ii) expressly approved such Business
Transaction. Article Sixth of the Company's Restated Articles of
Incorporation also provides that the 80 percent voting requirement is not
required for a Business Transaction involving a Related Person if the
following conditions are satisfied: (a) the cash or fair market value or
other consideration to be received per share by holders of voting stock of
the Company in the Business Transaction is not less than the highest purchase
price paid by the Related Person involved in the Business Transaction in
acquiring any of its holdings of the Company's voting stock; (b) the ratio of
the amount of cash and other consideration to be received per share by
holders of Common Stock in such Business Transaction to the market price of
the Common Stock immediately prior to the announcement of such Business
Transaction is at least as great as the ratio of the highest per share price
paid by the Related Person for any shares of Common Stock acquired by it to
the market price of the Common Stock immediately prior to the initial
acquisition by such Related Person of any Common Stock; and (c) the
consideration to be received by holders of each class of capital stock of the
Company in such Business Transaction is the same form and of the same kind as
the consideration paid by the Related Person in acquiring the shares of that
class of capital stock already owned by it. Article Sixth cannot be amended
or repealed without the affirmative vote of the holders of at least 80
percent of the Common Stock of the Company.
Takeover Act--Business Combination Provisions. The Takeover Act
provides that certain domestic public corporations (including the Company)
shall not engage at any time in any business combination (a merger, transfer
of ten percent of the Company's assets, issuance or transfer of stock equal
to 5 percent of the aggregate market value of all outstanding shares of the
Company, the adoption of a plan of liquidation or dissolution or other
similar transaction) with any interested shareholder (the beneficial owner or
an affiliate of a beneficial owner of ten percent or more of the Company's
voting shares) unless (i) the Board of Directors of the Company, prior to the
interested shareholder becoming an interested shareholder, approves either
the business combination or the acquisition of shares by the interested
shareholder which causes it to become an interested shareholder, (ii) subject
to the fair price requirements discussed below, the business combination is
approved by the affirmative vote of the holders of a majority of the
outstanding voting shares, not including any voting shares beneficially owned
by the interested shareholder, at a meeting called for such purpose at such
time as the interested shareholder beneficially owns 80 percent of the voting
shares of the Company and not earlier than 3 months after the interested
shareholder became the beneficial owner of 80 percent of the voting shares of
the Company, (iii) the business combination is approved by the affirmative
vote of the holders of all of the outstanding voting shares of the Company,
(iv) the business combination is approved by the affirmative vote of the
holders of a majority of the outstanding voting shares of the Company, not
including any voting shares beneficially owned by the interested shareholder,
at a meeting called for such purpose no earlier than four years after the
interested shareholder became an interested shareholder, or (v) subject to
the fair price requirements discussed below, the business combination is
approved by a majority of the outstanding voting shares at a shareholders'
meeting called for such purpose no earlier than 4 years after the interested
shareholder became an interested shareholder.
Takeover Act--Fair Price Provisions. The Takeover Act provides for a
fair price provision for business combinations approved pursuant to (ii) or
(v) of the preceding paragraph. Business combinations approved by
shareholders of the Company pursuant to the requirements of (ii) or (v) of
the preceding paragraph must meet certain conditions which require, among
other things, that the value of the consideration received per share by
holders of outstanding shares of Common Stock in the business combination
must be at least equal to the higher of (i) the price per share paid for any
shares of Common Stock acquired by the interested shareholder within the
three-year period immediately prior to (a) the announcement of the business
combination or (b) the transaction in which the interested shareholder became
an interested shareholder, whichever is higher, or (ii) the market value per
share of Common stock on the announcement date with respect to the business
combination or the date on which the interested shareholder became an
interested shareholder, whichever is higher.
Takeover Act--Board May Protect Other Constituencies and Consider Long-
Term Interests. The Takeover Act further allows the Board of Directors of
the Company in determining whether to approve a merger or other change of
control to take into account both the long-term as well as short-term
interests of the Company and its shareholders, the effect on the Company's
employees, customers, creditors and suppliers, the effect upon the community
in which the Company operates and the effect on the economy of the state and
nation.
Proposed Resolution
To cause the Control Share Acquisition provisions of the Takeover Act
not to apply to any Control Share Acquisition occurring after the adoption of
the Resolution, the following Resolution will be submitted to the
shareholders:
BE IT RESOLVED by the shareholders of Black Hills Corporation
that Article Fourth of the Company's Restated Articles of
Incorporation be amended by adding thereto the following paragraph
8:
8. The provisions of South Dakota Codified Laws Sections 47-33-8
through 47-33-16, inclusive, do not apply to control share
acquisitions (as defined by South Dakota Codified Laws Section
47-33-3(1)) of shares of the Company.
Vote Required
The affirmative vote of the holders of the majority of all issued and
outstanding shares of common stock is required to adopt the foregoing
resolution.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE
FOR THE ADOPTION OF THE RESOLUTION
<PAGE>
ITEM IV
APPOINTMENT OF INDEPENDENT AUDITORS
The firm of Arthur Andersen & Co., independent public accountants,
conducted the audit of the Company and its subsidiaries for 1993.
Representatives of Arthur Andersen & Co. will be present at the Annual
Meeting and will have the opportunity to make a statement, if they desire to
do so, and to respond to appropriate questions.
Audit services performed by Arthur Andersen & Co. during 1993 included
examinations of the financial statements of the Company and its subsidiaries
and limited reviews of interim financial information.
The Board of Directors, on recommendation of the Audit Committee and
subject to ratification by shareholders, has appointed Arthur Andersen & Co.
to perform an examination of the consolidated financial statements of the
Company and its subsidiaries for the year 1994 and to render their opinion
thereon.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR RATIFICATION
OF THE APPOINTMENT OF ARTHUR ANDERSEN & CO. TO SERVE AS
INDEPENDENT PUBLIC ACCOUNTANTS FOR THE YEAR 1994
SHAREHOLDER PROPOSALS FOR 1995 ANNUAL MEETING
Stockholder proposals intended to be presented at the 1995 Annual
Meeting of Shareholders must be received by the Secretary of the Company in
writing at its home offices at 625 Ninth Street, P.O. Box 1400, Rapid City,
South Dakota 57709, prior to November
26, 1994. Any proposal submitted must be in compliance with Rule 14a-8 of
Regulation 14A of the Securities and Exchange Commission.
<PAGE>
ITEM V
TRANSACTION OF OTHER BUSINESS
The Board of Directors does not intend to present any business for
action by the shareholders at the meeting except the matters referred to in
this Proxy Statement. If any other matters should be properly presented at
the meeting, it is the intention of the persons named in the accompanying
form of proxy to vote thereon in accordance with the recommendations of the
Board of Directors.
If a stockholder participates in the Company's Dividend Reinvestment and
Stock Purchase Plan, the proxy to vote shares of record will serve as
instructions to vote shares held in custody for the stockholder.
Accordingly, as Transfer Agent for shares of the Company's Common Stock,
Chemical Bank will cause shares held in the name of its nominee for the
account of a stockholder participating in the Plan to be voted in the same
way as that stockholder votes shares registered in their name. If
shareholders do not vote the shares registered in their name, shares held for
their account in the Plan will not be voted.
Please complete and sign the accompanying form of proxy whether or not
you expect to be present at the meeting and promptly return it in the
enclosed postage paid envelope.
By Order of the Board of Directors
ROXANN R. BASHAM
Corporate Secretary
Dated: March 25, 1994
<PAGE>
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The information required by Item 13, Financial and Other Information, of
Regulation 14-A is provided in the Company's Annual Report on Form 10-K for
the year ended December 31, 1993, which is incorporated by reference into
this Proxy Statement.
The Company hereby undertakes to provide to each shareholder whose proxy
is solicited for the 1994 Annual Meeting, upon written or oral request and
without charge, a copy of the Company's 1993 Annual Report on Form 10-K
(without exhibits) to the Securities and Exchange Commission. Requests
should be directed to Roxann R. Basham, Corporate Secretary and Treasurer,
Black Hills Corporation, P.O. Box 1400, Rapid City, SD 57709, or telephone
(605)-348-1700.
PLEASE COMPLETE, SIGN AND RETURN PROMPTLY
THE ENCLOSED PROXY SO THAT YOUR STOCK MAY
BE REPRESENTED AND VOTED AT THE ANNUAL MEETING.
<PAGE>
DRAFT PROXY CARD
Front of Proxy Card
BLACK HILLS CORPORATION
625 NINTH STREET
RAPID CITY, SOUTH DAKOTA 57701
THIS PROXY IS SOLICITED BY THE BOARD OF DIRECTORS
FOR USE AT THE ANNUAL MEETING OF STOCKHOLDERS OF THE COMPANY
TO BE HELD MAY 24, 1994 AT 9:30 A.M.
The undersigned hereby appoints Daniel P. Landguth, Dale E. Clement, and
David E. Morrill, and any one or more of them, proxy attorneys, with full
substitution and revocation in each, for and on behalf of the undersigned,
and with all powers the undersigned would possess if personally present, to
vote at the above Annual Meeting and any adjournment thereof all shares of
Common Stock of Black Hills Corporation that the undersigned would be
entitled to vote at such meeting.
PLEASE MARK THIS PROXY AS INDICATED ON THE REVERSE SIDE TO VOTE ON ANY
ITEM. IF YOU WISH TO VOTE IN ACCORDANCE WITH THE BOARD OF DIRECTORS'
RECOMMENDATION, PLEASE SIGN THE REVERSE SIDE; NO BOXES NEED TO BE CHECKED.
COMMENTS/ADDRESS CHANGE: PLEASE MARK COMMENT/ADDRESS BOX ON REVERSE SIDE
(Continued and to be signed on other side)
Back of Proxy Card X Please mark your votes this way
__________ ____________________________
COMMON DIVIDEND REINVESTMENT SHARES
The Board of Directors recommends a vote FOR Items 1,2,3 and 4.
WITHHELD
FOR FOR ALL
Item 1-ELECTION OF CLASS II DIRECTORS
Nominees:
Daniel P. Landguth
Dale E. Clement
John R. Howard
WITHHELD FOR: (Write that nominee's name in the
space provided below). (To cumulate votes so indicate)
FOR AGAINST ABSTAIN
Item 2-INCREASE THE COMPANY'S AUTHORIZED
INDEBTEDNESS
Item 3-AMEND ARTICLE FOURTH OF THE
COMPANY'S RESTATED ARTICLES OF INCORPORATION
Item 4-RATIFY THE APPOINTMENT OF ARTHUR
ANDERSEN & CO. TO SERVE AS THE COMPANY'S
INDEPENDENT AUDITORS IN 1994
Item 5-PROXY ATTORNEYS ARE AUTHORIZED AT
THEIR DISCRETION TO VOTE UPON SUCH OTHER
BUSINESS AS MAY PROPERLY COME BEFORE THE
MEETING
I PLAN TO ATTEND MEETING
If you check this box to the right
an admission card will be sent to you.
COMMENTS/ADDRESS CHANGE
Please mark this box if you have
written comments/address change on the
reverse side
Black Hills Corporation, as Administrator under the Company's Dividend
Reinvestment and Stock Purchase Plan, is instructed to execute a proxy with
identical instructions, for any shares held for my benefit.
Signature(s) Date ____________________
Please mark, date and sign as your account name appears and return in the
enclosed envelope. If acting as executor, administrator, trustee, guardian,
etc., you should indicate same when signing. If the signer is a corporation
or partnership, please sign the full corporate or partnership name by
authorized officer or person. If shares are held jointly, each stockholder
should sign.
<PAGE>
EXHIBIT INDEX
EX-13.A 1993 FORM 10-K (DRAFT FORM ONLY)
EX-13.B 1993 FINANCIAL SECTION OF ANNUAL REPORT (DRAFT FORM ONLY)
<PAGE>
DRAFT SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ___________ to ___________
Commission file Number 1-7978
BLACK HILLS CORPORATION
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57709
Registrant's telephone number, including area code
(605) 348-1700
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common stock of $1.00 par value New York Stock Exchange
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
State the aggregate market value of the voting stock held by non-affiliates
of the Registrant.
At February 28, 1994 $305,709,166
Indicate the number of shares outstanding of each of the Registrant's classes
of common stock, as of the latest practicable date.
CLASS OUTSTANDING AT FEBRUARY 28, 1994
Common stock, $1.00 par value 14,277,277 shares
DOCUMENTS INCORPORATED BY REFERENCE
1. Pages 13 through 34 of the Annual Report to Stockholders of the
Registrant for the year ended December 31, 1993, are incorporated
by reference in Part I and Part II and appended hereto.
2. Definitive Proxy Statement of the Registrant filed pursuant to
Regulation 14A for the 1994 Annual Meeting of Stockholders to be
held on May 24, 1994, is incorporated by reference in Part III.
<PAGE>
TABLE OF CONTENTS
Page
ITEM 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GENERAL . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ELECTRIC POWER SALES AND SERVICE TERRITORY. . . . . . . . . . .
Electric Power Sales--Retail . . . . . . . . . . . . . . . .
Retail Electric Service Territory. . . . . . . . . . . . . .
Electric Sales--Wholesale. . . . . . . . . . . . . . . . . .
Future Wholesale Opportunities . . . . . . . . . . . . . . .
ELECTRIC POWER SUPPLY . . . . . . . . . . . . . . . . . . . . .
General. . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . .
Pacific Power Colstrip Contract. . . . . . . . . . . . . . .
Tri-State Contract . . . . . . . . . . . . . . . . . . . . .
Reserve Capacity Integration Agreement . . . . . . . . . . .
Sunflower Agreement. . . . . . . . . . . . . . . . . . . . .
Neil Simpson Unit #2 . . . . . . . . . . . . . . . . . . . .
RATE REGULATION . . . . . . . . . . . . . . . . . . . . . . . .
Guarantee of the Construction Costs of Neil Simpson Unit
#2. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Regulatory Conditions of Approving Neil Simpson Unit
#2. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1995 Rate Cases. . . . . . . . . . . . . . . . . . . . . . .
South Dakota Regulation. . . . . . . . . . . . . . . . . . .
Wyoming--Retail. . . . . . . . . . . . . . . . . . . . . . .
Montana. . . . . . . . . . . . . . . . . . . . . . . . . . .
Wyoming--Wholesale . . . . . . . . . . . . . . . . . . . . .
COMPETITION IN ELECTRIC UTILITY BUSINESS. . . . . . . . . . . .
Competition in Service at Retail . . . . . . . . . . . . . .
Competition in Electric Generation . . . . . . . . . . . . .
Transmission Access. . . . . . . . . . . . . . . . . . . . .
Price Competition. . . . . . . . . . . . . . . . . . . . . .
CONSTRUCTION AND CAPITAL PROGRAMS . . . . . . . . . . . . . . .
Black Hills Power. . . . . . . . . . . . . . . . . . . . . .
Financing Neil Simpson Unit #2 . . . . . . . . . . . . . . .
Wyodak Resources . . . . . . . . . . . . . . . . . . . . . .
Western Production . . . . . . . . . . . . . . . . . . . . .
<PAGE>
TABLE OF CONTENTS (CONT.)
Page
COAL SALES. . . . . . . . . . . . . . . . . . . . . . . . . . .
Contract to Supply Coal to Neil Simpson Unit #2. . . . . . .
Other Sales. . . . . . . . . . . . . . . . . . . . . . . . .
OIL AND GAS OPERATIONS. . . . . . . . . . . . . . . . . . . . .
Size and Competition . . . . . . . . . . . . . . . . . . . .
Markets and Sales. . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Activity. . . . . . . . . . . . . . . . . . . . . .
ENVIRONMENTAL REGULATION. . . . . . . . . . . . . . . . . . . .
Air Quality . . . . . . . . . . . . . . . . . . . . . . . . .
Emission Limitations at Neil Simpson Unit #2 . . . . . . .
Emissions from Other Plants. . . . . . . . . . . . . . . .
Asbestos . . . . . . . . . . . . . . . . . . . . . . . . .
The Clean Air Act Amendments . . . . . . . . . . . . . . .
Air Allowances . . . . . . . . . . . . . . . . . . . . . .
New Major Emitting Facilities. . . . . . . . . . . . . . .
Water Quality. . . . . . . . . . . . . . . . . . . . . . . .
Land Quality . . . . . . . . . . . . . . . . . . . . . . . .
Solid Waste Disposal. . . . . . . . . . . . . . . . . . . . .
Reclamation. . . . . . . . . . . . . . . . . . . . . . . .
General. . . . . . . . . . . . . . . . . . . . . . . . . . .
PCB's. . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Releases . . . . . . . . . . . . . . . . . . . . . . .
Underground Storage Tanks. . . . . . . . . . . . . . . . .
Ben French Oil Spill . . . . . . . . . . . . . . . . . . .
Mush Creek Cleanup . . . . . . . . . . . . . . . . . . . .
Electromagnetic Fields . . . . . . . . . . . . . . . . . . .
Summary. . . . . . . . . . . . . . . . . . . . . . . . . . .
EMPLOYEES . . . . . . . . . . . . . . . . . . . . . . . . . . .
CORPORATE DEVELOPMENT . . . . . . . . . . . . . . . . . . . . .
ITEM 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . .
UTILITY PROPERTIES. . . . . . . . . . . . . . . . . . . . . . .
MINING PROPERTIES . . . . . . . . . . . . . . . . . . . . . . .
OIL AND GAS PROPERTIES. . . . . . . . . . . . . . . . . . . . .
ITEM 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . .
<PAGE>
TABLE OF CONTENTS (CONT.)
Page
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE COMPANY . . . . . . . . . . . . . . .
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . . . . .
ITEM 6. SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . . .
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . . . . . .
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . .
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . .
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. . . . . . .
ITEM 11. EXECUTIVE COMPENSATION. . . . . . . . . . . . . . . . . . . . .
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT. . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. . . . . . . . .
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . . . . .
<PAGE>
DEFINITIONS
When the following terms are used in the text they will have the meanings
indicated.
Term Meaning
Black Hills Power Black Hills Power and Light Company, the assumed
business name of the Company under which its
electric operations are conducted
Basin Electric Basin Electric Power Cooperative, Inc., a rural
electric cooperative engaged in generating and
transmitting electric power to its member RECs
Company Black Hills Corporation
DEQ Department of Environmental Quality of the State of
Wyoming
EAFB Ellsworth Air Force Base, a military air force base
near Rapid City, South Dakota
FERC Federal Energy Regulatory Commission
Indenture Indenture of Mortgage and Deed of Trust of the
Company
Neil Simpson Unit #1 A 20 megawatt coal-fired electric generating plant
owned by the Company and located adjacent to the
Wyodak Plant
Neil Simpson Unit #2 An 80 MW coal-fired power plant the Company now has
under construction at the site of the Wyodak Plant
and the Neil Simpson Unit #1
Pacific Power PacifiCorp, which operates its electric utility
operations under the assumed names of Pacific Power
& Light Company and Utah Power & Light Company
RECs Rural electric cooperatives, which are owned by
their customers and which rely primarily on the
Rural Electrification Administration of the United
States for their financing needs
SDPUC The South Dakota Public Utilities Commission
WAPA Western Area Power Administration of the Department
of Energy of the United States of America
WPSC The Wyoming Public Service Commission
Western Production Western Production Company, a wholly owned
subsidiary of Wyodak Resources
Wyodak Resources Wyodak Resources Development Corp., a wholly owned
subsidiary of the Company
Wyodak Plant A 330 megawatt coal-fired electric generating plant
which is owned 20 percent by the Company and 80
percent by Pacific Power and located near Gillette,
Wyoming
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL
The Company was incorporated under the laws of South Dakota in 1941
under the name Black Hills Power and Light Company. In 1986 the Company
changed its name to Black Hills Corporation and now operates its investor-
owned electric public utility operations under the assumed name of Black
Hills Power and Light Company. In addition the Company has diversified into
coal mining through Wyodak Resources and into oil and gas production through
Western Production.
Black Hills Power is engaged in the generation, purchase, transmission,
distribution and sale of electric power and energy to approximately 53,330
customers in 11 counties in western South Dakota, northeastern Wyoming and
southeastern Montana. The territory served by Black Hills Power includes 20
incorporated communities and various unincorporated and rural areas with a
population estimated at 165,000. The largest community served is Rapid City,
South Dakota, with a population, including environs, estimated at 75,000.
Rapid City is the major retail, wholesale and health care center for a
250-mile radius. Principal industries in the territory served are tourism
(including small stake casino gambling at Deadwood), cattle and sheep
raising, farming, milling, meat packing, lumbering, the production of cement,
the mining of bentonite, stone, gravel, silica sand, gold, silver, coal and
other minerals, the manufacture of electronic products, wood products and
gold jewelry, and the production and refining of oil. Black Hills Power
serves a substantial portion of the electric needs of the Black Hills tourist
region which includes the National Shrine of Democracy, Mount Rushmore
National Memorial and the Crazy Horse Memorial, a large granite mountain
carving under construction as a memorial to native Americans and one of their
leaders. Tourism has been and is expected to continue to be enhanced
significantly by the establishment of small stakes casino gambling at
Deadwood, South Dakota, which is a part of Black Hills Power's service
territory. Although only a small portion of EAFB is served by Black Hills
Power, EAFB forms a significant economic base for the territory served.
Wyodak Resources, incorporated under the laws of Delaware in 1956, is
engaged in the mining and sale of sub-bituminous coal. The coal mining
operation is located approximately five miles east of Gillette, Wyoming.
In 1986, Wyodak Resources acquired all of the outstanding capital stock
of Western Production, an oil and gas exploration, producing and operating
company incorporated under the laws of Wyoming. Western Production is an oil
producing and operating company with interests located in the Rocky Mountain
Region and Texas. Western Production also has a partial interest in a
natural gas processing plant.
Information as to the continuing lines of business of the Company for
the calendar years 1991-1993 is as follows:<PAGE>
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
Revenue from sales to unaffiliated customers:
<S> <C> <C> <C>
Electric $97,885 $97,232 $97,922
Coal mining 19,775 18,485 16,918
Oil and gas production 11,396 9,599 9,077
Revenue from intercompany sales:
Electric $ 270 $ 216 $ 236
Coal mining 10,047 9,811 9,220
</TABLE>
Reference is made to the Consolidated Statements of Income and Note 11
of "Notes to Consolidated Financial Statements" appended hereto.
ELECTRIC POWER SALES AND SERVICE TERRITORY
Electric Power Sales--Retail. Even though Black Hills' service area
again experienced milder than normal summer weather, Black Hills Power's firm
kilowatt hour sales increased in 1993 by 3.5 percent over 1992. The increase
in energy sales is largely due to an increase in the number of customers and
their use of electricity. Firm energy sales are forecast to increase over
the next ten years at an annual compound growth rate of approximately 2.5
percent. During the next ten years the peak system demand is forecast to
increase at an annual compound growth rate of 2.6 percent. These forecasts
are from studies conducted by Black Hills Power with the help of outside
consultants whereby the service territory of Black Hills Power is carefully
examined and analyzed to estimate changes in the needs for electrical energy
and demand over a 20-year period. These forecasts are only estimates, and
the actual changes in electric sales may be substantially different. In the
past Black Hills Power's forecasts have tracked actual sales within a band of
reasonable performance.
Electric sales are materially affected by weather. Like 1992, Black
Hills Power's electric service territory again experienced a cool summer in
1993, resulting in degree days that were 59 percent lower than normal for the
1993 summer months. Consequently, energy sales and peak demand were
substantially less during the cooling season than they would have been in a
normal weather year.
Retail Electric Service Territory. Black Hills Power's service
territory is currently protected by assigned service area and franchises that
generally grant to Black Hills Power the exclusive right to sell all electric
power consumed therein, subject to providing adequate service. See--
COMPETITION IN ELECTRIC UTILITY BUSINESS--Competition in Service at Retail
under this Item 1.
At the end of 1993, Black Hills served electric energy to 53,330
customers in a population island that includes the major population centers
of the Black Hills area in western South Dakota and northeastern Wyoming and
a small oil field in southeastern Montana. (See--GENERAL under this Item 1
for a general description of the service territory.)
Black Hills Power's electric service territory is experiencing modest
business and population growth. In 1993 the value of commercial building
permits in Rapid City increased by 91 percent, and residential building
permits increased 10.5 percent. South Dakota's unemployment rate in 1993
averaged 3.4 percent. Personal income in South Dakota increased 7.3 percent
in 1993 and visitor spending in South Dakota increased by 14 percent.
The Company believes that this growth in its electric service territory
will continue; however, the Company can give no assurances. One of the major
employers in the Rapid City area is the United States Defense Department's
EAFB. EAFB is a military air force base near Rapid City, South Dakota. Its
current mission is to serve as the training, operation and maintenance base
for the Air Force's B-1 bombers. There are now stationed at EAFB 30 B-1
bombers, out of the Defense Department's total of 96 B-1s, of which 80 are
operational.
Black Hills Power does not provide electric service to EAFB. However,
currently EAFB employs approximately 5,200 military and 600 civilian
personnel. In addition to these direct employees, additional nongovernmental
employees residing in Rapid City and the surrounding area depend upon the
continual operation of EAFB. Many of the persons with these jobs reside in
the service territory of Black Hills Power. Many businesses in Black Hills
Power's service territory are at least partially dependent upon the
operations at EAFB. The exact economic impact from a closing of EAFB on
Black Hills Power's electric sales cannot be estimated. While the impact
would be felt, there are other businesses that would not be affected and are
experiencing growth for other reasons in Black Hills Power's electric service
territory.
While the future of EAFB is not certain, management believes that the
mission of EAFB assures that the base will continue. Emphasis on reducing
the budget deficit and the deemphasis of military spending are expected to
result in additional military base closings. The independent commission that
recommends base closings is expected to make its recommendations in 1995 for
the next base closings. If the United States Congress or the Administration
does not interfere with those recommendations, those bases as recommended for
closing are expected to be subsequently closed. There are many criteria used
by the independent commission in making its decision, but three of the most
important considerations are the strategic importance of the mission of the
base, civilian encroachments interfering with the safe operation of the base,
and the amount and timing of the savings or payback to the government
resulting from such closings. EAFB personnel have been complaining about
certain civilian business and housing encroachments to the flight line of the
base. The City of Box Elder and the State of South Dakota are expected to
take corrective action to satisfy those complaints, but no assurances can be
given that the encroachments will be eliminated. Box Elder has already
placed a moratorium on new buildings in the encroachment zone. Because of
the large number of employees at EAFB and the cost of maintaining EAFB, a
large savings would result to the Department of Defense from the closing.
The Company believes, however, that the strategic mission of the base (the
training, maintenance and operation of the B-1 bombers) and the open, low-
populated area in western South Dakota and eastern Wyoming that is available
for practicing bombing runs along with strong community support of the base
should result in no EAFB closing. This may depend, however, upon the
continual support by the Department of Defense and Congress of the B-1 bomber
program. Due to cost overruns and failures of some tactical ancillary
equipment along with debates on the need for long-range bombing capability in
light of the end of the cold war have caused the B-1 bomber program to be
somewhat controversial. This controversy has led to a decision to run the
B-1 through extensive tests during 1994. EAFB has announced that those tests
will be conducted at EAFB.
Currently the Clinton Administration's budget provides for the Air Force
to maintain an active, operational B-1 bomber fleet of 50. A fleet of 50 is
believed to require the B-1s to be operated from two bases. The current Air
Force plan is to base its operational B-1s only at EAFB and Dyess Air Force
Base, Texas.
The EAFB receives strong support from the Black Hills communities and
the State of South Dakota and is the only major military establishment of the
Department of Defense located in South Dakota. For all of these reasons, the
Company believes that the EAFB will survive the next round of base closings,
but the Company can give no assurances.
Two other major industries in Black Hills' service territory suffering
some stress are the lumbering industry and gold mining industry. The
lumbering industry has already suffered substantial cutbacks due to
government cutbacks in timber harvesting. Some impact has already occurred.
The gold mining industry, including Homestake Mining Company (representing
11.8 percent of Black Hills' total firm KWH sales in 1993 and 8.2 percent of
firm electric sales revenue) depends largely upon the price of gold and
continuing to find economically minable ore reserves. Homestake has
gradually over the years reduced the number of employees, and this impact has
substantially occurred. Homestake recently abandoned a deep exploration
program 6,000 feet underground to a location north of its present mine to
locate another ore body that would have economically justified the
construction of another shaft and the extension of the underground mine for
several years. However, Homestake did recently report the discovery of some
additional deep reserves at its present underground mining location below the
7,000-foot level. Unless a substantial reduction in the current price of
gold occurs, the Company believes that the gold mining industry will be
stable in the Black Hills area for at least the next ten years; however, the
life of mines cannot be predicted, and no assurances can be given.
The new industry of low stakes casino gambling at Deadwood (located in
Black Hills Power's service territory) continues to experience modest growth
despite the South Dakota voters' rejection of raising the $5 betting limit to
$100.
The Black Hills area continues to attract new small businesses and
retirees who are attracted by a quality place to live.
Electric Sales--Wholesale. At this time the only firm wholesale
customer of Black Hills Power is the municipal electric system at Gillette,
Wyoming. Service is rendered under a long-term contract expiring July 1,
2012 wherein Black Hills Power undertakes the obligation to serve the City of
Gillette 60 percent of its highest demand and that associated energy as if
the demand served by Black Hills Power was always Gillette's first demand.
The agreement also allows Gillette to obtain the benefits of a 4,000 KW
average firm power purchase agreement from WAPA. Gillette's highest demand
to date is 38.78 MW, making Black Hills' current base load obligation to
serve 23 MW. The most recent average yearly capacity factor of this 23 MW
demand has been approximately 80 percent. Revenue from sales to Gillette
represented 8 percent of revenue from total sales in 1993.
Black Hills Power is further obligated to serve the next increment of
10 MW of Gillette's demand above 33 MW if Gillette is unable to obtain other
sources. Subject to certain emergency conditions, once Black Hills Power
serves a full increment of another 10 MW, that increment is added to Black
Hills Power's firm obligation to serve. When Gillette serves 10 MW, 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 MW increment of capacity to Gillette.
Other than this firm sale to the City of Gillette, Black Hills Power has
made only minimal energy sales to other utilities.
Future Wholesale Opportunities. Black Hills Power has not had
sufficient surplus resources in the past to effectively engage in the
wholesale electric market. Therefore, to date Black Hills Power has not
developed any wholesale markets other than the Gillette sale. If utility
retail sales do not increase as expected, the addition of Neil Simpson Unit
#2 may result in surplus power and energy. In that event, Black Hills Power
would explore all possible avenues to sell that surplus power. Due to the
inability to serve firm power to the east of Black Hills Power's service
territory without high-cost AC-DC-AC converter stations because of the
incompatibility of the east and west transmission systems, Black Hills
Power's opportunities for wholesale sales are restricted to the western
system. Black Hills Power maintains two firm interconnections to the western
system, one with WAPA's western transmission system at Stegall, Nebraska and
one with Pacific Power's transmission system at the Wyodak Plant. These two
interconnections give Black Hills Power the potential ability to sell power
wholesale to any utility entity in the western part of the United States if
transmission charges are paid. See--COMPETITION IN ELECTRIC UTILITY BUSINESS
- --Transmission Access under this Item 1.
Whether physical transmission limitations exist that would restrict such
sales by Black Hills Power is unknown for any particular sale, but Black
Hills Power believes that the western transmission system is adequate at this
time to accommodate the relatively small sale of wholesale power required for
Black Hills Power to sell any surplus resulting from Neil Simpson Unit #2.
The revenue received from such a sale would depend on transmission costs, the
type of sale Black Hills Power would make (i.e., firm long-term or short-
term, capacity sale with minimum energy or base load sale with maximum
energy, unit power from Neil Simpson Unit #2 only or system power with
reserves), and the competitive market at the time such sale is made. The
needs of Black Hills to serve its present retail and wholesale commitments
and the regulatory treatment of Neil Simpson Unit #2 will govern the type of
power and energy sale Black Hills Power would be able to make. All of these
conditions are unknown at this time, but Black Hills Power will be carefully
studying these conditions as the operating date for Neil Simpson Unit #2
approaches.
ELECTRIC POWER SUPPLY
General. In 1993 Black Hills Power retired three 5 MW low-pressure
units at the Kirk Station. Obsolescence and high costs of operation made
these units no longer economical to operate and maintain.
Black Hills Power owns generation with a nameplate rating totalling
283.21 MW. See--UTILITY PROPERTIES under Item 2.
Black Hills Power also purchases electric power from other entities.
See--Pacific Power Colstrip Contract, Tri-State Contract, Reserve Capacity
Integration Agreement, and Sunflower Agreement following.
Reserves. Black Hills Power is not a member of a power pool. To meet
its reserve margin, Black Hills Power utilizes the criteria established by
the Western System Coordinating Council, a voluntary technical review and
standard setting association composed of all electric utilities in the
western United States. This criteria generally requires resources in reserve
that are capable of (i) replacing the most severe single contingency,
(ii) plus 5 percent of the utility's firm load responsibilities without firm
purchased power and (iii) an allowance for auxiliary operations for the lost
generator. Currently the most severe single contingency for Black Hills
Power is the loss of its 20 percent interest in the 330 MW Wyodak Plant.
Neil Simpson Unit #2 with a normal capability of 80 MW will be Black Hills
Power's largest generation resource when it comes into commercial operation
in late 1995 or early 1996 and, therefore, the most severe single
contingency.
Generating plants' capabilities to generate power will change depending
on ambient air temperatures. Generally, a power plant's net output
capability is higher in the winter and lower in the summer. Therefore, the
reserve margin, the loss of the largest unit, is less in summer (because the
unit generates less power) than in the winter. One reserve margin test is to
determine the reserve margin based on a summer rating, a time when generators
are producing less power and the utilities' requirements are at their peak.
The following chart illustrates a Black Hills Power estimated summer
rating reserve calculation for 1994 as compared to 1996 when Neil Simpson
Unit #2 is expected to be in commercial operation.
<PAGE>
<TABLE>
Reserve Analysis--Estimated
(1)Net Dependable Capability--
Summer Rating
<CAPTION>
1994 1996
Base Load Resources kilowatts kilowatts
<S> <C> <C>
Osage Station--3 units 30,450 30,450
Kirk Plant 16,100 16,100
Ben French Station--Coal unit 21,600 21,600
Neil Simpson Unit #1 14,600 14,600
Wyodak Plant (20%) 59,000 59,000
Neil Simpson Unit #2 (4)72,000
Pacific Power Colstrip Contract 75,000 75,000
Tri-State Contract(2) 20,000
Total Base Load Resources 236,750 288,750
Peaking Resources
Ben French Station
--Combustion Turbines 67,200 67,200
--Diesel Units 10,000 10,000
Pacific Reserve Integration
Agreement 32,800 32,800
Sunflower Peaking Contract(3) 40,000
Total Peaking Resources 150,000 110,000
Total Base Load and Peaking
Resources 386,750 398,750
Less: Reserves 71,000 82,000
Resources to Serve Load, less
reserves 315,750 316,750
_________________________
<FN>
(1)See--UTILITY PROPERTIES under Item 2 for the nameplate rating of Black
Hills Power's generating resources.
(2)Tri-State contract can be extended for 40 MW of firm capacity and energy
to December 31, 1997. Black Hills Power can cancel agreement for 1996.
(3)Sunflower contract expires September 30, 1996.
(4)This assumes Neil Simpson Unit #2 is in production in 1996.
</TABLE>
<PAGE>
Pacific Power Colstrip Contract. Additional base load power was
acquired by Black Hills Power through a 40-year purchased power agreement
executed in 1983 with Pacific Power. The agreement provides that Black Hills
Power purchase from Pacific Power 75 megawatts of electric power and
associated energy until December 31, 2023. The price for the power and
energy is based on Pacific Power's annual levelized fixed cost and variable
cost in Units 3 and 4 of the Colstrip coal-fired generating plant located
near Colstrip, Montana and a fixed payment for transmission. Although Black
Hills Power's payments are based upon Units 3 and 4, Pacific Power has agreed
to deliver the power and energy from its system, notwithstanding the
operational capabilities of Units 3 and 4, at a load factor varying from a
minimum of 41 percent to a maximum of 80 percent as scheduled monthly by
Black Hills Power. Under the agreement, Black Hills Power would not be
obligated to pay capacity and energy charges for power not delivered because
of a default by Pacific Power in delivering electric power. The Company has
incurred capacity charges of $18,000 to $19,000 per megawatt month and $13
per megawatt hour over the last three years of this agreement. The Company's
load factor related to this contract has been approximately 68 percent over
the last three years. The energy purchased under this agreement in 1993 was
approximately 23 percent of Black Hills Power's expected total requirements.
See RATE REGULATION under this Item 1.
Tri-State Contract. In 1992 Black Hills Power entered into a firm
capacity and energy purchase agreement under which Tri-State Generation and
Transmission Association, Inc., a rural electric cooperative headquartered in
Colorado, has agreed to supply Black Hills Power 20 megawatts of firm
capacity and associated energy up to a 75 percent capacity factor commencing
October 1, 1993 and continuing to December 31, 1997 for a capacity charge of
$8,400 per megawatt month and $16 per megawatt hour. Black Hills Power has
the option to be exercised by September 1, 1995 to terminate the contract at
a date earlier, but not before December 31, 1995, if Black Hills Power
anticipates that Neil Simpson Unit #2 will commence commercial operations at
the time of termination. Black Hills Power further has the option to
purchase an additional 20 MW up to December 31, 1997 at a capacity charge of
$8,900 per megawatt month if a one-year notice is given and $9,400 per
megawatt month if a six-month notice is given.
Reserve Capacity Integration Agreement. Black Hills Power entered into
a reserve capacity integration agreement in 1987 with Pacific Power under the
terms of which for a period of 25 years Pacific Power shall have the right to
schedule power that is produced from Black Hills Power's four 25 megawatt
combustion turbines; and in return Pacific Power shall make available to
Black Hills Power during the 25 years, at Black Hills Power's option, 100
megawatts of reserve capacity from Pacific Power's system. Black Hills Power
shall have the right to schedule power from this reserve only at such times
when Black Hills Power, under prudent utility practice, would have operated
the combustion turbines. At such times that Black Hills Power schedules
Pacific Power's reserves, it has agreed to pay (i) Pacific Power's
incremental costs of generation (largely the cost of coal) from a Pacific
Power coal-fired plant operating as of the time of the schedule or (ii) the
cost of fuel (oil or natural gas) for the combustion turbines, whichever is
lower in price. Notwithstanding Pacific Power's rights to the combustion
turbines, Black Hills Power reserves a prior right to schedule power from the
combustion turbines if required to serve its customers because of
transmission outages or low voltage conditions. The agreement further
requires Pacific Power to pay the operation and maintenance expenses of the
combustion turbines, except for property taxes and insurance, during the 25
years, and pay Black Hills Power $50,000 per month for the entire 25-year
period. This reserve integration agreement was a part of the PacifiCorp
Settlement as outlined in the "Management's Discussion and Analysis of
Financial Condition and Results of Operations" of the Annual Report to
Shareholders of the Company for the year ended December 31, 1993, on pages 14
through 20, incorporated herein by reference.
Sunflower Agreement. In 1993 Black Hills Power entered into a Peaking
Capacity Agreement with Sunflower Electric Power Cooperative ("Sunflower"),
a rural electric cooperative headquartered in Kansas. Sunflower agreed to
supply Black Hills Power for a period of three years commencing October 1,
1993, seasonal firm peaking capacity with a monthly load factor of 15
percent. For winter seasons the contract provides for 15 MW in the 1993-94
winter and 20 MW and 30 MW in the next two winter seasons, respectively. For
the summer season, the contract provides 40 MW for 1994, 50 MW for 1995 and
20 MW for 1996. The term of the sale may be extended from year to year if
neither party cancels the agreement. The sale is conditioned upon WAPA
agreeing to maintain a transmission path for Sunflower for delivery to Black
Hills Power at Stegall, Nebraska. Black Hills agreed to pay Sunflower for
the capacity purchased $3,200/MW month for 1993, $3,780/MW month for 1994,
$4,410/MW month for 1995 and $4,630/MW month for 1996. For the energy
purchased Black Hills agreed to pay Sunflower's peaking fuel cost plus a
charge for operation and maintenance costs and overhead, estimated to be
$34.20/MWH.
The cost of all power purchased is either included in rates or is
substantially being passed through to customers under automatic fuel and
purchased power adjustment provisions in Black Hills Power's rates. See RATE
REGULATION--South Dakota Regulation under this Item 1. Black Hills Power
purchased additional non-firm, short-term power during 1993 from other
electric power suppliers.
Neil Simpson Unit #2. Neil Simpson Unit #2, an 80 MW coal-fired
electric generating plant to be located adjacent to Wyodak Resources' coal
mine near Gillette, Wyoming, is now under construction by Black Hills Power.
The new plant will increase Black Hills Power's current utility rate base
approximately 58 percent. See--RATE REGULATION--Guarantee of the
Construction Costs of Neil Simpson Unit #2 under this Item 1.
Neil Simpson Unit #2 will be equipped with a pulverized coal boiler with
low NOx burners and overfire air to control NOx emissions, a circulating dry
scrubber and electrostatic precipitator to control SO2 and particulate
emissions. See--ENVIRONMENTAL REGULATIONS--Air Quality--Emission Limitations
at Neil Simpson Unit #2 under this Item 1. The plant is being designed to be
capable of generating at 70 degrees F ambient air temperature a minimum of
80 MW net of the power required to operate the plant.
The new plant, in the opinion of management, will allow Black Hills
Power to keep its rates competitive, to provide for an orderly retirement of
existing generation, to capture low construction and financing costs and to
stabilize the Company's earnings. While benefiting the Company and its
shareholders, Black Hills Power's electric customers will also benefit from
what management believes to be its lowest cost alternative to continue
providing reliable electric service on a long-term basis.
Black Hills Power commenced construction of Neil Simpson Unit #2 in
August of 1993, and commercial operation is scheduled by December 31, 1995.
The estimated capital costs of Neil Simpson Unit #2 are $113,624,000
plus $11,265,000 of allowance for funds used during construction for a total
estimated capital cost of $124,889,000.
All governmental construction permits required to construct Neil Simpson
Unit #2 were obtained by Black Hills Power. The construction permits are all
in full force and effect, and there is currently no litigation or appeals
pending affecting those permits.
Whether the SDPUC and WPSC allow the new facility in rates will be
determined at a later time. See--RATE REGULATION--1995 Rate Cases under this
Item 1.
In obtaining all governmental permits to construct Neil Simpson Unit #2,
Black Hills Power committed to maintain certain levels of pollutant emissions
(see--ENVIRONMENTAL REGULATION--Air Quality--Emission Limitations at Neil
Simpson Unit #2 under this Item 1), committed to a guarantee of the
construction costs (see--RATE REGULATION--Guarantee of the Construction Costs
of Neil Simpson Unit #2 under this Item 1), committed Wyodak Resources to a
coal contract (see--COAL SALES--Contract to Supply Coal to Neil Simpson Unit
#2 under this Item 1) and committed to certain other regulatory studies (see
- --RATE REGULATION--Other Regulatory Conditions of Approving of Neil Simpson
Unit #2 under this Item 1). See--CONSTRUCTION AND CAPITAL PROGRAMS--
Financing Neil Simpson Unit #2 under this Item 1.
RATE REGULATION
Guarantee of the Construction Costs of Neil Simpson Unit #2. The
Company has guaranteed to the WPSC and the SDPUC that the Company will never
include in rate base for the determination of electric rates in those
jurisdictions those capital costs of Neil Simpson Unit #2 which exceed
$124,889,000 (the "Guaranteed Cost"), including allowance for funds used
during construction. The Company currently receives from retail sales in
South Dakota and Wyoming approximately 91 percent of all electric revenues.
The Guaranteed Cost does not include the costs of additions to Neil Simpson
Unit #2 subsequent to commercial operation or the operating costs of the
plant. Due to the Guaranteed Cost, the Company would likely be forced to
write off against earnings any construction costs of Neil Simpson Unit #2 in
excess of the Guaranteed Cost.
Black & Veatch Architects/Engineers of Kansas City, Missouri is
furnishing the Neil Simpson Unit #2 design, engineering, and construction
management services for a fixed fee. Contracts have been entered into with
a general contractor and with other contractors and vendors to provide the
various components of Neil Simpson Unit #2, such as the boiler, the turbine
generator, the air quality control system, the condenser, the distributive
control information system, the structural steel, the transformers, the coal
silo and the coal conveying system. All contracts provide for either fixed
contract sums or fixed unit prices. The Company estimates that as of
March 1, 1994, contracts have been entered into with contractors and vendors
providing approximately 90 percent of the completion costs of the project.
The balance of the contracts yet to be entered into are for certain supplies
and small components and are expected to be finalized by April 1994.
The contract between the Company and the architect/engineer provides
that Black & Veatch will furnish the Company an estimate of the costs of
completing the construction of Neil Simpson Unit #2 on which the engineer
represents that the Company can rely with a high level of confidence. The
contract provides for damages, both direct and consequential, not to exceed
$35 million for any damages incurred by the Company arising out of the
negligence of the architect/engineer in performing the contract.
Each of the contracts for the various components of the construction of
Neil Simpson Unit #2 provide for certain obligations to correct defective
work, warranties and liquidated damages provisions which the Company believes
will provide some compensation to the Company for damages resulting from any
failure of the various contractors and vendors to perform. Performance bonds
from reputable surety companies have also been required to guarantee
performance of all of the erection contracts. However, notwithstanding that
the Company believes it has negotiated contracts with reputable businesses
requiring damages for breach of performance and sureties to guarantee
performance of erection contracts, the Company can give no assurances that
Neil Simpson Unit #2 will be constructed on time and within the Guaranteed
Cost, and if not, that the Company would be adequately compensated for all
damages incurred due to any breaches of contracts. The contracts contain
defenses to paying damages if the failure to perform was caused by events
beyond the control of the contractors. Unexpected costs can result from
various causes beyond the control of any party such as labor unrest,
transportation delays, weather conditions, governmental interference and
other causes. While the Company believes it has properly protected itself to
the extent reasonably possible through its contracts with its
architect/engineer and contractors and vendors, the Company, through its
guarantee to the SDPUC and the WPSC, did assume the risk of not being able to
earn a return on any costs in excess of the Guaranteed Cost caused by
(i) events beyond the control of any contracting party, (ii) uncompensated
consequential damages and direct damages in excess of contractual liquidated
damages and litigation costs resulting from contract breaches, (iii) any
inability to enforce contracts or performance bonds due to any unexpected
lack of financial responsibility of contractors, vendors or sureties and
(iv) costs in excess of estimates for the remaining 10 percent of Neil
Simpson Unit #2 for which contracts have yet to be let.
As of the date of finalizing this 10-K, the construction of Neil Simpson
Unit #2 is proceeding as scheduled. Based upon all current contracts and the
estimate furnished by the architect/engineer, the Company expects to
construct Neil Simpson Unit #2 within the time as scheduled and at a cost not
to exceed the Guaranteed Cost. As of the date of finalizing this 10-K, the
guaranteed construction cost of $124,889,000 includes an unallocated
contingency of approximately $4,400,000.
Black Hills Power receives no bonus or incentive ratemaking benefit if
it is able to bring Neil Simpson Unit #2 into commercial operation at total
capital costs of less than the Guaranteed Cost.
Other Regulatory Conditions of Approving Neil Simpson Unit #2. As a
condition to the WPSC granting a certificate of public convenience and
necessity allowing Black Hills Power to build Neil Simpson Unit #2, Black
Hills Power agreed to certain regulatory procedures consisting of
implementing a cost-effective demand-side management program, establishing
and perpetuating an Integrated Resource Planning Advisory Group, studying the
feasibility of wind generation and pursuing all reasonable cost containment
measures in the construction and operation of Neil Simpson Unit #2 and the
overall electric utility operations of Black Hills Power.
Management is of the opinion that while these conditions are important
and Black Hills Power will comply with all of the conditions, such conditions
do not constitute anything more than what Black Hills is required to do as an
electric utility under today's regulatory environment. Black Hills Power is
in the process of implementing a demand-side management program in attempting
to find cost-effective programs that would reduce the demand on Black Hills'
system, thereby postponing to that degree the need for further electric power
resources. Black Hills Power has implemented the Integrated Resource
Planning Advisory Group consisting of members of the staffs of the SDPUC and
the WPSC as well as representatives of Black Hills Power and its customers.
This group will serve as a communication conduit for Black Hills Power to
keep all regulators advised of its continuing integrated resource planning
process.
1995 Rate Cases. Black Hills Power expects to file general rate cases
during 1995 to request a rate increase which would include the full costs,
including allowance for funds during construction, of Neil Simpson Unit #2.
Based upon assumptions of load growth, inflation and costs, Black Hills Power
anticipates gradual small rate increases during construction of Neil Simpson
Unit #2 totaling 2.5 percent by the operation of automatic fuel and power
purchased adjustment tariffs that have been approved in all jurisdictions in
Black Hills Power's service area. Neil Simpson Unit #2 is expected to
increase Black Hills Power's electric utility rate base approximately 58
percent. Taking into account the reduction of purchased power expense when
Neil Simpson Unit #2 is placed into operation and other projections, the 1995
general rate filing is projected to result in a 10 percent increase in total
revenue. Percentages of increases for different customer classes will vary
depending upon final approved cost of service allocations.
In granting Black Hills Power's application to the WPSC for a
certificate of public convenience and necessity on June 2, 1993 authorizing
Black Hills Power to construct Neil Simpson Unit #2, the WPSC found that Neil
Simpson Unit #2 provides Black Hills Power the least cost approach,
consistent with adequate and reliable service, to the resource needs of Black
Hills Power and its customers; and Neil Simpson Unit #2 is a sensible
resource addition choice for Black Hills Power.
On May 26, 1993, the SDPUC issued an order denying a request by Rosebud
Enterprises, Inc. ("Rosebud") that the SDPUC determine Black Hills Power's
resource needs and the avoided costs of the needed resource and to establish
a legally enforceable obligation requiring Black Hills Power to purchase
power from Rosebud to be generated from a waste fuel facility that would be
qualified under the Public Utility Regulatory Policies Act. The SDPUC
further denied Rosebud's request to issue an order finding that Black Hills
Power may be imprudent to proceed to construct Neil Simpson Unit #2. The
SDPUC did find that Black Hills Power has in good faith planned and permitted
Neil Simpson Unit #2 in order to fulfill Black Hills Power's duty to serve
its customers. However, the SDPUC made no finding of prudency or imprudency
concerning Black Hills Power's decision to proceed with the construction of
Neil Simpson Unit #2. The Commission did find that it had no authority under
South Dakota law to make its own determination as to a utility's need for
additional capacity or the timing of that need. The Commission found that it
has established a strong precedent of placing the risk of determining the
need for construction of new facilities and the timing of that need on each
utility serving in South Dakota. It stated that South Dakota utilities have
a duty to serve their respective service areas under South Dakota law,
including the decision to add capacity. The Commission found that it would
review the prudency of capacity additions only when a utility attempts to
include the additional capacity in rates.
Neither the WPSC nor the SDPUC has made any determinations of rate
treatment resulting from Neil Simpson Unit #2. These decisions are expected
to be made in response to the 1995 general rate filings when Black Hills
Power will request the full inclusion of Neil Simpson Unit #2 into rate base.
While Black Hills Power believes that both the WPSC's and the SDPUC's orders
were supportive of Neil Simpson Unit #2, the Company can give no assurances
that the regulatory commissions will allow the full cost of Neil Simpson Unit
#2 in rate base. Questions concerning the prudency of Black Hills Power to
construct Neil Simpson Unit #2 may arise in the rate proceedings, and Black
Hills Power assumes the risk of being able to prove to the regulatory
commissions that Black Hills Power did need Neil Simpson Unit #2 and was
prudent to construct the plant.
If the impact of rate increases is high on a customer class, some
regulatory commissions will find reasons to phase in the rate increases over
a period of time after construction. Sometimes regulatory commissions will
initially allow only the debt portion of the cost of new plant and disallow
all or a part of the equity portion if the commissions find that management
was either imprudent in building a power plant or the utility assumed the
risk that the plant would be needed when completed. The result of such
rulings would be to deny the Company a return on a portion of their
investment in new plant until such time as the entire plant is included in
the rate base. The justification of regulatory commissions in second-
guessing utilities as to the need for new plant is that the risk of building
new plant is on the utility and not the customer. While Black Hills Power
will urge that such rulings would be unfair and the Company should not be
penalized if an unforeseen event occurs beyond the control of the Company,
the Company can give no assurances that it will be successful in getting the
entire construction cost of Neil Simpson Unit #2 in rate base if to do so
will result in what may be considered as onerous rate increases to some of
the customer classes.
If Black Hills Power is not in a surplus power condition at the time of
the rate case, management believes that they should be successful in getting
the entire plant into rate base. Black Hills Power does not believe it will
be in a surplus condition. See--ELECTRIC POWER SALES AND SERVICE TERRITORY
and ELECTRIC POWER SUPPLY--Reserves under this Item 1. If, on the other
hand, Black Hills Power is perceived by the regulators to be in a surplus
power condition at the time Neil Simpson Unit #2 comes into commercial
operation, there is a higher probability of the disallowance of a portion of
Neil Simpson Unit #2 in rate base for a period of time.
The Company believes that even if Black Hills Power is in a surplus
power condition at the time Neil Simpson Unit #2 comes into commercial
operation and a portion of Neil Simpson Unit #2 is not allowed in rate base,
Black Hills Power should be able to make up the deficit in revenue by sales
of the surplus power to other utilities until such time that the power is
needed for Black Hills Power's customers or sell a portion of Neil Simpson
Unit #2. Management believes that there will be a sufficient need for power
in the area that such sales are probable. However, management can give no
assurances that such market will exist and that the market prices for the
power contract terms Black Hills Power could offer will be satisfactory. See
- --ELECTRIC POWER SALES AND SERVICE TERRITORY--Future Wholesale Opportunities
and ELECTRIC POWER SUPPLY--Reserves under this Item 1.
South Dakota Regulation. In South Dakota, representing 84 percent of
revenue from total 1993 electric sales, Black Hills Power has not had a
formal rate case before the SDPUC since 1982. However, as a result of an
investigation by the SDPUC concerning the effect of the reduced corporate
income tax rates under the Tax Reform Act of 1986 and affiliated
transactions, the SDPUC in 1988 allowed Black Hills Power to include in its
base rates the full cost of purchased power under the Pacific Power 40-year
contract.
South Dakota law and the SDPUC allow Black Hills Power to incorporate in
its rates automatic adjustment clauses which allow all increases and
decreases in the cost of purchased power and fuel to be added to or
subtracted from rates without a rate case or order from the SDPUC. However,
the clauses place a limitation on that portion of the cost of coal purchased
by Black Hills Power from its affiliate Wyodak Resources which can be allowed
in rates. This limitation provides that Black Hills Power may not include in
rates any cost of coal which allows Wyodak Resources to earn a return on
equity on sales to Black Hills Power in excess of a percentage equal to
(i) the average interest rate paid by electric utilities with an "A" rating
on long-term bonds plus (ii) 400 basis points (4%). The return on equity is
calculated as of each April 1 and applied to determine if any refund is due
for the cost of coal passed on to rate payers during the previous calendar
year. If a refund is due, the refund is credited without interest over the
12 months following the April 1 date of calculation. Black Hills Power
estimates that the return on equity to be applied in 1993 to determine the
refund will be 11.6 percent. The Company has accrued $1,060,000 in 1993 in
anticipation of what Black Hills Power estimates the refund to be for 1993
under this adjustment clause. The SDPUC rate order specifically provides
that the limitation applies only to purchases by Black Hills Power, which
tonnage sales represented 33 percent of Wyodak Resources' total sales of coal
in 1993.
Retail rates in South Dakota decreased approximately 4 percent in 1993
over 1992.
Wyoming--Retail. In Wyoming, where revenue from retail sales
represented 7 percent of revenue from total electric sales in 1993, Black
Hills has not had a formal rate case before the WPSC since 1981. Every three
months, Black Hills Power files an application to adjust rates to reflect
changes in the cost of purchased power. The WPSC has been consistently
approving these applications.
Retail electric rates in Wyoming averaged 0.7 percent lower in 1993 than
1992.
Montana. Black Hills Power's revenue from sales of electric power in
Montana in 1993 represented only 1 percent of revenues from total sales. The
last formal rate application in Montana was in 1983. Every three months,
Black Hills Power files an application to adjust rates to reflect changes in
the cost of fuel and purchased power. The Montana Public Service Commission
has been consistently approving these applications.
Wyoming--Wholesale. The only wholesale customer of Black Hills Power is
the City of Gillette, Wyoming. See--ELECTRIC POWER SALES AND SERVICE
TERRITORY--Electric Sales--Wholesale. The rates paid by Gillette are subject
to regulation by the FERC. Either party may apply to the FERC for rate
modifications. The current rates were determined by negotiations between
Gillette and Black Hills Power.
None of the above-referenced rate orders and rate adjustments caused
Black Hills Power to earn less than a rate of return which would have been
allowed by any of the regulatory commissions through a general rate case
filing.
Black Hills Power has not experienced major problems in the recent past
with regulatory bodies allowing it to increase its rates on a timely basis
and allowing all operating costs and electric plant in rate base, but no
assurances can be given that major problems will not occur in the future.
COMPETITION IN ELECTRIC UTILITY BUSINESS
Competition in Service at Retail. In addition to Black Hills Power,
RECs and the federal government through WAPA provide electric service in and
around the service territory of Black Hills Power. WAPA retails electric
service to certain government facilities. Black Hills Power and the RECs
serve in territories which are protected by state laws or regulations which
generally give each entity the exclusive right to serve retail in its
respective territory; however, these laws or regulations are subject to
change and there are certain exceptions. In South Dakota, the SDPUC may
allow a new customer with a load of over 2,000 kilowatts to choose to be
served by a utility other than the utility in whose territory the new
customer locates.
Each municipality in Black Hills Power's service territory has the right
upon meeting certain conditions to acquire or construct a municipally-owned
electric system and to serve the customers within its city. Black Hills
Power is not aware of any such movement by any municipality in its service
territory, which does not already have a municipally-owned electric system,
to create one.
In Wyoming, public utilities operate in service territories assigned by
the WPSC, and a franchise granted by the municipality's governing body is
required to serve within the said municipality. Black Hills Power's
franchise for the City of Newcastle, Wyoming, representing approximately
2,000 customers and 6 percent of Black Hills Power's electric revenue,
expires in 1999. The franchise may be renewed by action of the city's common
council. Black Hills Power may apply for and obtain the right to serve in
another utility's electric service territory if it is found to be in the
public interest to do so, but such applications are rarely granted.
The respective service territories of Black Hills Power and the RECs
were assigned originally on the basis of where each was serving at the time
of assignment. Since the RECs were serving in rural areas (the purpose for
which they were formed), a large portion of the rural area surrounding the
municipalities in which Black Hills Power serves constitutes REC service
territory. Although Black Hills Power has traditionally served considerable
territory outside of municipalities and, therefore, has been assigned a large
amount of such territory, the RECs have the largest portion of such area and,
if the laws are not changed, will over a long period of time tend to receive
a larger portion of the growth of the population centers.
To assist in the planning of new resources and to minimize the risk of
the loss of large loads, Black Hills Power does endeavor to contract with its
large industrial users to serve all electric power needs for a term of years.
Currently Homestake Mining Company is under a 9-year contract to purchase all
of its electric power requirements, the South Dakota State Cement Plant is
under a similar 6-year contract and the City of Gillette (See--ELECTRIC POWER
SALES AND SERVICE TERRITORY--Electric Sales--Wholesale) is under an 18-year
contract for 60 percent of its base load. These three customers together in
1993 accounted for 29 percent of Black Hills' total firm KWH sales and 21
percent of firm electric sales revenue.
The primary competing fuel in Black Hills Power's territory is natural
gas which is available to approximately 80 percent of its customers.
Competition in Electric Generation. Under the Public Utility Regulatory
Policies Act, certain small power generators burning waste fuel and renewable
fuel and certain cogenerators that utilize excess steam for a purpose other
than power generation are deemed to be qualified facilities and the owner can
force an electric utility such as Black Hills Power to purchase power for its
avoided costs. Generally avoided costs are those costs that would be avoided
if it purchased power from the qualifying facility. To date Black Hills
Power's only interface with qualifying facilities under PURPA was the attempt
by Rosebud Enterprises, Inc. to build a waste fuel facility and sell power to
Black Hills Power to avoid the building of Neil Simpson Unit #2. See--RATE
REGULATION--1995 Rate Cases under this Item 1.
In addition to competition from RECs and the federal government from
central station sources, Black Hills Power could face the competition of
industrial and public customers constructing self-generation facilities using
alternative fuels, such as waste material, natural gas or oil. To date Black
Hills Power has not faced any material competition from such sources.
Management does not believe that such sources are cost effective but can give
no assurances that material competition from these sources will not occur.
Under the new federal Energy Policy Act of 1992, a new class of
wholesale-only electric generators, referred to as exempt wholesale
generators (EWGs) was created. The EWGs are now exempt from the Public
Utility Holding Company Act of 1935 (PUHCA). Under PUHCA, the parent company
of a participant in a power project could become a public utility holding
company subject to PUHCA, resulting in unacceptable restrictions and
regulations. To some extent this impediment to creating EWGs as a subsidiary
of a nonutility company has now been removed. An EWG must be engaged
exclusively in the ownership and/or operation of "eligible facilities." An
"eligible facility" is an electric generating facility whose output is sold
only at wholesale. An EWG is not subject to restrictions relating to type of
fuel, maximum size, technology or permissible utility ownership as a
qualifying facility is under PURPA. An EWG is subject to regulation by the
FERC. A regulated electric utility may purchase power from an EWG in which
the utility has an interest if each state commission with regulatory
authority over the purchasing utility's retail rates approves such
transaction.
The Energy Policy Act of 1992 encourages independent power producers to
effectively compete with qualifying facilities under PURPA and the electric
utility itself to construct the future electric generation as it is needed.
Black Hills Power's experience with competing qualified facilities and
the effect of the new Energy Policy Act of 1992 indicate that Black Hills
Power will be challenged by other alternatives each time it proposes to build
generation. To be able to build its own generation, Black Hills Power will
have to demonstrate under an integrated resource plan that its proposal is
the least cost and most reliable of all other proposals. As a result of this
competition, Black Hills Power is not necessarily going to be the sole
generator of its future power requirements as it was in the past. The Energy
Policy Act of 1992 does not prevent the Company from engaging in the business
of an independent power producer in other utilities' service territories and
could lead to additional opportunities for the Company in the future due to
the Company's coal fuel supply with mine-mouth plants that have been
permitted.
Transmission Access. The Energy Policy Act of 1992 granted the FERC
broad authority to mandate transmission access to the EWGs as well as others
engaged in wholesale power transactions. Under the new law, any electric
utility or any other entity generating wholesale energy may apply to FERC for
an order requiring a utility to transmit such energy, including enlargement
of relevant facilities. If the utility refuses to wheel or furnish
transmission service to an independent power producer, the FERC may, but is
not required, order wheeling in response to an application. FERC is not to
order wheeling if to do so would impair the transmitting utility's
reliability of service. The new law does provide for the transmitting
utility to obtain its full cost of transmission service, to be determined by
the FERC.
The new Energy Policy Act of 1992 specifically prevents the FERC from
ordering wheeling to end users (retail wheeling).
Black Hills Power does now furnish transmission service for competing
RECs and for its only wholesale customer, the City of Gillette, Wyoming.
Therefore, the Energy Policy Act is not likely to have any effect in allowing
transmission access by other electric utilities serving at retail. However,
the Energy Policy Act can require Black Hills Power to furnish transmission
service for competing EWGs and qualifying facilities, thereby increasing
competition for Black Hills Power. As long as the states in which Black
Hills Power operates continue to grant exclusive service territories and the
federal government does not preempt this state jurisdiction, the increase in
transmission access through the Energy Policy Act of 1992 through Black Hills
Power's transmission system is likely not to have an effect upon Black Hills
Power. However, if the electric rates of Black Hills Power become
noncompetitive with alternative sources of power or such a trend develops
throughout the country, further pressure on both Congress and the state
legislators for more competition could result in modifications to the
utility's service territory and retail wheeling could be mandated, all of
which could have an adverse effect upon Black Hills Power's electric
business. On the other hand, if Black Hills Power can continue to acquire
low-cost new generation and can offer power at competitive rates, retail
wheeling may become a positive opportunity for the Company.
Price Competition. Each of Black Hills Power and the RECs serving
around its service territory offers a package of rates and services designed
to recognize the costs and needs of various customer classes. The following
rate comparisons are provided to show the difference in cost that typical
customers are currently experiencing.
<PAGE>
Regular Residential Service
Percentage That
REC is Higher (+)
Monthly Cost or Lower (-)
(500 kWh) Than BHP
SD - Black Hills Power $41.59 ---
SD - Black Hills Electric (REC) $61.70 +48
SD - Butte Electric (REC) $57.64 +39
SD - West River Electric (REC) $52.50 +26
WY - Black Hills Power $38.19 ---
WY - Tri-County Electric (REC) $35.34 -8
Small Commercial Service
Percentage That
REC is Higher (+)
Monthly Cost or Lower (-)
(6,000 kWh, 30 kW) Than BHP
SD - Black Hills Power $507.44 ---
SD - Black Hills Electric (REC) $410.90 -19
SD - Butte Electric (REC) $389.70 -23
SD - West River Electric (REC) $631.80 +25
WY - Black Hills Power $451.55 ---
WY - Tri-County Electric (REC) $300.02 -51
Large Commercial/Industrial Service
Percentage That
REC is Higher (+)
Monthly Cost or Lower (-)
(120,000 kWh, 300 kW) Than BHP
SD - Black Hills Power $6,406.20 ---
SD - Black Hills Electric (REC) $7,053.00 +10
SD - Butte Electric (REC) $8,283.00 +29
SD - West River Electric (REC) $7,827.80 +22
WY - Black Hills Power $6,681.63 ---
WY - Tri-County Electric (REC) $6,523.90 -2
Of the group, only Black Hills Power and Tri-County Electric have their
rates established by commission order. This allows the South Dakota RECs the
opportunity to offer incentive rates and services to commercial and
industrial users designed to attract new customers without regulatory review
while Black Hills Power may be denied this opportunity by regulation of its
rates.
As Black Hills Power constructs new generation, its electric rates will
need to be increased. (See RATE REGULATION--1995 Rate Cases under this Item
1.) While its REC competitors also have continual needs for new
construction, the RECs serving in Black Hills Power's service territory do
have available surplus power from Basin Electric at this time. Depending on
the timing of construction costs and other economic factors such as power
sale fluctuations and other costs and loss or gain of customers of Black
Hills Power and its competitors, Black Hills Power's rates could become less
competitive with other electric suppliers. However, the RECs could
experience higher costs of financing due to government attempts to balance
the budget to offset the surplus power advantage.
Black Hills Power's management forecasts that its construction program
and anticipated load growth will result in rate increases higher than
inflation during the next three years but will be lower than inflation when
averaged over ten years. If this forecast is accurate, management believes
Black Hills Power's rates will remain favorably competitive with other
electric suppliers in its service territory. Many factors beyond the control
of the Company could affect this, such as higher than expected construction
costs, unfavorable regulatory treatment and unexpected loss of load. No
assurances can be given in this area.
CONSTRUCTION AND CAPITAL PROGRAMS
The construction and capital costs for 1993 for its electric, mining and
oil and gas production operations were $25,932,000, $7,425,000 and
$6,933,000, respectively.
The Company reviews its construction and capital program annually.
Current estimates of construction and capital expenditures for 1994 through
1996 are as follows:
<TABLE>
<CAPTION>
1994 1995 1996
(in thousands)
<S>
Electric <C> <C> <C>
Neil Simpson Unit #2 $65,113 $45,035 $-----
Other Production 2,283 859 897
Transmission 4,228 1,617 8,478
Distribution 6,511 6,503 6,876
General 1,448 814 2,354
Total $79,583 $54,828 $18,605
Coal mining $ 2,129 $ 853 $ 2,042
Oil and gas production $ 5,000 $ 6,000 $ 6,000
Total $86,712 $61,681 $26,647
</TABLE>
Black Hills Power. The 1993 construction costs for the Company were
financed primarily with internally generated funds, common stock sales and
short-term borrowings.
The above capital budget includes approximately $110,148,000 for the
completion of the design and construction of Neil Simpson Unit #2. See--
ELECTRIC POWER SUPPLY--Neil Simpson Unit #2 under this Item 1.
Financing Neil Simpson Unit #2. The Company's plans to finance the
construction of Neil Simpson Unit #2 and its other construction program
include the sale of additional shares of common stock, the issuance of long-
term bonds and the increasing of dividends paid by Wyodak Resources to the
Company.
In 1993 the Company sold 525,000 shares of additional common stock in a
public offering at 25 3/8. Net proceeds to the Company from this sale were
approximately $12.7 million. The Company also modified its dividend
reinvestment program so that the Company can elect to either issue new stock
or purchase stock on the market to satisfy the shareholders' requests to
reinvest dividends. The Company's expectations at this time are to raise an
additional $4 million of equity capital from the dividend reinvestment
program by the time Neil Simpson Unit #2 is operational.
To complete the equity portion of the capital budget, the Company plans
to cause Wyodak Resources to upstream $45 million of dividends during 1994
and 1995.
To finance the debt portion of the construction program, the Company is
planning to issue approximately $87 million of long-term bonds under the
Company's first mortgage Indenture. The bonds are expected to be issued
commencing in mid-1994 and continuing through 1995, probably in two or three
issues.
Based upon its projections, the financing program is designed to create
a capital ratio at the time Neil Simpson Unit #2 becomes operational of 50
percent equity and 50 percent debt for the consolidated Company and 55
percent debt and 45 percent equity for Black Hills Power's capital structure
for ratemaking purposes.
Wyodak Resources. The capital program of Wyodak Resources includes coal
handling facilities and replacement of other mining equipment. Wyodak
Resources plans to finance these additions with internally generated funds.
During 1993 Wyodak Resources constructed new coal handling facilities in
conjunction with Pacific Power. See--MINING PROPERTIES under Item 2.
Western Production. Western Production's capital program is planned to
be devoted primarily to oil and gas development drilling in Texas and the
Rocky Mountain Region. Secondary emphasis will be on production acquisitions
and exploration drilling. The capital program is planned to be financed with
internally generated funds and approximately $3 million of short-term bank
borrowings.
COAL SALES
Contract to Supply Coal to Neil Simpson Unit #2. Black Hills Power and
Wyodak Resources entered into the Restated and Amended Coal Supply Agreement
for Neil Simpson Unit #2 on February 12, 1993. Under this agreement, Wyodak
Resources agrees to supply all of the fuel requirements for Neil Simpson Unit
#2 for its useful life and reserve 20 million tons of coal reserves for that
purpose. Black Hills Power made a commitment to both the SDPUC and the WPSC
that coal would be furnished and priced as provided by this agreement for the
life of the plant.
Under this agreement, Wyodak Resources agrees that its earnings from
coal sales to Black Hills Power (including the 20 percent share on the Wyodak
Plant and all sales to Black Hills Power's other plants) will be limited to
a return on Wyodak Resources' original cost, depreciated investment base.
The return agreed to is 4 percent (400 basis points) above A-rated utility
bonds to be applied to a new investment base each year. In addition, Wyodak
Resources committed to further reduce the coal price for coal to be used in
any of Black Hills' power plants during the period of time that under prudent
dispatch that power plant would not have been operated if it were not for the
discounted price of coal. In South Dakota (84 percent of Black Hills Power's
electric revenues), Black Hills Power is currently precluded from passing on
to its customers any cost of coal from Wyodak Resources which would exceed
the same rate of return, but the dispatch discount is an additional
accommodation not applied at this time.
Since Wyodak Resources is expected to incur only minimal additional
capital costs to fulfill the coal supply agreement for Neil Simpson Unit #2,
Wyodak Resources is not expected to increase its earnings from such sale.
Since Wyodak Resources is a subsidiary of the Company, regulators limit
the amount of Black Hills Power's coal costs it can include in electric rates
charged to its customers. The Company believes that the above methodology
requiring Wyodak Resources' return on sales to Black Hills Power to be based
on an original cost depreciated investment base will continue to be applied
by the SDPUC and the WPSC which regulate approximately 89 percent of the
Company's electric sales. However, regulatory commissions may in the future
apply a different methodology such as limiting Black Hills Power to include
in rates only what the commission determines to be a fair market purchase
price of coal. Such fair market purchase price could be less than what
Wyodak Resources requires to earn a rate of return on its investment base.
Earnings from the intercompany sales of coal at this time represent
approximately 7 percent of the Company's consolidated earnings.
Other Sales. The coal mining industry is highly competitive and
significant new sales opportunities are limited. Wyodak Resources operates
in an area with many other mining companies which have substantial unused
capacity. They, like Wyodak Resources, have the permits and capability for
large increases in production. Wyodak Resources has no train load-out
facilities and is not able to compete for large coal sales which require unit
train (usually 110 cars) loading capabilities, and the current market price
for such sales does not support the cost of constructing the necessary
facilities. Until coal prices substantially improve, Wyodak Resources' coal
sales will be confined to a size less than a unit train and to sales for
consumption at or near the mine. Wyodak Resources will have some increased
coal sales to fuel Neil Simpson Unit #2, but increased profits from those
sales are unlikely. See--COAL SALES--Contract to Supply Coal to Neil Simpson
Unit #2 under this Item 1. No assurances can be given that there will be new
plants or the degree of profitability of any such new coal sales. See--
CORPORATE DEVELOPMENT in this Item 1.
Sales and production statistics for the last five calendar years are as
follows:
Revenue From Sale % Revenue
of Coal Derived From Tons of Coal Sold
Year (in thousands) Black Hills Power (in thousands)
1993 $29,822 34% 3,027
1992 28,296 35 2,958
1991 26,138 35 2,742
1990 26,528 36 2,908
1989 21,456 37 2,349
Wyodak Resources furnishes all of the fuel supply for the Wyodak Plant
in which Black Hills Power owns a 20 percent interest and Pacific Power an 80
percent interest. See Note 6 of "Notes to Consolidated Financial Statements"
appended hereto. The price for unprocessed coal sold to the Wyodak Plant is
based on a coal supply agreement entered into by Black Hills Power, Pacific
Power and Wyodak Resources in 1974 and terminating in the year 2013. This
agreement was amended and restated in 1987 as discussed below.
Wyodak Resources, Black Hills Power and Pacific Power entered into
settlement agreements in 1987 which settled a dispute over the quantity of
coal Pacific Power was required to purchase to operate the Wyodak Plant and
Pacific Power's obligation to purchase additional coal commencing in 1990
under a contract which would have provided coal for a since canceled second
unit at the Wyodak Plant. Said agreements are referred to as the PacifiCorp
Settlement which is discussed in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" of the 1993 Annual Report to
Shareholders of the Company on pages 14 through 20, incorporated herein by
reference.
Revenue from coal sales to the Wyodak Plant totaled $21,438,000 in 1993
or 72 percent of revenue for all coal sold by Wyodak Resources. The quantity
of coal sold in 1993 for the Wyodak Plant was 2,118,000 tons, as compared to
2,079,000 tons sold in 1992. Barring unusual periods of maintenance, the
quantity of coal for the maximum consumption capability of the Wyodak Plant
for one year is approximately 2,100,000 tons and the average yearly
consumption is 1,900,000. The average consumption is expected to continue
during the remaining 20 years of the coal agreement. However, from time to
time, the plant's physical operating capabilities will affect the quantity of
coal burned.
Wyodak Resources sells coal to Black Hills Power pursuant to an
agreement entered into in 1977 and last amended in 1987 which is
approximately the same as the original Wyodak Plant agreement except for an
additional amount for processing the coal and a discount for all coal
delivered in a year in excess of 500,000 tons. Wyodak Resources has reserved
sufficient coal, presently estimated at 9,000,000 tons, for the generating
plants of Black Hills Power until such plants are retired.
Black Hills Power expects its power plants, with the exception of the
Wyodak Plant, to continue to consume approximately the same quantity of coal
as in 1993 unless unexpected mechanical failures occur. Of the 3,027,000
tons of coal sold by Wyodak Resources in 1993, 1,009,000 tons were sold to
Black Hills Power, 1,696,000 tons were sold to Pacific Power and 322,000 tons
were sold to others.
Wyodak Resources' revenue from sales of coal to Pacific Power and Black
Hills Power as compared to its revenue from all sales to other customers for
the last three years was as follows:
Revenue from
All Sales to
Unaffiliated
Revenue from Revenue from Customers
Sales to Sales to(1) (includes
Pacific Power Black Hills Power Pacific Power)
Year (in thousands)
1993 $17,448 $10,047 $19,775
1992 16,541 9,811 18,485
1991 14,632 9,220 16,918
(1)Is not adjusted for refunds under South Dakota rate order. See--RATE
REGULATION of this Item 1.
In addition to the coal sold to the Wyodak Plant and to Black Hills
Power, Wyodak Resources sells coal to the South Dakota State Cement Plant
under an all requirements contract expiring on December 1, 1997. Wyodak
Resources sold 240,000 tons under this contract in 1993. Smaller amounts of
coal are sold to various businesses and for residential use. All long-term
contracts contain adjustment clauses based upon certain costs and government
indices.
In 1988 Wyodak Resources agreed to the termination of a long-term coal
supply agreement with the City of Grand Island, Nebraska. Under this
agreement, Wyodak Resources will receive approximately $155,000 per year for
14 years during which Grand Island will have an option to purchase coal.
Wyodak Resources has reserved sufficient coal in the eventuality that Grand
Island exercises its option.
Many factors can significantly affect sales of coal and revenue under
the existing contracts. Examples include the seller's or buyer's inability
to perform due to machinery breakdown, damage to equipment, governmental
impositions, labor strikes, coal quality problems, transportation problems
and other unexpected events.
OIL AND GAS OPERATIONS
Size and Competition. Oil and gas operations have not been a
significant percent of the Company's total operations. Net income and assets
related to oil and gas operations have been 7 percent or less of the
Company's consolidated amounts over the last five years. The oil and gas
industry is highly competitive. Western Production encounters strong
competition from many oil and gas producers, including many which possess
substantial resources, in acquiring drilling prospects and producing
properties.
Markets and Sales. The Company's oil and gas production is sold at or
near the wellhead, generally at posted prices. Gas production is generally
sold in the spot market at prevailing prices. Western Production has been
able to market all of its oil and gas production. Operating revenue by
source for the last five years is as follows:
Oil and Gas Gas Plant Field
Sales Revenue Services
(in thousands) (in thousands) (in thousands)
1993 $7,489 $ 759 $3,148
1992 5,640 701 3,258
1991 4,780 693 3,595
1990 4,240 876 3,480
1989 3,681 1,082 3,581
Quantities and sale prices for oil and gas production are affected by
market factors beyond the control of the Company. Such factors include the
extent of domestic production, level of imports of foreign oil and gas,
general economic conditions that determine levels of industrial production,
political events in foreign oil-producing regions and variations in
governmental regulations and tax laws. There can be no assurance that oil
and gas prices will not decrease in the future. Such declines would decrease
net revenues from oil and gas properties and reduce the value of such assets.
These declines could result in the write down of certain oil and gas assets.
Management estimates that oil prices must average $14 to $15 per barrel for
its oil operations to remain profitable.
Production. Western Production produced approximately 456,000
equivalent barrels of oil in 1993. Approximately 48 percent of this
production came from the Finn-Shurley Field which is comprised primarily of
stripper wells (wells producing less than 10 barrels per day).
Drilling Activity. Western Production participated in the drilling of
24 wells in 1993. Western Production's average working interest in such
wells was 53.1 percent, or 12.74 net wells. Approximately 83 percent of the
wells were classified as development wells and 17 percent were classified as
exploratory wells. A development well is a well drilled within the presently
proved productive area of an oil and gas reservoir, as indicated by
reasonable interpretation of available data, with the objective of completing
in that reservoir. An exploratory well is a well drilled in search of a new,
as yet undiscovered oil or gas reservoir or to greatly extend the known
limits of a previously discovered reservoir.
ENVIRONMENTAL REGULATION
The Company is subject to present and developing laws and regulations
with regard to air and water quality, land use, land reclamation and other
environmental matters by various federal and state authorities.
Air Quality
Emission Limitations at Neil Simpson Unit #2. One of the governmental
permits required to build Neil Simpson Unit #2 was a prevention of
significant deterioration permit to be granted by the DEQ, Division of Air
Quality. On April 14, 1993, Black Hills Power received the permit ("PSD
Permit") allowing Black Hills to proceed with the construction of Neil
Simpson Unit #2.
The PSD Permit sets certain emission rate limitations for pollutants
which cannot be exceeded during the operation of Neil Simpson Unit #2.
Wyoming law requires that after a 120-day start-up period, Black Hills will
require an operating permit. During the start-up period, performance tests
are conducted to determine if the plant can be operated within the emission
limitations of the PSD Permit.
The PSD Permit sets emission rate limitations on particulate, sulfur
dioxide (SO2), nitrogen oxides (NOx), carbon monoxide and particulate
emissions and opacity limitations. The PSD Permit requires constant
monitoring to determine continual compliance with the SO2, NOx and opacity
limitations.
The SO2 emissions are not to exceed 0.20 lbs./MMBtu on a two-hour
rolling average and 0.17 lbs./MMBtu on a 30-day rolling average. To control
SO2 and particulate emissions, Neil Simpson Unit #2 will include a
circulating dry scrubber and electrostatic precipitator wherein the flue
gases from the pulverized coal boiler will be treated in the scrubber with a
lime reagent and the matter will be removed by the precipitator. The
manufacturer of the scrubber and precipitator has guaranteed particulate and
SO2 limitation emission rates sufficient to meet the PSD Permit limitations.
The guarantee requires a six-month 100 percent availability and compliance
period. The manufacturer further guaranteed under certain conditions for a
period of five years corrosion minimums and operation and maintenance costs.
The PSD Permit sets the initial NOx emission rate limitation at 0.23
lbs./MMBtu; however, the permit provides that during the first two years of
operation if Black Hills Power demonstrates that the 0.23 lbs./MMBtu
limitation can be lowered to the manufacturer's guarantee of 0.17 lbs./MMBtu,
the Wyoming Department of Environmental Quality reserves the right to lower
the NOx emissions limitation permanently.
The method of control of NOx for Neil Simpson Unit #2 are low NOx
burners with overfire-air controls. The PSD Permit does not require any
further devices to remove NOx such as selective catalytic reduction or
selective noncatalytic reduction systems. The manufacturer of the boiler for
Neil Simpson Unit #2 has guaranteed that the boiler will meet the NOx
limitations. The guarantee is based upon tests to be conducted under ideal
operating conditions during the 12 months after commercial operation. The
boiler is being designed so that a selective catalytic reduction system could
be installed if later required to meet the NOx limitations.
The Company believes that Neil Simpson Unit #2 is being designed to meet
all emission limitations. However, both the SO2 and NOx emission limitations
are some of the lowest emission rates in the United States, and flaws in
design or unexpected coal quality or other events could cause additional
unexpected capital costs in being able to operate with these limitations.
Emissions from Other Plants. All of Black Hills Power's generating
plants are believed by management to be operating in full compliance with air
quality laws and regulations. Applications for continued operation of the
Kirk power plant has been submitted for the approval of the South Dakota
Department of Environment and Natural Resources ("DENR").
Asbestos. Black Hills Power completed the majority of the asbestos
removal work at the Osage power plant in 1993. This included that removal
work being performed in conjunction with the reinforcement of the walls of
the three boiler units. The remaining asbestos at the Osage, Neil Simpson,
Kirk and Ben French facilities is believed to be adequately encapsulated.
Its removal will occur as other projects necessitate or as deterioration
occurs. No cost determination has been made for the additional work
required.
The Clean Air Act Amendments. Legislation enacted by the Congress of
the United States in late 1990 to amend the Clean Air Act will have an impact
on Black Hills Power's power plants.
All of the power plants other than the Wyodak Plant are made up of units
with generating capacity of 25 megawatts or less and are believed to be
exempt from most of the limitations and requirements of the Act. All
facilities, however, are subject to the payment of fees calculated on the
basis of tons per year of emissions of sulfur dioxide, nitrous oxide and
particulate. The annual fees for those facilities located in South Dakota
totaled approximately $25,000 for 1993. Fee assessments have not yet been
made for Wyoming facilities, however, it is estimated that they will not
exceed $90,000.
According to analyses of emissions from the plant stacks, all four of
the power plants operated by Black Hills Power are believed to be operating
in compliance with current federal and state law. Black Hills Power does not
maintain continuous monitoring on all of these four plants, and unexpected
changes in coal quality or problems with plant operations can cause
violations which could result in penalties being imposed in the future.
Black Hills Power endeavors to operate the plants to prevent such excursions,
but the potential remains for human error and equipment failure.
The Wyodak Plant is equipped with sulfur removal equipment and the plant
is already in compliance with the new sulfur emissions requirements of the
Clean Air Act. New equipment is not necessary to bring the facility in
compliance with the NOx requirements of the Act, but continuous monitoring
equipment for NOx has been purchased and installed at a cost to Black Hills
Power of $147,000. The amendments do require a three-year study on
designated hazardous pollutants which may result in future regulations, but
the impact of that study on the Wyodak Plant is not yet known.
Air Allowances. The Clean Air Act Amendments put into place a program
designed to allow each affected facility to emit into the atmosphere on an
annual basis only that quantity of sulfur dioxide for which it has
authorization by virtue of its control of air allowances. An air allowance
is a right to emit one ton of sulfur dioxide. These allowances are
transferable between facilities and can be sold to other owners of power
production facilities. As a result of the pollution control equipment
already in place at the Wyodak Plant, the Company will be granted beginning
in the year 2000 approximately 1,800 allowances per year in excess to the
needs of its 20 percent interest in the Wyodak Plant.
None of the Company's existing wholly owned power plants will require
air allowances. Neil Simpson Unit #2 will require approximately 850 air
allowances each year beginning in 2000. Allowances required for Neil Simpson
Unit #2 will come from the allowances allocated as the Company's share of the
Wyodak Plant.
By voluntarily complying with the requirements of Phase I of the Clean
Air Act Amendments, and obtaining approval from the Environmental Protection
Agency, the Company is expected to be able to receive an advance of its air
allowances at the Wyodak Plant for the years 1995 and 1996, that can in turn
be sold. This requires a host unit Phase I facility to substitute the Wyodak
Plant air allowances for its requirements. The Company has located a host
unit Phase I facility and entered into an agreement for the sale of a portion
of the Company's allowances as a substitution unit, with the allowances to be
taken by the host unit sometime after 1995. This transaction is subject to
EPA approval, which is expected to require the Company to then pay these
allowances back to EPA ten to twenty years after the sale.
Additional sales of allowances prior to the year 2000 by facilities
voluntarily complying with Phase I appear to be in serious doubt in view of
recent Environmental Protection Agency proposed action.
Whether funds received from the sale of air allowances can be retained
by the electric utility or flowed through to the benefit of the customers has
yet to be determined in the Company's regulatory jurisdictions.
New Major Emitting Facilities. The Federal Clean Air Act Amendments of
August 7, 1977, require states, among other things, to classify their land
into control areas to prevent significant deterioration of air quality
wherein certain limitations in ambient air quality will be established so as
to allow new major emitting facilities (as defined) to be constructed in
those areas only if the particulate emissions therefrom together with
existing emissions would not cause the ambient air in that area to exceed
those limitations. Wyodak Resources is presently authorized to mine up to
10,000,000 tons per year under its permit and existing clean air laws and
regulations and the Neil Simpson #2 power plant has been permitted at that
site.
Water Quality
All of the power plants operated by Black Hills Power require permits
under the National Pollutant Discharge Elimination System. Renewal
applications for the permits for the Ben French and the Kirk power plants
have been submitted to the DENR, and the permits for the other facilities are
current, including authorizations for storm water discharge.
The Osage plant has recently experienced an inability to meet the permit
levels for pH at one of its discharge points. The nature of the ash
generated at the facility is believed to be the source of the high pH values.
The utilization of the new discharge pond at the site has resulted in a
shorter period of time to allow the pH to neutralize.
Black Hills Power has been working closely with the DEQ and has hired a
consultant in an effort to resolve the problem. In-plant treatment efforts
have not proven successful. CO2 injection equipment currently being
installed at the discharge point is expected, however, to return the effluent
to an acceptable pH level. In the event this effort fails, it will be
necessary to seek a modification of the permit and utilize a sulfuric acid
treatment. The cost of the project including the CO2 equipment is not
expected to exceed $20,000.
No penalties, claims or actions have been taken against the Company
because of the discharge levels, and none are expected. The other plants are
in compliance with their stated permit discharge levels.
Pollution prevention plans are in place for the plant facilities, and
the current Spill Prevention Control and Countermeasures plans are in the
process of being updated, and will include hazardous materials contingency
plans.
Land Quality
Solid Waste Disposal. Black Hills Power disposes of power plant wastes
from its Ben French, Kirk and Osage power plants at several locations at or
near each of said plants. Such disposal is done under authority of permits
either issued or under temporary authority pending action on applications.
An application has been submitted seeking the expansion of the current ash
disposal site for the Ben French power plant and is under consideration by
the DENR. At Osage, a permit was granted for the new ash dam facility, and
use began in October 1993. Applications are pending for reclamation of a
historic disposal site at Osage, for renewal and expansion of its landfill
permit, and for closure of the old ash dam. Management is not aware of any
unusual problems which may arise from locating new sites or from maintaining
the existing disposal sites in full compliance with the law.
Reclamation. Under federal and state laws and regulations, Wyodak
Resources is required to submit to and receive approval from the DEQ for a
complete mining and reclamation plan (Plan) which provides for the orderly
mining, reclaiming and restoring of all land in conformity with all laws and
regulations relating thereto. The current approved State Program Permit
(Permit) authorizes Wyodak Resources to mine coal for a period of five years
up to 1995 in compliance with the Plan and all conditions of the Permit. The
Permit is subject to annual reporting and must be renewed after extensive
review every five years, at which time the DEQ may impose further conditions.
In 1992 Wyodak Resources received a modification of its Permit to include an
additional 37,300,000 tons of reserves acquired through coal lease
modifications.
The Permit imposes a variety of conditions which the DEQ believes are
required to comply with applicable laws and regulations and to establish
reclamation with a minimal impact on land, water and air. These conditions
are continuing and require monitoring of water and land that could reveal
factors unknown at this time. The exact costs of complying with these
conditions cannot be accurately ascertained until years later when
reclamation is completed.
Conditions which could result in material unexpected increases in costs
of reclamation relate to three depressions, the existing south pit depression
and an additional north pit depression and north extension depression which
will result from future mining. Because of the thick coal seam and
relatively shallow overburden, the present Plan for restoration leaves areas
of the mine that will have limited reclamation potential because of their
location in depressions with interior drainage only. While the DEQ has
allowed these depressions in the present Plan as modified, the DEQ has
reserved the right to review and evaluate future mining plans proposed by
Wyodak Resources. Such plans are reviewed for the feasibility and
desirability of causing Wyodak Resources to place additional overburden
generated elsewhere for the purpose of reducing the depressions if the DEQ
finds that the placement is necessary to prevent degradation of more acres
than expected. Each time Wyodak Resources files an application to mine
additional coal reserves, the DEQ extensively reviews the reclamation of the
depressions. The DEQ has allowed the depressions at the minimum acres
specified, and subject to the maintenance of water quality at the sites.
Exceedence of the acreage limitations or degradation of water quality could
result in additional requirements being placed upon Wyodak Resources,
including the placement of additional quantities of overburden in the
depressions and restoring water quality. The extent and costs of reclaiming
the depressions and other reclamation requirements that may be imposed upon
Wyodak Resources cannot be accurately ascertained at this time.
The cost of reclaiming the land is accrued as the coal is mined. While
the reclamation process takes place on a continual basis, much of the
reclamation occurs over an extended period after the area is mined.
Approximately $650,000 is charged to operations as reclamation expense
annually. As of December 31, 1993, accrued reclamation costs were
approximately $7,290,000.
Wyodak Resources supports reclamation procedures which are economically
feasible and consistent with sound environmental practices, but it can give
no assurances that it will be successful in doing so.
General
PCB's. The Company's electrical system contains an undetermined number
of polychlorinated biphenyl (PCB or PCB's) contaminated transformers. PCB's
are believed to have cancer causing and toxic effects on humans and are
heavily regulated in their use and disposal as a toxic substance at levels in
excess of 50 parts per million. Black Hills Power is beginning its third
year of a five-year testing program that is intended to remove PCB
contaminated transformers. If PCBs are present in levels above 50 parts per
million, the equipment is removed from the system and disposed of in
accordance with the current federal Toxic Substances Control Act. A concern
is always present that an incident involving a PCB contaminated transformer
could result in substantial cleanup costs for the Company. Those incidents
which might involve a fire or the release of PCB-contaminated oil into a
waterway are of the greatest concern and result in substantial damage claims.
PCB-contaminated equipment and oils at levels below 50 parts per million
are disposed of through a licensed facility located in Colman, South Dakota.
Those items with contamination at higher levels are transported and disposed
of through an EPA permitted incineration facility located in Deer Park,
Texas. Black Hills Power has exclusively used these facilities for a number
of years, and its management believes the disposal contractors are operating
their respective facilities in full compliance with governmental regulation.
Oil Releases. Two unauthorized oil releases occurred in 1993 as a
result of equipment owned by Black Hills Power. Both involved minor
quantities of petroleum products and only minimal remedial measures were
required by the DENR. No penalties, claims or actions have been taken
against the Company because of the releases, and none are expected.
Underground Storage Tanks. Black Hills Power does not have any
underground storage tanks in operation at this time. The residual
contamination from underground storage tanks that were removed from the
Wyodak Resources mine site was believed to have caused some contamination of
ground waters. The DEQ, however, has not required any further remediation
action at the site.
Ben French Oil Spill. Assessment and remediation efforts have continued
during 1993 on Black Hills Power property located near the Ben French power
plant. The extensive contamination of the site with fuel oil is historic,
but was discovered in 1990 and 1991 when the Company took steps to cleanup a
release caused by an overflow that had resulted from an equipment failure.
The Company hired experts to aid in the assessment and remediation and has
worked closely with the DENR.
Soil borings and the operation of monitoring wells on the perimeters of
Black Hills Power's property show no indication of contamination beyond Black
Hills Power's property at this time. The confinement of the contamination is
attributed to the contour of the land at the site. The fuel oil is, however,
migrating toward a natural drainage area which could allow it to enter area
waterways. In such event, the clean-up costs could be greatly increased. In
order to prevent such an occurrence, one duct-bank remediation system is
currently in place and a second such system is expected to be installed in
1994. These systems are designed to channel the oil to a recovery location.
Additional monitoring wells were installed in the area during 1993, and
fuel oil as a free product continues to be removed from the site on a weekly
basis. Although the quantity of free product being removed is greatly
diminished from that earlier recovered, no time frame for the completion of
the remediation work has been established.
Costs for the cleanup in excess of $20,000 are expected to be reimbursed
from the South Dakota Petroleum Release Compensation Fund up to a $1,000,000
limit. To date, no penalties, claims or actions have been taken or
threatened against the Company because of this release. No assurances can be
given, however, that no actions will be taken or what the eventual cost of
this cleanup will be.
Mush Creek Cleanup. In 1993 Western Production undertook the clean-up
of an unpermitted oil disposal site located near its facilities outside
Newcastle, Wyoming. The initial disposal at the site is believed to have
occurred sometime in 1983 or 1984 before Western Production ownership. The
crude oil and some contaminated soils have been removed from the site and
properly disposed of under the authorizations of the DEQ. The Company
intends to apply for the renewal of the existing solid waste permit for the
remediation of the site. The extent of the remaining clean-up effort
required is not known at this time. Western Production plans further testing
of soils and groundwater in the area of the site to determine the potential
costs.
The clean-up effort was begun in cooperation with other businesses who
had used the disposal site, but in view of the higher-than-expected costs,
disputes have now surfaced over responsibility for the cleanup. The cost of
the project to date exceeds $140,000, but future costs remain undetermined
pending further site assessment. To date, only $7,500 of these costs have
been paid by others.
Electromagnetic Fields
The SDPUC has opened a docket to study electromagnetic fields ("EMF")
issues. A number of studies have examined the possibility of adverse health
effects from EMF. Certain states have enacted regulations to limit the
strength of magnetic fields at the edge of transmission line rights-of-way.
None of the jurisdictions in which Black Hills Power operates has adopted
formal rules or programs with respect to EMF or EMF considerations in the
siting of electric facilities. Black Hills Power expects that public
concerns will make it more difficult to site and construct new power lines
and substations in the future. It is uncertain whether Black Hills Power's
operations may be adversely affected in other ways as a result of EMF
concerns. Black Hills Power is designing all new transmission lines under
EMF standards adopted by other states so as to minimize the EMF effect.
Summary
The Company makes ongoing efforts to comply with new as well as existing
environmental laws and regulations to which it is subject. It is unable to
estimate the ultimate effect of existing and future environmental
requirements upon its operations.
EMPLOYEES
At December 31, 1993, the number of employees of the Company (including
Black Hills Power), Wyodak Resources and Western Production were 359, 58 and
42, respectively, for a total of 459 employees.
CORPORATE DEVELOPMENT
The Company's strategic plan for corporate development includes the plan
to search for opportunities for growth in its present business segments. The
Company's primary focus will be in the development of additional mine-mouth
power plants and Wyodak Resources' coal mine.
To encourage the further development of Wyodak Resources' coal and to
continue to assure the availability of electric generation in the future, the
Company's plan is to cause Black Hills Power to participate in the
construction of new generating facilities as they are needed by Black Hills
Power either individually, with other traditional electric utilities or non-
utility entities at Wyodak Resources' mine. See--ELECTRIC POWER SALES AND
SERVICE TERRITORY--Future Wholesale Opportunities and COMPETITION IN ELECTRIC
UTILITY BUSINESS under this Item 1.
Management believes that surplus power in the western United States is
decreasing and estimates that new plants will be required in the middle to
late 1990's. Due to a four- to six-year lead time to construct plants,
management believes the planning process should be in process.
Management is continuing to explore the possibility of the Company
engaging in the business, either by itself or in concert with others, of an
exempt wholesale generator. This generation would be designed to sell power
to traditional electric utilities other than Black Hills Power. (See the
discussion of the new Energy Policy Act of 1992 under COMPETITION IN ELECTRIC
UTILITY BUSINESS--Competition in Electric Generation under this Item 1.) The
negative aspects of being able to engage in that business are the small size
and lack of resources of the Company. The independent power producing
business is concentrating in companies of a much larger size than the
Company. However, the Company does have expertise in the power generation
business and the potential for low-cost generation at Wyodak Resources' coal
mine, the site of the Wyodak Plant, Neil Simpson Unit #1 and Neil Simpson
Unit #2. If the Company is precluded from generating its own electric power
needs, it may find a niche in the independent power business.
Western Production continues to locate opportunities to acquire existing
oil and gas production, to develop additional oil reserves by drilling and to
investigate investing in oil and gas working interests with other entities.
Opportunities depend on the sensitivity of oil and gas prices that are all
beyond the control of Western Production.
<PAGE>
ITEM 2. PROPERTIES
UTILITY PROPERTIES
The following table provides information on the generating plants of
Black Hills Power. During 1993, 99 percent of the fuel used in electric
generation, measured in Btus (British thermal units), was coal.
<TABLE>
<CAPTION>
Generating Units Plant Totals
Net Generation
Twelve Months
Nameplate Ended
Year of Rating Principal December 31, 1993
Installation (Kilowatts)(a) Fuel (thousands of KWH)
<S> <C> <C> <C> <C>
Osage Plant 1948 11,500 Coal
(Osage, Wyoming) 1950 11,500 Coal
1952 11,500 Coal 237,936
Kirk Plant 1956 18,750 Coal 105,149
(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 161,168
Neil Simpson Unit #1 1969 21,760 Coal 153,795
(Wyodak, Wyoming)
Wyodak Plant 1978(c) 72,400(c) Coal 569,036
(Wyodak, Wyoming)
Total 283,210 1,227,084
<FN>
(a) Nameplate rating is the capacity assigned to the generating unit by
the manufacturer. Actual generating capability depends upon duration
of usage, conditions of operation and other factors. See--ELECTRIC
POWER SUPPLY--Reserves for an Analysis of the Net Dependable
Capability--Summer Rating for these resources.
(b) These combustion turbines are those referenced by the reserve capacity
integration agreement with Pacific Power. See ELECTRIC POWER SUPPLY
under Item 1 and the PacifiCorp Settlement.
(c) Black Hills Power's 20 percent interest. See Note 6 of "Notes to
Consolidated Financial Statements" appended hereto and the following
discussion concerning the acquisition of the Wyodak Plant at
CONSTRUCTION AND CAPITAL PROGRAM under Item 1.
</TABLE>
Black Hills Power owns transmission lines and distribution systems in
and adjoining the communities served consisting of 445 miles of 230 kV, 4
miles of 115 kV, 532 miles of 69 kV, 8 miles of 47 kV and numerous
distribution lines of less voltage. Black Hills Power owns a service center
in Rapid City, several district office buildings at various locations within
its service area, and an eight-story home office building at Rapid City,
South Dakota housing its home office on four floors, with the balance of the
building rented to three tenants.
MINING PROPERTIES
Wyodak Resources is engaged in mining and processing sub-bituminous coal
near Gillette in Campbell County, Wyoming. The coal averages 8,000 Btus per
pound. Mining rights to the coal are based upon coal owned and five federal
leases. The estimated tons of recoverable coal from each source as of
December 31, 1993 are set forth in the following table:
<TABLE>
<CAPTION>
Estimated Tons of
Recoverable Coal
(in thousands)
<S> <C>
Fee coal 1,381
Federal lease dated May 1, 1959 19,763
Federal lease dated April 1, 1961 7,703
Federal lease dated October 1, 1965 117,534
Federal lease dated September 28, 1983 20,355
Federal lease dated March 1, 1983 22,604
189,340
</TABLE>
Coal reserves are estimated at 189,340,000 tons of which approximately
32,250,000 tons are committed to be sold to the Wyodak Plant, approximately
10,000,000 tons to Black Hills Power's other plants, and 20,000,000 tons for
Neil Simpson Unit #2. Purchase options are granted on 52,000,000 tons of
which options for 50,000,000 tons can be exercised only if Wyodak Resources
has not committed the coal reserves to other buyers prior to such exercise.
Because the coal purchase price that will be paid if the options are
exercised would be substantially higher than prices being paid under new coal
contracts, it is unlikely that the options will be exercised.
In 1989 an oil and gas developer established two oil-producing wells on
the north portion of the lease dated October 1, 1965. The oil was leased to
the developer by the owner of the oil rights, the State of Wyoming, and the
coal is leased by Wyodak Resources from the owner of the coal rights, the
federal government through its BLM. The oil is produced from a formation at
a depth of approximately 9,000 feet while the coal is mined by the open pit
method at a depth of 200 to 300 feet. Therefore, it is impossible to mine
coal in the vicinity of the oil wells and maintain and operate the oil wells
at the same time. The law is uncertain as to who would have priority under
these circumstances. To date this conflict would affect approximately
15,000,000 tons of coal. At this time Wyodak Resources does not plan any
mining operations at the site of the oil wells for at least 15 years, but the
life of oil wells may extend for many years beyond 15. To mitigate its
potential damages, Wyodak Resources has negotiated an option to purchase the
oil wells at fair market value if a mining conflict should occur.
Each federal lease grants Wyodak Resources the right to mine all of the
coal in the land described therein, but the government has the right at the
end of 20 years from the date of the lease to readjust royalty payments and
other terms and conditions. All of the federal leases provide for a royalty
of 12.5 percent of the selling price of the coal.
Each federal lease requires diligent development to produce at least one
percent of all recoverable reserves within either 10 years from the
respective dates of the 1983 leases or 10 years from the date of adjustment
of the other leases. Each lease further requires a continuing obligation to
mine, thereafter, at an average annual rate of at least one percent of the
recoverable reserves. All of the federal leases and its remaining fee coal
constitute one logical mining unit and is treated as one lease for the
purpose of determining diligent development and continuing operation
requirements. All coal is to be mined within 40 years from 1992, the date of
the logical mining unit. Even if federal coal leases are not mined out in 40
years, the federal coal is likely to be available for further lease after the
40 years. Wyodak Resources' current coal agreements require production which
should be sufficient to satisfy the diligent development and continual
operation requirements of present law. Wyodak Resources will require
additional coal sales in order to mine all of its federal coal within the 40
year requirement.
The law, which requires that an owner of land that is primarily devoted
to agriculture must approve a reclamation plan before the state will approve
a permit for open pit mining, affects approximately 3,100,000 tons of the
recoverable coal included in the federal lease dated October 1, 1965. Wyodak
Resources has excluded these tons of coal from its mine plan and will not
mine such coal until a surface consent has been negotiated or the right to
mine has been settled by litigation.
Approximately 32,250,000 tons of the Federal Coal Lease dated October 1,
1965, has been mortgaged as security for the performance of its obligations
under the coal supply agreement for the Wyodak Plant.
In 1992, Pacific Power, the Company and Wyodak Resources entered into an
agreement providing for the construction of new coal handling facilities.
The new coal handling facilities consist of an in-pit system (consisting of
in-pit movable crushers and a conveyor to a secondary crusher transfer
point), an out-of-pit system (consisting of the secondary crusher), new truck
load-out facilities, a conveyor to deliver coal to Neil Simpson Unit #1 and
a conveyor to deliver coal to the Wyodak Plant and eventually to Neil Simpson
Unit #2. The total construction costs of these facilities is expected to be
$24,500,000, of which Pacific Power will pay $19,000,000 and Wyodak Resources
$5,500,000. The reason for the large amount being paid by Pacific Power is
that under the PacifiCorp Settlement, Pacific Power was obligated to pay up
to $15,000,000, plus an amount to adjust for inflation since 1987, for new
coal handling facilities which were required to extend the mining of coal to
another pit, the Peerless area, situated west of the Wyodak Plant. Under the
agreement among PacifiCorp, the Company and Wyodak Resources, Wyodak
Resources will operate the in-pit system, the conveyor to Neil Simpson Unit
#1 and the truck load-out system, and PacifiCorp will operate the secondary
crusher transfer building and the conveyor to the Wyodak Plant. The
agreement provides for the use of the new coal handling facilities to deliver
coal to the Wyodak Plant, Neil Simpson Unit #1, Neil Simpson Unit #2, the
truck load-out and, if there is sufficient capacity, to additional power
plants to be constructed at the site. The agreement provided for Black Hills
Power to own certain undivided interests of these facilities, but Black Hills
Power and Wyodak Resources have entered into an agreement providing for the
transfer of all interests of Black Hills Power in these facilities to Wyodak
Resources. This transfer is consistent with the agreement of Wyodak
Resources to deliver Black Hills Power completely processed coal.
OIL AND GAS PROPERTIES
Western Production operates 347 wells as of December 31, 1993. The vast
majority of these wells are in the Finn Shurley Field, located in Weston and
Niobrara Counties, Wyoming. Twelve of the wells Western Production operates
are located in Adams and Weld Counties, Colorado, two are located in Washakie
County, Wyoming and two are located in Fall River County, South Dakota.
Western Production does not operate but owns a working interest in 39
producing properties located in Wyoming, Kansas, Colorado, Montana, North
Dakota and Texas. The majority of wells operated by Western Production were
drilled between 1977 and 1984, prior to its acquisition by Wyodak Resources.
They were drilled under drilling programs wherein working interests were sold
to various investors. Approximately 232 investors own working interests in
wells operated by Western Production.
Western Production owns a 44.7 percent interest in a natural gas
processing plant also located at the Finn Shurley Field. The gas plant is
operated by Western Gas Resources, Inc. of Denver, Colorado, which owns a 50
percent interest therein and processes all the gas produced from the Finn
Shurley Field and the Boggy Creek Field.
The following table summarizes Western Production's estimated quantities
of proved developed and undeveloped oil and natural gas reserves at
December 31, 1993 and 1992, and a reconciliation of the changes between these
dates using constant product prices for the respective years. These
estimates are based on reserve reports by Ralph E. Davis Associates, Inc. (an
independent engineering company selected by the Company). Such reserve
estimates are based upon a number of variable factors and assumptions which
may cause these estimates to differ from actual results.
<PAGE>
<TABLE>
<CAPTION>
1993 1992
Oil Gas Oil Gas
(in thousands of barrels of oil
and MCF of gas)
<S> <C> <C> <C> <C>
Proved developed and
undeveloped resources:
Balance at beginning of year 2,199 3,243 2,524 4,799
Production (327) (777) (247) (379)
Additions 259 1,847 193 272
Revisions to previous
estimates due to changed
economic conditions (1,015) (1,554) (271) (1,449)
Balance at end of year 1,116 2,759 2,199 3,243
Proved developed reserves at
end of year included above 1,116 2,759 1,630 2,633
Year-end prices $13.00 $ 2.35 $18.75 $ 1.65
</TABLE>
Western Production has approximately 99,000 gross and 65,000 net acres
of oil and gas leases, out of which 25,000 gross and 15,000 net acres are
producing and 74,000 gross and 50,000 net acres are undeveloped.
Approximately 23 percent of the undeveloped acres are held by production
thereby not requiring annual delay rental payments. No representations are
made that reserves can be attributed to any undeveloped oil and gas leases.
Undeveloped leasehold that are not held by production have varying provisions
but generally terminate if oil and gas is not produced within the primary
term of the lease.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in minor routine
administrative proceedings and litigation incidental to the businesses, none
of which, in the opinion of management, will have a material effect on the
consolidated financial statements of the Company.
<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 1993.
EXECUTIVE OFFICERS OF THE COMPANY
The following is a list of all executive officers of the Company. There
are no family relationships among them. Officers are normally elected
annually.
Daniel P. Landguth, born May 9, 1946, Chairman, President, and Chief
Executive Officer of Black Hills Corporation
Mr. Landguth was elected to his present position in January 1991.
He had served as President of Black Hills Corporation since October
1989, President and Chief Operating Officer of Black Hills Power
since June 1987, and Senior Vice President and Chief Operating
Officer since 1985.
Dale E. Clement, born August 1, 1933, Senior Vice President - Finance
Mr. Clement was elected to his present position in September 1989.
He had served on the Board of Directors since 1979. Prior to
joining the Company he was Dean and Professor of Finance at the
University of South Dakota, School of Business.
Joseph E. Rovere, born July 7, 1929, Vice President - Public Affairs/District
Administration
Mr. Rovere was elected to his present position in October 1982.
Roxann R. Basham, born August 6, 1961, Secretary and Treasurer
Mrs. Basham was elected to her present position January 1, 1993.
She had served as Assistant Secretary/Treasurer since May 1991 and
as Financial Analyst since February 1985.
Gary R. Fish, born August 1, 1958, Controller
Mr. Fish was elected to his present position in August 1988.
Everett E. Hoyt, born August 8, 1939, President and Chief Operating Officer
of Black Hills Power
Mr. Hoyt was elected to his present position in October 1989.
Prior to joining the Company he was Senior Vice President - Legal,
Corporate Secretary, and Assistant Treasurer of Northwestern Public
Service Company.
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The information required by Item 5 is provided in the Annual Report to
Shareholders of the Company for the year ended December 31, 1993, on page 34
appended hereto and market price information is shown in Note 13 of "Notes to
Consolidated Financial Statements" on page 31 of the Annual Report to
Shareholders of the Company for the year ended December 31, 1993, appended
hereto.
ITEM 6. SELECTED FINANCIAL DATA
The information required by Item 6 is provided under an identical
caption in the Annual Report to Shareholders of the Company for the year
ended December 31, 1993, on page 31 appended hereto.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION
The information required by Item 7 is provided under a similar caption
in the Annual Report to Shareholders of the Company for the year ended
December 31, 1993, on pages 14 through 20 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, 1993, on pages 22 through 31 appended hereto. Selected quarterly
financial data is shown in Note 13 of "Notes to Consolidated Financial
Statements" on page 31 of the Annual Report to Shareholders of the Company
for the year ended December 31, 1993, appended hereto.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No change of accountants or disagreements on any matter of accounting
principles or practices or financial statement disclosure have occurred.
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Company is incorporated
herein by reference to the Proxy Statement for the Annual Shareholders'
Meeting to be held May 24, 1994.
For information regarding the executive officers of the Company refer to
Part I, Item 4.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding management remuneration and transactions is
incorporated herein by reference to the Proxy Statement for the Annual
Shareholders' Meeting to be held May 24, 1994.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Information regarding the security ownership of certain beneficial
owners and management is incorporated herein by reference to the Proxy
Statement for the Annual Shareholders' Meeting to be held May 24, 1994.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions is
incorporated herein by reference to the Proxy Statement for the Annual
Shareholders' Meeting to be held May 24, 1994.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) 1. Index to Consolidated Financial Statements
Page
Reference*
Report of Independent Public Accountants . . . . . . 21
Consolidated Statements of Income and Retained Earnings
for the three years ended December 31, 1993 . . . . 22
Consolidated Statements of Cash Flows for
the three years ended December 31, 1993 . . . . . . 23
Consolidated Balance Sheets at December 31, 1993
and 1992 . . . . . . . . . . . . . . . . . . . . . . 24
Consolidated Statements of Capitalization at
December 31, 1993 and 1992 . . . . . . . . . . . . . 25
Notes to Consolidated Financial Statements . . . . . 26-31
2. Schedules **
V Property, Plant, and Equipment for the three years
ended December 31, 1993
VI Accumulated Depreciation and Depletion of Property,
Plant, and Equipment for the three years ended
December 31, 1993
IX Short-Term Borrowings for the three years ended
December 31, 1993
* Page References are to the incorporated portion of the Annual
Report to Shareholders of the Company for the year ended December 31,
1993.
** All other schedules have been omitted because of the absence of the
conditions under which they are required or because the required
information is included elsewhere in the financial statements
incorporated by reference in the Form 10-K.
3. Exhibits
*3(a) Bylaws dated December 10, 1991 (Exhibit 3(a) to Form 10-K for
1991).
*3(b) Restated Articles of Incorporation dated July 28, 1986
(Exhibit 3(b) to Form 10-K for 1986). Articles of Amendment
to Restated Articles of Incorporation dated May 21, 1987,
(Exhibit 3(b) to Form 8-K for May 1987, File No. 0-0164).
Articles of Amendment to Restated Articles of Incorporation
dated May 16, 1989 (Exhibit 3(b) to Form 10-K for 1989).
Articles of Amendment to Restated Articles of Incorporation
dated May 28, 1992 (Exhibit 3(b) to Form 10-K for 1992).
Articles of Correction to Amendment to Restated Articles of
Incorporation, dated September 13, 1993 (Exhibit 4.03 to Form
S-3 dated September 22, 1993, Registration No. 33-69234).
*4(a) Reference is made to Article Fourth (7) of the Restated
Articles of Incorporation of the Company and the Articles of
Amendment to Restated Articles of Incorporation (Exhibit 3(b)
hereto).
*4(b) Indemnification Agreement and Company and Directors' and
Officers' indemnification insurance (Exhibit 4(b) to Form 10-K
for 1987).
*4(c) Indenture of Mortgage and Deed of Trust, dated
September 1, 1941, and as amended by supplemental
indentures (Exhibit B to Form 8-K, File No. 2-4832);
(Exhibit 7-B, File No. 2-6576); (Exhibit 7-C, File
No. 2-7695); (Exhibit 7-D, File No. 2-8157);
(Exhibit A to Form 10-K for fiscal year 1950,
File No. 2-4832); (Exhibit 4-I, File No. 2-9433);
(Exhibit 4-H, File No. 2-13140); (Exhibit 4-I, File
No. 2-14829); (Exhibits 4-J and 4-K, File No.
2-16756); (Exhibits 4-L, 4-M, and 4-N, File No.
2-21024); (Exhibits 2(q), 2(r), 2(s), 2(t), 2(u),
and 2(v) to Form S-7, File No. 2-57661); (Exhibit
(b) to Form 8-K for February 1977, File No. 2-4832);
(Exhibit II-1 to Form 10-Q for quarter ended
April 30, 1977, File No. 2-21024); (Exhibit II-1 to
Form 10-Q for quarter ended July 31, 1977, File No.
2-21024); (Exhibit 4(b) to Form S-3, File No.
2-81643); (Exhibit II-6a to Form 10-Q for quarter
ended September 30, 1986, File No. 0-0164); (Exhibit
II-6a to Form 10-Q for quarter ended September 30,
1987, File No. 0-0164); (Exhibit II-6a to Form
10-Q for quarter ended September 30, 1988, File No.
0-0164); and (Exhibit 4(d) and 4(e) to Post-
Effective Amendment No. 1 to Form S-8, File No.
33-15868).
*10(a) Coal Supply Agreement dated May 12, 1975, between
Wyodak Resources Development Corp. and the South
Dakota Cement Commission (Exhibit 5(d) to Form S-7,
File No. 2-57661). Extension of Coal Supply
Agreement dated June 2, 1980, and First Supplement
dated February 8, 1983 (Exhibit 10(c) to Form 10-K
for 1983). Second Supplement to Extension of Coal Supply
Agreement dated June 1, 1985 (Exhibit 10(c) to Form 10-K for
1985). Third Supplement to Extension of Coal Supply Agreement
dated July 14, 1986 (Exhibit 10(c) to Form 10-K for 1986).
Fourth Supplement to Extension of Coal Supply Agreement dated
December 1, 1987 (Exhibit 10(c) to Form 10-K for 1987). Fifth
Supplement to Extension of Coal Supply Agreement dated March
12, 1992 (Exhibit 10(a) to Form 10-K for 1992).
*10(b) Agreement for Transmission Service and The Common
Use of Transmission Systems dated January 1, 1986,
among the Company, Basin Electric Power Cooperative,
Rushmore Electric Power Cooperative, Inc.,
Tri-County Electric Association, Inc., Black Hills
Electric Cooperative, Inc., and Butte Electric
Cooperative, Inc. (Exhibit 10(d) to Form 10-K for
1987).
*10(c) Restated and Amended Coal Supply Agreement for Neil
Simpson Unit #2 dated February 12, 1993 (Exhibit
10(c) to Form 10-K for 1992).
*10(d) Coal Supply Agreement and First Amendment dated
September 1, 1977, between the Company and Wyodak
Resources Development Corp. (Exhibit 5(g) to Form
S-7, File No. 2-60755). Second Amendment to Coal
Supply Agreement dated November 2, 1987 (Exhibit
10(f) to Form 10-K for 1987).
*10(e) Coal Lease dated May 1, 1959, between Wyodak
Resources Development Corp. and the Federal
Government (Exhibit 5(i) to Form S-7, File No.
2-60755). Modified coal lease dated January 22,
1990, between Wyodak Resources Development Corp.
and the Federal Government (Exhibit 10(h) to Form
10-K for 1989).
*10(f) Coal Lease dated April 1, 1961, between Wyodak
Resources Development Corp. and the Federal
Government (Exhibit 5(j) to Form S-7, File No.
2-60755). Modified coal lease dated January 22,
1990, between Wyodak Resources Development Corp.
and the Federal Government (Exhibit 10(i) to Form
10-K for 1989).
*10(g) Coal Lease dated October 1, 1965, between Wyodak
Resources Development Corp. and the Federal
Government, as amended (Exhibit 5(k) to Form S-7,
File No. 2-60755). Modified coal lease dated
January 22, 1990, between Wyodak Resources Development Corp.
and the Federal Government (Exhibit 10(j) to Form 10-K for
1989).
*10(h) Participation Agreement dated May 16, 1978, and
various related agreements dated June 8, 1978,
including, without limitation, Lease Agreement,
Amended and Restated Coal Supply Agreement, Coal
Supply System Agreement and Security Agreement, and
Real Estate Mortgage (all relating to the lease
financing of the Wyodak Plant and the dedication by
Wyodak Resources Development Corp. of coal deposits
with respect thereto) filed pursuant to item 6(b) of
Amendment No. 1 to Registrant's Current Report on
Form 8-K for June 1978 and located in Commission
File No. 2-4832. Further Restated and Amended Coal
Supply Agreement dated May 5, 1987 (Exhibit 10(k)
to Form 10-K for 1987).
*10(i) Coal Supply Agreement dated August 24, 1978, between
Wyodak Resources Development Corp. and the City of
Grand Island, Nebraska (Exhibit 5(l) to Form S-7,
File No. 2-64014). Restated and Amended Coal Supply
Agreement dated March 4, 1983 (Exhibit 10(l) to Form
10-K for 1983). First Amendment to Restated
and Amended Coal Supply Agreement dated October 29,
1987 (Exhibit 10(l) to Form 10-K for 1987).
*10(j) Power Sales Agreement dated December 31, 1983,
between Pacific Power & Light Company and the
Company (Exhibit 7(b) to Form 8-K for January 1984,
File No. 0-0164).
*10(k) Coal Supply Agreement for Wyodak Unit #2 dated
February 3, 1983, and Ancillary Agreement dated
February 3, 1982, between Wyodak Resources
Development Corp. and Pacific Power & Light Company
and the Company (Exhibit 10(o) to Form 10-K for
1983). Amendment to 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).
*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(bb) Compensation Plan for Outside Directors (Exhibit 10(bb) to
Form 10-K for 1992).
*10(cc) Retirement Plan for Outside Directors dated January 1, 1993
(Exhibit 10(cc) to Form 10-K for 1992).
*10(dd) Pension Equalization Plan of Black Hills Corporation dated
January 1, 1990 (Exhibit 10(dd) to Form 10-K for 1992).
10(dd) Amendment #1 to Pension Equalization Plan of Black Hills
Corporation dated April 27, 1993.
10(ee) Black Hills Corporation 1994 Executive Gainsharing Program.
10(ff) Black Hills Corporation 1994 Results Compensation Program.
*10(gg) Pension Plan of Black Hills Corporation as amended and
restated effective October 1, 1989. First amendment to the
Pension Plan of Black Hills Corporation dated September 25,
1992. Amendment to the Pension Plan of Black Hills
Corporation dated December 4, 1992. Amendment to the Pension
Plan of Black Hills Corporation dated February 5, 1993
(Exhibit 10(ff) to form 10-K for 1992).
*10(hh) Agreement for Supplemental Pension Benefit for Everett E. Hoyt
dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for 1992).
*10(ii) Agreement for Supplemental Pension Benefit for Dale E. Clement
dated December 19, 1991 (Exhibit 10(hh) to Form 10-K for
1992).
13 Annual Report to Shareholders of the Registrant for
the year ended December 31, 1993.
22 Subsidiaries of the Registrant.
23 Consent of Independent Public Accountants.
_________________________
* Exhibits incorporated by reference.
(b) No reports on Form 8-K have been filed in the quarter ended
December 31, 1993.
(c) See (a) 3. above.
(d) See (a) 2. above.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements included in Black Hills
Corporation's 1993 Annual Report to Shareholders incorporated by reference in
this Form 10-K, and have issued our report thereon dated January 28, 1994.
Our audit was made for the purpose of forming an opinion on those statements
taken as a whole. The schedules listed as a part of Item 14.(a)2. in this
Form 10-K are the responsibility of the Company's management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audit
of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Minneapolis, Minnesota,
January 28, 1994
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
BLACK HILLS CORPORATION
By DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman,
President, and Chief Executive
Dated: March , 1994
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
DANIEL P. LANDGUTH Director and Principal March , 1994
Daniel P. Landguth (Chairman, Executive Officer
President, and Chief Executive)
DALE E. CLEMENT Director and Principal March , 1994
Dale E. Clement (Senior Vice Financial Officer
President - Finance)
GARY R. FISH Principal Accounting March , 1994
Gary R. Fish (Controller) Officer
GLENN C. BARBER Director March , 1994
Glenn C. Barber
BRUCE B. BRUNDAGE Director March , 1994
Bruce B. Brundage
MICHAEL B. ENZI Director March , 1994
Michael B. Enzi
JOHN R. HOWARD Director March , 1994
John R. Howard
EVERETT E. HOYT Director and Officer March , 1994
Everett E. Hoyt (President
and Chief Operating Officer
of Black Hills Power)
KAY S. JORGENSEN Director March , 1994
Kay S. Jorgensen
CHARLES T. UNDLIN Director March , 1994
Charles T. Undlin
<PAGE>
<TABLE>
Schedule V
BLACK HILLS CORPORATION
Property, Plant, and Equipment
Year ended December 31, 1993
<CAPTION>
Balance at Additions
Beginning at Retire-
of Year Cost (a) ments(b)
(in thousands)
<S> <C> <C> <C>
Utility property:
Production $143,212 $ 2,549 $2,440
Transmission and
distribution 141,324 12,483 1,115
General 23,905 4,422 776
308,441 19,454 4,331
Construction work in
progress 9,829 6,478 -
Total utility property 318,270 25,932 4,331
Other property:
Coal mining
Coal land and land rights 7,117 - -
Coal leases and rights 7,188 - -
Buildings 1,183 404 7
Mining equipment 28,688 7,154 98
Housing properties 105 - 25
Oil and gas production 28,465 6,933 3,027
Other 41 - -
72,787 14,491 3,157
Construction work in
progress 202 (133) -
Total other property 72,989 14,358 3,157
Total $391,259 $40,290 $7,488
(continued)
<CAPTION>
Other Balance at
Changes End of
add(deduct) Year
(in thousands)
<S> <C> <C>
Utility property:
Production $ 4 $143,325
Transmission and
distribution 10 152,702
General - 27,551
14 323,578
Construction work in
progress 1,967 18,274
Total utility property 1,981 341,852
Other property:
Coal mining
Coal land and land rights - 7,117
Coal leases and rights - 7,188
Buildings (2) 1,578
Mining equipment (106) 35,638
Housing properties - 80
Oil and gas production - 32,371
Other - 41
(108) 84,013
Construction work in
progress - 69
Total other property (108) 84,082
Total $1,873 $425,934
<FN>
(a) See summary of significant accounting policies in consolidated financial
statements (Note 1) for information relative to allowance for funds used
during construction included in additions.
(b) Costs applicable to retirements, other than non-utility property, are
charged to the accumulated depreciation account (Schedule VI).
</TABLE>
<PAGE>
___________________________________________________________________________
Schedule VI
BLACK HILLS CORPORATION
Accumulated Depreciation and Depletion of Property, Plant, and Equipment
Year ended December 31, 1993
<TABLE>
<CAPTION>
Additions
Balance at Charged to Balance at
Beginning Costs and Retire- End of
of Year Expenses ments Year
(in thousands)
<S> <C> <C> <C> <C>
Utility property $104,582 $ 9,990 $4,130 $110,442
Other property-
Coal mining 18,827 1,953 106 20,674
Oil and gas
production 9,481 4,146 251 13,376
28,308 6,099 357 34,050
Total $132,890 $16,089 $4,487 $144,492
</TABLE>
<PAGE>
<TABLE>
Schedule V
BLACK HILLS CORPORATION
Property, Plant, and Equipment
Year ended December 31, 1992
<CAPTION>
Balance at Additions
Beginning at Retire-
of Year Cost (a) ments(b)
(in thousands)
<S> <C> <C> <C>
Utility property:
Production $139,791 $ 4,155 $ 734
Transmission and
distribution 135,408 7,217 1,301
General 24,031 1,378 1,504
299,230 12,750 3,539
Construction work in
progress 7,072 2,757 -
Total utility property 306,302 15,507 3,539
Other property:
Coal mining
Coal land and land rights 7,117 - -
Coal leases and rights 7,188 - -
Buildings 1,125 58 -
Mining equipment 23,893 4,822 27
Housing properties 111 - 6
Oil and gas production 23,486 5,180 201
Other 41 - -
62,961 10,060 234
Construction work in
progress 81 121 -
Total other property 63,042 10,181 234
Total $369,344 $25,688 $3,773
(continued)
<CAPTION>
Other Balance at
Changes End of
add(deduct) Year
(in thousands)
<S> <C> <C>
Utility property:
Production $ - $143,212
Transmission and
distribution - 141,324
General - 23,905
- 308,441
Construction work in
progress - 9,829
Total utility property - 318,270
Other property:
Coal mining
Coal land and land rights - 7,117
Coal leases and rights - 7,188
Buildings - 1,183
Mining equipment - 28,688
Housing properties - 105
Oil and gas production - 28,465
Other - 41
- 72,787
Construction work in
progress - 202
Total other property - 72,989
Total $ - $391,259
<FN>
(a) See summary of significant accounting policies in consolidated financial
statements (Note 1) for information relative to allowance for funds used
during construction included in additions.
(b) Costs applicable to retirements, other than non-utility property, are
charged to the accumulated depreciation account (Schedule VI).
</TABLE>
<PAGE>
___________________________________________________________________________
<TABLE>
Schedule VI
BLACK HILLS CORPORATION
Accumulated Depreciation and Depletion of Property, Plant, and Equipment
Year ended December 31, 1992
<CAPTION>
Additions
Balance at Charged to Balance at
Beginning Costs and Retire- End of
of Year Expenses ments Year
(in thousands)
<S> <C> <C> <C> <C>
Utility property $ 98,589 $ 9,614 $3,621 $104,582
Other property-
Coal mining 17,377 1,482 32 18,827
Oil and gas
production 6,608 2,764 (109) 9,481
23,985 4,246 (77) 28,308
Total $122,574 $13,860 $3,544 $132,890
</TABLE>
<PAGE>
<TABLE>
Schedule V
BLACK HILLS CORPORATION
Property, Plant, and Equipment
Year ended December 31, 1991
<CAPTION>
Balance at Additions
Beginning at Retire-
of Year Cost (a) ments(b)
(in thousands)
<S> <C> <C> <C>
Utility property:
Production $127,586 $12,180 $ 85
Transmission and
distribution 127,970 8,018 580
General 19,906 4,955 830
275,462 25,153 1,495
Construction work in
progress 2,360 4,712 -
Total utility property 277,822 29,865 1,495
Other property:
Coal mining
Coal land and land rights 6,107 1,009 -
Coal leases and rights 7,188 - -
Buildings 1,125 - -
Mining equipment 23,745 171 23
Oil and gas 1,687 - -
Housing properties 111 - -
Oil and gas production 16,000 5,987 188
Other 41 - -
56,004 7,167 211
Construction work in
progress 132 (51) -
Total other property 56,136 7,116 211
Total $333,958 $36,981 $1,706
(continued)
<CAPTION>
Other Balance at
Changes End of
add(deduct) Year
(in thousands)
<S> <C> <C>
Utility property:
Production $ 110 $139,791
Transmission and
distribution - 135,408
General - 24,031
110 299,230
Construction work in
progress - 7,072
Total utility property 110 306,302
Other property:
Coal mining
Coal land and land rights 1 7,117
Coal leases and rights - 7,188
Buildings - 1,125
Mining equipment - 23,893
Oil and gas (1,687) -
Housing properties - 111
Oil and gas production 1,687 23,486
Other - 41
1 62,961
Construction work in
progress - 81
Total other property 1 63,042
Total $ 111 $369,344
<FN>
(a) See summary of significant accounting policies in consolidated financial
statements (Note 1) for information relative to allowance for funds used
during construction included in additions.
(b) Costs applicable to retirements, other than non-utility property, are
charged to the accumulated depreciation account (Schedule VI).
</TABLE>
<PAGE>
___________________________________________________________________________
<TABLE>
Schedule VI
BLACK HILLS CORPORATION
Accumulated Depreciation and Depletion of Property, Plant, and Equipment
Year ended December 31, 1991
<CAPTION>
Additions
Balance at Charged to Balance at
Beginning Costs and Retire- End of
of Year Expenses ments Year
(in thousands)
<S> <C> <C> <C> <C>
Utility property $ 91,236 $ 9,164 $1,811 $ 98,589
Other property-
Coal mining 16,046 1,572 241 17,377
Oil and gas
production 3,829 3,015 236 6,608
19,875 4,587 477 23,985
Total $111,111 $13,751 $2,288 $122,574
</TABLE>
<PAGE>
Schedule IX
BLACK HILLS CORPORATION
Short-Term Borrowings
<TABLE>
<CAPTION>
Weighted
Weighted Maximum Average Average
Average Amount Amount Interest
Interest Outstanding Outstanding Rate
Balance at Rate at During During During
Year December 31 December 31 the Year the Year the Year
(in thousands)
<S> <C> <C> <C> <C> <C>
1993 $11,700 4.5% $17,350 $11,059 5.2%
1992 $ 6,000 5.8% $12,600 $ 5,616 6.0%
1991 $ 5,100 6.7% $17,000 $ 4,552 8.3%
</TABLE>
The Company's short-term borrowings consist solely of notes payable to
banks.
See Note 4 in the consolidated financial statements for additional
discussion on notes payable to banks.
The average amount of short-term borrowings outstanding during the year
represents an average of daily balances. The weighted average interest rate
during the year was based on a weighting of interest rates associated with
these balances.
<PAGE>
Exhibit 22
BLACK HILLS CORPORATION
SUBSIDIARY OF REGISTRANT
Wyodak Resources Development Corp.,
a Delaware corporation.
SUBSIDIARIES OF WYODAK RESOURCES DEVELOPMENT CORP.
Landrica Development Company,
a South Dakota corporation.
Western Production Company,
a Wyoming corporation.
<PAGE>
APPENDIX
BLACK HILLS CORPORATION
The following items, appended hereto, are incorporated into the Form
10-K from the 1993 Annual Report to Shareholders:
PART II
Pages
Item 5 Market for Registrant's Common Equity
and Related Stockholder Matters 34
Item 6 Selected Financial Data 31
Item 7 Management's Discussion and Analysis of
Financial Condition and Results of Operation 14-20
Item 8 Financial Statements and Supplementary Data 22-31
<PAGE>
DRAFT COPY - FINANCIAL SECTION OF ANNUAL REPORT
FINANCIAL DIRECTORY
Management's Discussion and Analysis of
Financial Condition and Results of
Operations . . . . . . . . . . . . . . . .
Report of Management . . . . . . . . . . . .
Report of Independent Public Accountants . .
Consolidated Statements of Income . . . . .
Consolidated Statements of Retained
Earnings . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows. . . .
Consolidated Balance Sheets . . . . . . . .
Consolidated Statements of Capitalization .
Notes to Consolidated Financial Statements .
Financial Statistics . . . . . . . . . . . .
Electric Operation Statistics . . . . . . .
Investor Information . . . . . . . . . . . .
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Black Hills Corporation (the Company) is an energy services company
consisting of three principal businesses: electric, coal mining, and oil
and gas production. Under the assumed name of Black Hills Power and Light
Company, the Company provides electric service to customers in the states
of South Dakota, Wyoming, and Montana; Wyodak Resources Development Corp.
(WRDC) mines and sells coal via long-term contracts; and Western Production
Company (WPC) explores and produces oil and gas.
FINANCIAL CONDITION
An important analysis of the Company's financial condition is its
overall ability to generate cash to fund its operations and to pay
dividends. Of particular importance in the management of liquidity are:
funds generated by operations, changes in working capital, fixed asset
additions, and the financial flexibility to attract short and long-term
financing on competitive terms.
Net cash provided from operating and investing activities for the
years ended December 31, 1993, 1992, and 1991, was $6,496,000, $15,359,000,
and $(4,666,000), respectively.
Except for the Company's current construction of Neil Simpson Unit #2
(NSS #2), a new power plant, and acquisition of a 20% interest in the
Wyodak Plant in 1991, property additions from 1991 through 1993 were
primarily for replacement of equipment and modernization of facilities.
Cash used for property additions in 1993 totaled $39,957,000 compared to
$27,821,000 in 1992 and $25,587,000 in 1991. Major property additions in
1993 included $12,675,000 for NSS #2 (see Construction of Neil Simpson Unit
#2), $6,000,000 for distribution projects, $2,000,000 for transmission
projects, $2,000,000 for a computer conversion, $4,800,000 for a new coal
conveying system, $2,200,000 for coal mining equipment, and $6,933,000 for
oil and gas investments. Property additions in 1992 included $2,227,000
for NSS #2, $1,300,000 for the dual fuel conversion of two combustion
turbines, $6,700,000 for distribution projects, $2,600,000 for coal
haulers, $2,000,000 for an electric shovel, and $5,000,000 for oil and gas
investments. Property additions in 1991 included $1,300,000 for remodeling
the General Office, $1,500,000 for transmission lines, $2,500,000 for a
230/69 KV substation, $6,700,000 for distribution projects, $1,500,000 for
new information services technology, $1,000,000 for the purchase of surface
rights over the Fortin Draw Tract coal lease, and $6,000,000 for oil and
gas investments.
On April 8, 1991, the Company purchased a 20% interest and PacifiCorp
an 80% interest in the Wyodak Plant, a 330 MW coal-fired electric
generating station located in Campbell County, Wyoming. PacifiCorp is the
operator of the Wyodak Plant. The total acquisition cost of the Company's
20% interest was approximately $42,022,000. The Company financed its 20%
interest with the issuance of first mortgage bonds, therefore, the
acquisition is not included above in the amount of cash used for property
additions.
In 1990 the Company received a rate order from the South Dakota Public
Utilities Commission that allows the capitalization of the full cost of the
Wyodak Plant for rate making purposes in South Dakota. Electric sales to
South Dakota customers represent approximately 82% of total electric sales.
The Company and PacifiCorp had leased the Wyodak Plant since 1978
under a leveraged lease agreement. The capital asset and associated debt
were previously amortized over the original term of the lease. The net
effect of terminating the lease and purchasing the Wyodak Plant was
approximately an $11,300,000 increase in debt.
The Company purchased the 20% interest in the Wyodak Plant in order to
provide its customers a reasonable cost of power from the plant after the
term of the original lease. The purchase of the Wyodak Plant also gives
the Company more control over the use of common facilities in the operation
of any new plants which may be constructed at the site.
Other financial requirements during the period included dividends of
$17,720,000, $16,977,000, and $16,045,000 and retirement of long-term debt
totaling $4,166,000, $3,725,000, and $1,921,000 for the years 1993, 1992,
and 1991, respectively.
Capital requirements for projected construction, capital improvements,
and oil and gas production are estimated to be as follows:
<TABLE>
<CAPTION>
1994 1995 1996
(in thousands)
<S> <C> <C> <C>
NSS #2 $65,113 $45,035 $ -
Other electric 14,470 9,793 18,605
Coal mining 2,129 853 2,042
Oil and gas
production 5,000 6,000 6,000
$86,712 $61,681 $26,647
</TABLE>
Major capital expenditures forecasted for the electric operations in
the 1994-1996 time frame include approximately $110,148,000 for additional
capacity (See Construction of Neil Simpson Unit #2). The coal mining
operations forecasted expenditures include the replacement of mining
equipment. Forecasted expenditures for the oil and gas operations include
an active development and exploratory drilling program and acquisition of
existing producing properties.
<PAGE>
Long-term debt and sinking fund requirements are as follows:
<TABLE>
<CAPTION>
1994 1995 1996
(in thousands)
<S> <C> <C> <C>
Electric $2,028 $2,136 $2,255
Coal mining 1,514 8 -
$3,542 $2,144 $2,255
</TABLE>
Under its mining permit, WRDC is required to reclaim all land where it
has mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual
basis, much of the reclamation occurs over an extended period after the
area is mined. Approximately $650,000 is charged to operations as
reclamation expense annually. As of December 31, 1993, accrued reclamation
costs were $7,290,000.
The Company's capitalization for the three years ended December 31 was
as follows:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Long-term debt 34% 37% 40%
Common equity 66 63 60
100% 100% 100%
</TABLE>
The Company sold 525,000 shares of Common Stock, $1 par value, at a
price of $25-3/8 per share in 1993 through a public stock offering.
Proceeds from the sale were used to finance NSS #2. Net proceeds from the
sale were approximately $12,700,000.
During 1993 the Company also revised its Dividend Reinvestment and
Stock Purchase Plan, under which shareholders may purchase additional
shares of Common Stock through dividend reinvestment or optional cash
payments at 100% of the recent average market price. The Company has the
option of issuing new shares or purchasing the shares on the open market.
Proceeds from the sale of new shares will be used to finance capital
expenditures.
The Company issued $12,300,000 Pollution Control Revenue Refunding
Bonds in 1992 to redeem $12,300,000 Pollution Control and Industrial
Revenue Bonds which were collateralized as first mortgage bonds. The
refunding bonds have no sinking fund requirements and are longer term than
the redeemed bonds maturing in 2010, thereby preserving the lower tax
exempt interest rate for a longer period of time. The redeemed bonds had
sinking fund provisions which were to begin in 1993 and would have retired
the principal in approximately equal amounts until their final due date in
2007. The refunding bonds are not secured under the Company's Indenture of
Mortgage, therefore this refunding transaction increased the Company's
ability to issue first mortgage bonds.
During 1992, the Company also entered into a refunding agreement to
refund the existing August 1, 1984, $12,200,000, 10.5% Pollution Control
Revenue Bonds in July 1994 with 7.5% Pollution Control Revenue Bonds. The
refunding agreement obligates the Company to call and satisfy in full the
existing bonds as of August 1, 1994, including a redemption premium of
2% or $240,000 on the existing bonds. Because of the forward nature of
this transaction it will not be reflected in the Company's financial
statements until 1994.
During 1991, the Company issued $48,806,000 of first mortgage bonds.
The bonds were issued in two series, $35,000,000 at 9.35% due 2021 and
$13,806,000 at 9.00% due 2003. The funds were primarily used for the
purchase of the Company's 20% interest in the Wyodak Plant.
At December 31, 1993, the Company had $40,000,000 of unsecured short-
term lines of credit which provides for interim borrowings and the
opportunity for timing of permanent financing, with borrowings outstanding
of $11,700,000. Average borrowings during 1993, 1992, and 1991 were
$11,059,000, $5,616,000, and $4,552,000, respectively. The average interest
rate on these borrowings was 5.2%, 6.0%, and 8.3% in 1993, 1992, and 1991,
respectively. The Company anticipates that the average borrowings in 1994
and 1995 will increase significantly directly related to the financing of
the construction of NSS #2. There are no compensating balance requirements
associated with these lines of credit. The Company pays a 0.125% facility
fee on $10,000,000 of the existing lines.
Credit ratings for the Company's First Mortgage Bonds remained at an
A1 level at Moody's Investors Service, Inc., a 5 (High Single A) at Duff &
Phelps, Inc., and at an A+ level with a negative outlook at Standard &
Poor's Corporation in 1993. These ratings reflect the opinion of the
respective agencies as to the credit quality of the Company's bonds.
Standard & Poor's stated that the negative outlook was issued reflecting a
burdensome future construction program which will pressure financials and
will require supportive rate treatment to maintain current credit
worthiness.
In the past the Company has depended upon internally generated funds,
issuance of short and long-term debt, and sales of preferred and common
stock to finance its activities. Additional long-term financing will be
necessary in the 1994-1995 time period to finance NSS #2 (See Construction
of Neil Simpson Unit #2).
CONSTRUCTION OF NEIL SIMPSON UNIT #2
Construction of NSS #2, an 80 MW coal fired generating plant located
adjacent to WRDC's coal mine, commenced in August 1993. The plant
construction is scheduled to be completed by the end of 1995. Purchased
power will be utilized by the Company in the interim to meet load growth
not satisfied by existing resources. The construction costs of the plant
are estimated at $124,889,000 which will increase net utility plant by
approximately 58%. As of December 31, 1993, the Company has incurred
approximately $15,000,000 of costs related to the plant. NSS #2 will be
air cooled, and will meet all Clean Air Act requirements. NSS #2 will be
fueled by coal from WRDC's mine and will increase the amount of tons sold
annually by approximately 10%. The coal pricing methodology will continue
to restrict WRDC's earnings on all coal sales to the Company to a return on
its investment base and to further reduce the price for coal to be used in
any of the Company's power plants during a period of time that under
prudent dispatch that power plant would not have been operated if it were
not for the discounted price of coal.
Additional long-term financing will be needed in the 1994-1995 time
period to finance NSS #2. The Company estimates that approximately
$87,000,000 of debt and $4,000,000 of additional equity will need to be
issued. The Company plans to raise the additional equity through the
Company's Employee Stock Purchase Plan and Dividend Reinvestment Plan.
These additional financings are expected to increase the debt component of
the Company's capital structure from 34% at December 31, 1993 to
approximately 45% to 48% by 1996.
The Company has guaranteed to the South Dakota Public Utilities
Commission (SDPUC) and the Wyoming Public Service Commission that the
Company will never include in rate base for the determination of electric
rates those costs of NSS #2 which exceed $124,889,000 including allowance
for funds used during construction. Due to the guarantee, the Company
would likely be forced to write off against earnings any construction costs
of NSS #2 in excess of the guaranteed costs except to the extent that those
costs could be recovered through performance guarantees and damage
provisions in the contracts with the vendors and contractors. The Company
estimates that over 85% of the completion costs of the project has been
contracted. The $124,889,000 estimated cost of the plant currently
includes a $4,800,000 unallocated contingency.
During 1993, the Company withdrew its application to the SDPUC for a
rate stability plan that had requested rate increases to be phased in
during construction of NSS #2. The Company reassessed the probable rate
impact of NSS #2 and determined that a phased-in plan would not be
necessary. The Company estimates that due to lower capital costs, coal
cost concessions, and cost containment, an overall rate increase of
approximately 10% in 1996, along with adjustments during construction as a
result of the purchased power and automatic fuel adjustment tariff, should
be sufficient to incorporate NSS #2 into the Company's electrical rates.
ROSEBUD QUALIFYING FACILITY CHALLENGE DISMISSED
In May 1993, the SDPUC issued an order denying a request by Rosebud
Enterprises, Inc. (Rosebud) that the SDPUC determine the Company's resource
needs, the avoided costs of the needed resource, and to force the Company
to purchase power from Rosebud. Rosebud had proposed to sell the Company
power generated from a waste fuel facility that would be qualified under
the Public Utility Regulatory Policies Act. The SDPUC further denied
Rosebud's request to issue an order finding that the Company may be
imprudent to proceed with construction of NSS #2. The SDPUC did find that
the Company had in good faith planned and permitted NSS #2 in order to
fulfill the Company's duty to serve its customers. The SDPUC's bench
ruling stated that in order to be able to defer or cancel the construction
of new generation, a utility must obtain a sufficient commitment from a
qualifying facility ahead of the lead time for the construction of its own
new capacity. By its late qualifying facility proposal to the Company and
its failure to move its project forward, Rosebud had not enabled the
Company to avoid NSS #2. The SDPUC further ruled that the risk of building
NSS #2 was on the Company, and the Commission would not rule on the
prudency and need for the plant until the Company applied for a rate
increase that included NSS #2 in rate base.
<PAGE>
RESULTS OF OPERATIONS:
CONSOLIDATED RESULTS
Consolidated net income for 1993 was $22,946,000 compared to
$23,638,000 in 1992 and $22,681,000 in 1991 or $1.66, $1.73, and $1.66 per
average common share, respectively. This equates to a 13.7% return on
year-end common equity in 1993, 15.8% in 1992, and 16.0% in 1991. The
Company recognized a non-recurring $940,000 after-tax non-cash gain in 1992
related to the PacifiCorp Settlement (see PacifiCorp Settlement) which was
equivalent to $0.07 per share. Without this gain, earnings per share would
have been flat for the three year period with 1% more average common shares
outstanding in 1993.
Consolidated revenue and income provided by the three businesses as a
percentage of the total were as follows:
<TABLE>
<CAPTION>
Revenue
1993 1992 1991
<S> <C> <C> <C>
Electric 71% 72% 73%
Coal mining 21 21 20
Oil and gas
production 8 7 7
100% 100% 100%
Net Income
Electric 49% 47% 54%
Coal mining 46 49 42
Oil and gas
production 5 4 4
100% 100% 100%
</TABLE>
Dividends paid on Common Stock totaled $1.28 per share in 1993. This
reflected increases approved by the Board of Directors from $1.24 per share
in 1992 and $1.17 per share in 1991. Dividends have increased at a 5.5%
average annual compound growth rate over the last three years. All
dividends were paid out of current earnings.
In January 1994 the Board of Directors increased the quarterly
dividend 3.1% to 33 cents per share. If this dividend is maintained during
1994, the increase is equivalent to an annual increase of 4 cents per
share. In January 1992 the Board of Directors declared a three-for-two
common stock split in the form of a 50% stock dividend, payable March 2,
1992. All per share information included herein gives retroactive effect
for the stock split for all periods presented.
WYODAK PLANT MAINTENANCE SCHEDULE
The Wyodak Plant was out of operation for six weeks in 1991 for
scheduled maintenance and is scheduled for maintenance again in the spring
of 1994. Fiscal 1992 and 1993 represent whole years of operations from the
Wyodak Plant.
When the Wyodak Plant is out of service, replacement power is provided
from purchased power and increased generation from the Company's other
generating plants. Additional purchased power costs are recovered by the
utility through the fuel adjustment clauses. The loss of coal sales to the
Wyodak Plant is partially mitigated through greater coal sales to the
Company's other generating plants and reduced operating costs.
PACIFICORP SETTLEMENT
In 1987 WRDC and the Company entered into settlement agreements with
PacifiCorp canceling PacifiCorp's obligation to purchase coal commencing in
1990 for a second plant scheduled to be constructed adjacent to the Wyodak
Plant but which had been canceled, and settling a dispute over the quantity
of coal PacifiCorp was required to purchase to operate the Wyodak Plant.
This settlement resulted in an increase in the Company's net income in
1993, 1992, and 1991 of approximately $1,500,000, $2,800,000, and
$2,600,000 or $0.11, $0.20, and $0.19 per share of common stock,
respectively. The 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 requires PacifiCorp to pay up to $15,000,000, such
amount to be adjusted for inflation and deflation, for the cost of new coal
handling facilities. Construction of the coal handling facilities occurred
in 1992 and 1993. As a result of a definitive agreement entered into with
PacifiCorp in 1992 regarding the construction of these facilities, the
Company recognized a 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.
<PAGE>
<TABLE>
<CAPTION>
Electric Operations
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Revenue $98,155 $97,448 $98,158
Operating expenses 74,173 74,056 73,522
Operating income $23,982 $23,392 $24,636
Net income $11,171 $11,041 $12,156
</TABLE>
Electric revenue increased 0.7% in 1993 compared to a 0.7% decrease in
1992 and a 6.4% increase in 1991. Firm kilowatthour sales increased 3.5%
in 1993 compared to a 0.5% increase in 1992 and a 3.6% increase in 1991 and
have averaged an annual 2.5% growth rate over the last three years.
Homestake Mining Company, the Company's largest customer, reduced its
energy usage by 22,000 megawatt hours in 1993 by concentrating on more
efficient production areas in a depressed gold market. Sales growth in
1992 was reduced by mild weather conditions.
The revenue increase in 1993 from additional electric sales was offset
by a decrease in the fuel and purchased power adjustment passed on to
electric customers. The decrease in purchased power was due to a
$2,000,000 refund received from PacifiCorp on the 40-year power purchase
agreement.
Revenue decreased in 1992 due to a decrease in the fuel and purchased
power adjustment passed on to electric customers. This decrease was a
result of a $600,000 increase in the refund accrued for the limitation on
the return allowed on WRDC coal sales to the Company's power plants and a
$600,000 decrease in fuel and purchased power expense. Purchased power
decreased in 1992 compared to 1991 due to a full year of operations at the
Wyodak Plant.
In South Dakota the Company may not include in rates any cost of coal
which allows WRDC to earn a return on equity on sales of coal to the
Company's utility operations in excess of a percentage equal to the rate on
long-term "A" rated utility bonds plus 400 basis points (4%). The
investment base on which the return is calculated includes all of WRDC's
investment base except for investments in subsidiary companies and other
non-mining interests. The maximum return on equity to be applied in 1994
for the 1993 adjustment will be approximately 11.6%. The returns applied in
1992 and 1991 were 12.7% and 13.4%, respectively. The Company has recorded
an accrual for the 1994 refund for sales in 1993 of approximately
$1,060,000. The 1993 and 1992 refunds were approximately $1,538,000 and
$940,000, respectively. Tons of WRDC's coal sold to Black Hills represent
approximately 35% of its total coal sales. The refund increased in 1994
and 1993 compared to 1992 primarily due to the decrease in long-term "A"
rated utility bond interest rates. The decrease in the allowed return in
1993 was offset by an increase in WRDC's investment base primarily due to
its investment in an electric shovel and new coal conveying facilities.
Revenue per kilowatt sold was 6.0 cents in 1993 down from 6.2 cents in
1992 and 6.1 cents in 1991. The number of customers in the service area
increased to 53,330 in 1993 from 52,535 in 1992 and 51,775 in 1991.
Operating expenses were relatively flat in 1993 compared to 1992 as a
result of the $2,000,000 purchased power refund. Operating expenses
increased 0.7% in 1992, and decreased slightly in 1991. The decrease in
1991 reflects the effect of buying out the Wyodak Plant Lease and a
decrease in administrative and general expenses and property taxes. The
Wyodak Plant Lease payment was recorded as an operating expense in the
past. Since the purchase of the Plant in April 1991, the cost of ownership
is now reflected in depreciation and interest expense.
The Company went through a corporate reorganization during the first
quarter of 1991 resulting in a $600,000 reduction in administrative and
general expenses. Eleven existing positions and several vacant positions
were eliminated.
During 1991 the South Dakota Department of Revenue instituted the unit
valuation method in determining property values for those entities whose
property is centrally assessed for tax purposes resulting in a decrease in
property taxes of approximately $1,050,000 from 1990 levels. Property
taxes increased $540,000 in 1993 and $600,000 in 1992 as a result of
increased valuations.
<PAGE>
<TABLE>
<CAPTION>
COAL MINING OPERATIONS
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Revenue $29,822 $28,296 $26,138
Operating expenses 17,462 16,724 16,667
Operating income $12,360 $11,572 $ 9,471
Net income $10,648 $11,695 $ 9,623
</TABLE>
Revenue increased 5.4% in 1993 and 8.3% in 1992 due to a 2.3% and 7.9%
increase, respectively in tons of coal sold. The increase in tons of coal
sold reflects two whole years of operations at the Wyodak Plant. Operating
expense increased 4.4% in 1993 reflecting an increase in depreciation
expense as a result of an increase in capital investments and higher taxes
associated with increased revenues. Operating expenses remained relatively
flat in 1992 caused by a decrease in administrative and general expenses
offset by an increase in coal production. Operating income increased 6.8%
in 1993 and 22.2% in 1992 reflecting the increase in coal revenue.
Revenue decreased 1.5% in 1991 due to a 5.7% decrease in tons of coal
sold offset by a 4.5% increase in the average price per ton sold. The
decrease in tons of coal sold was primarily due to the Wyodak Plant's
scheduled six week maintenance period during the year. The increase in the
average price was due to increases in the government indices used in the
coal contract price calculations and 1990 coal audit adjustments.
Operating expenses decreased 4.1% in 1991 due to the decrease in coal
production and a decrease in ad valorem taxes and administrative expenses.
Administrative expenses decreased due to the corporate reorganization that
occurred during the year. Operating income increased 3.4% primarily due to
the decrease in administrative expenses.
Non-operating income was $2,226,000 in 1993 compared to $3,894,000 in
1992 and $3,677,000 in 1991. Non-operating income includes the PacifiCorp
Settlement, a coal contract settlement from Grand Island, Nebraska, and
interest income from investments. Non-operating income decreased in 1993
due to a decrease in interest income attributable to lower interest rates
and a non-recurring $940,000 after-tax non-cash gain recognized in 1992
related to the PacifiCorp Settlement.
In late 1987 WRDC agreed to the termination of a long-term coal supply
agreement with the City of Grand Island, Nebraska. Grand Island was
granted a 14 year option to purchase coal and in return WRDC receives
payments of approximately $155,000 each year. WRDC has reserved sufficient
coal in the eventuality the City of Grand Island exercises its option.
<PAGE>
<TABLE>
<CAPTION>
Oil and Gas Production
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Revenue $11,396 $9,599 $9,077
Operating expenses 9,952 8,214 7,717
Operating income $ 1,444 $1,385 $1,360
Net income $ 1,127 $ 902 $ 902
</TABLE>
The oil and gas operations have not been a significant percent of the
Company's total operations. Net income and assets related to oil and gas
operations have been 7% or less of the Company's consolidated amounts over
the last three years.
Revenue, primarily comprised of oil and gas sales, is supplemented by
field services in the Finn-Shurley oil field in eastern Wyoming.
Equivalent barrels of oil sold increased approximately 48% to 465,000
barrels in 1993 from 315,000 barrels in 1992 and 262,000 barrels in 1991.
The average sales price of oil per barrel was $16.69 in 1993 compared to
$19.10 in 1992 and $20.03 in 1991. WPC's operating expenses increased 21%
in 1993 compared to 6.4% in 1992 and 9.6% in 1991. Operating expenses
increased primarily due to increased depletion expense as a result of
increased oil and gas production and lower oil prices. WPC recognized
$3,725,000, $2,291,000, and $1,350,000 of depletion expense in 1993, 1992,
and 1991, respectively.
Low commodity prices reduce the value of the Company's oil and gas
assets and will cause the Company to increase its depletion expense.
Management estimates that oil prices must average $14 to $15 per barrel for
its oil and gas operations to remain profitable.
WPC's proved reserves, and the revenues generated from production,
will decline as production occurs, except to the extent WPC conducts
successful exploration and development activities or acquires additional
proved reserves. WPC has been in an active exploration and development
drilling program during 1991, 1992, and 1993. Much of WPC's production
growth in 1993 was the result of its horizontal drilling program in the
Austin Chalk formation in Texas. WPC intends to increase its net proved
reserves by selectively increasing its oil and gas exploration and
development activities and by acquiring additional interests in the Finn-
Shurley oil field and Rocky Mountain region primarily with the use of
internally generated funds.
WPC's reserves are based on reports prepared by Ralph E. Davis
Associates, Inc. in 1993 and 1992 and Huddleston & Co., Inc. in 1991,
independent engineering companies, selected by the Company. Reserves were
determined using constant product prices at the end of the respective
years. Estimates of economically recoverable reserves and future net
revenues are based on a number of variables which may differ from actual
results. WPC's unaudited reserves, principally proved developed and
undeveloped properties, were estimated to be 1.1, 2.2, and 2.5 million
barrels of oil and 2.8, 3.2, and 4.8 billion cubic feet of natural gas as
of December 31, 1993, 1992, and 1991, respectively. The decrease in the
reserves was caused by price decreases, production increases, and
engineering revisions. WPC has interests in 386 oil and gas properties in
seven states. WPC operates a total of 347 wells in Wyoming, Colorado, and
South Dakota. WPC's non-operated properties are located in Wyoming,
Colorado, North Dakota, Montana, Kansas, and Texas.
EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
On January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions. This new standard requires that the expected
cost of these benefits must be accrued for during the years employees
render service. The Company prospectively adopted the new standard
effective January 1, 1993, and is amortizing the discounted present value
of the accumulated postretirement benefit obligation of $2,996,000 to
expense over a 20 year period. The net periodic postretirement cost
charged to expense in 1993 was $527,000 (pre-tax). For measurement
purposes, an 11.5% annual rate of increase in healthcare benefits was
assumed for 1994; the rate was assumed to decrease gradually to 6% in 2005
and remain at that level thereafter. The healthcare cost trend rate
assumption has a significant effect on the amount reported. A 1% increase
in the health care cost trend assumption would increase the net periodic
postretirement benefit cost by approximately $140,000 annually or 20.8%.
ACCOUNTING FOR INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, which requires
the use of the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently
enacted income tax rates, to reflect the tax effect of temporary
differences between the financial reporting and tax basis of assets and
liabilities. Such temporary differences are the result of provisions in
the income tax law that either require or permit certain items to be
reported on the income tax return in a different period than they are
reported in the financial statements. The new standard required
adjustments to existing balances of accumulated deferred income taxes to
reflect changes in income tax rates. To the extent such income taxes are
recoverable or payable through future rates, a $6,912,000 net regulatory
liability has been recorded in the accompanying consolidated balance
sheets. Initial application of the statement had no material impact on the
Company's results of operations.
INFLATION
Inflation may have a significant impact on replacement of property and
capital improvements in the future due to the capital intensive nature of
the utility business. The rate making process gives no recognition to the
fair value of existing plant; however, in the past, the Company has been
allowed to recover and earn on the increased cost of its net investment
when the addition to or replacement of facilities occurred. The majority
of the mining operations' coal contracts provide for the adjustment over
time of components of the sales price through indexes, formulas, or direct
pass-through of costs.
<PAGE>
REPORT OF MANAGEMENT
Management of Black Hills Corporation is responsible for the
preparation, integrity, and objectivity of the consolidated financial
statements of the Company and its subsidiaries. The consolidated financial
statements are prepared in conformity with generally accepted accounting
principles and reflect management's informed judgments and best estimates
with due consideration given to materiality. Information contained
elsewhere in the Annual Report is consistent with the consolidated
financial statements.
The Company's system of internal controls is designed to provide
reasonable assurance that assets are safeguarded, transactions are executed
in accordance with management's authorization, and the consolidated
financial statements are prepared in accordance with generally accepted
accounting principles. The internal controls are continually reviewed and
evaluated for effectiveness. No internal control system can prevent the
occurrence of errors and irregularities with absolute assurance due to the
inherent limitations of any system. Management's objective is to maintain
a system that meets its goals in a cost effective manner.
The Audit Committee, composed exclusively of outside directors, is
responsible for overseeing the Company's financial reporting process and
reporting the results of its activities to the Board of Directors. This
committee, management, and the internal auditor periodically review matters
associated with financial reporting, audit activities, and internal
controls. As part of their audit of the Company's 1993 consolidated
financial statements, the Company's independent auditors, Arthur Andersen &
Co., considered the Company's system of internal controls to the extent
they deemed necessary to determine the nature, timing, and extent of their
audit tests. The independent and internal auditors have free access to the
Audit Committee to discuss the results of their audits without the presence
of management.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Black Hills Corporation:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of BLACK HILLS CORPORATION AND SUBSIDIARIES as
of December 31, 1993 and 1992, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1993. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Black Hills
Corporation and Subsidiaries as of December 31, 1993 and 1992, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 1993, in conformity with generally
accepted accounting principles.
As discussed in Notes 8 and 9 to the consolidated financial
statements, effective January 1, 1993, the Company changed its method of
accounting for post retirement benefits other than pensions and its method
of accounting for income taxes.
ARTHUR ANDERSEN & CO.
Minneapolis, Minnesota,
January 28, 1994
<PAGE>
<TABLE>
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
Years ended December 31 1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Operating revenues:
Electric . . . . . . . . . . .$ 98,155 $ 97,448 $ 98,158
Coal mining. . . . . . . . . . 29,822 28,296 26,138
Oil and gas production . . . . 11,396 9,599 9,077
139,373 135,343 133,373
Operating expenses:
Fuel and purchased power . . . 36,946 38,209 38,851
Operations . . . . . . . . . . 23,368 23,337 23,825
Maintenance . . . . . . . . . 6,869 6,513 6,729
Administrative and general . . 8,144 7,811 7,910
Depreciation, depletion, and
amortization . . . . . . . . 16,051 13,860 12,012
Taxes, other than income
taxes (Note 12) . . . . . . . 10,209 9,264 8,579
101,587 98,994 97,906
Operating income:
Electric . . . . . . . . . . . 23,982 23,392 24,636
Coal mining . . . . . . . . . 12,360 11,572 9,471
Oil and gas production . . . . 1,444 1,385 1,360
37,786 36,349 35,467
Other income (expense):
Interest expense . . . . . . . (8,817) (8,965) (8,001)
Investment income . . . . . . 1,739 3,149 2,956
Allowance for funds used
during construction . . . . 729 378 177
Other, net (Note 12) . . . . . 474 1,233 631
(5,875) (4,205) (4,237)
Income before income taxes . . . 31,911 32,144 31,230
Income taxes (Note 9). . . . . . (8,965) (8,506) (8,549)
Net income . . . . . . . .$ 22,946 $ 23,638 $ 22,681
Weighted average common shares
outstanding (Note 2) . . . . . 13,811 13,689 13,675
Earnings per share of common
stock (Note 2) . . . . . . . .$ 1.66 $ 1.73 $ 1.66
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
Years ended December 31 1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Balance, beginning of year . . . . . . $105,173 $ 98,512 $91,876
Net income . . . . . . . . . . . . . . 22,946 23,638 22,681
Cash dividends on common stock
($1.28, $1.24, and $1.17 per
share, respectively) . . . . . . . . (17,720) (16,977) (16,045)
Balance, end of year . . . . . . . . . $110,399 $105,173 $98,512
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
Years ended December 31 1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Cash flows provided from
(used for) operating activities:
Net income . . . . . . . . . . . . . $ 22,946 $23,638 $22,681
Principal non-cash items-
Depreciation, depletion, and
amortization . . . . . . . . . . 16,051 13,860 12,012
Deferred income taxes and
investment tax credits. . . . . . 1,042 761 (801)
Gain on coal settlement . . . . . . - (940) -
Allowance for other funds used during
construction . . . . . . . . . . (333) (94) (65)
(Increase) decrease in receivables,
inventories, and other current assets (1,556) 1,378 488
Increase (decrease) in current
liabilities . . . . . . . . . . . . (2,562) 4,814 1,847
Other, net . . . . . . . . . . . . . . 4,259 1,091 (470)
39,847 44,508 35,692
Cash flows provided from (used for)
investing activities:
Neil Simpson Unit #2 construction
costs, excluding allowance for
other funds used during construction
(Note 7) . . (12,675) (2,227) -
Other property additions, excluding
allowance for other funds used
during construction . . . . . . . . . (27,282) (25,594) (25,587)
Short-term investments purchased . . . (33,622) (33,938) (14,771)
Short-term investments sold . . . . . . .25,504 32,610 -
Proceeds from sale of long-term
investments . . . . . . . . . . . . . 14,724 - -
(33,351) (29,149) (40,358)
Cash flows provided from (used for)
financing activities:
Dividends paid . . . . . . . . . . . . (17,720) (16,977) (16,045)
Common stock issued . . . . . . . . . . 13,705 534 -
Net short-term borrowings . . . . . . . 3,784 900 (500)
Long-term debt issued . . . . . . . . . - - 8,768
Long-term debt retired . . . . . . . . (4,166) (3,725) (1,921)
(4,397) (19,268) (9,698)
Increase (decrease) in cash and
cash equivalents. . . . . . . . . . 2,099 (3,909) (14,364)
Cash and cash equivalents:
Beginning of year . . . . . . . . . . . 5,767 9,676 24,040
End of year . . . . . . . . . . . . . .$ 7,866 $ 5,767 $ 9,676
Supplemental disclosure of cash flow
information:
Cash paid during the period for -
Interest . . . . . . . . . . . . . .$ 9,283 $ 9,296 $ 6,837
Income taxes. . . . . . . . . . . . .$ 8,000 $ 7,440 $ 8,700
Non-cash investing and financing
activities (Notes 3 and 6)
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31 1993 1992
(in thousands)
ASSETS
<S> <C> <C>
Current assets:
Cash and cash equivalents . . . . .$ 7,866 $ 5,767
Short-term investments . . . . . . . 24,217 16,099
Receivables, net
Customers . . . . . . . . . . . . 12,415 10,246
Other . . . . . . . . . . . . . . 901 1,807
Materials, supplies, and fuel. . . . 6,765 6,448
Prepaid expenses . . . . . . . . . . 1,638 1,662
Total current assets . . . . . 53,802 42,029
Property and investments:
Electric . . . . . . . . . . . . . . 341,852 318,270
Coal mining. . . . . . . . . . . . . 51,670 44,483
Oil and gas production . . . . . . . 32,371 28,465
Investments . . . . . . . . . . . . 7,250 21,974
433,143 413,192
Less accumulated depreciation
and depletion. . . . . . . . . . .(144,492) (132,890)
Net property and investments. . 288,651 280,302
Deferred charges:
Federal income taxes . . . . . . . . 7,271 2,153
Other . . . . . . . . . . . . . . . 3,129 5,718
10,400 7,871
$352,853 $330,202
LIABILITIES AND CAPITALIZATION
Current liabilities:
Current maturities of
long-term debt. . . . . . . . . . .$ 3,542 $ 4,166
Notes payable (Note 4) . . . . . . . 11,768 7,984
Accounts payable . . . . . . . . . . 9,535 8,939
Accrued liabilities-
Taxes. . . . . . . . . . . . . . . 5,583 5,544
Fuel and purchased power refunds 1,375 4,120
Interest . . . . . . . . . . . . . 1,700 2,167
Other. . . . . . . . . . . . . . . 6,023 6,008
Total current liabilities . . . 39,526 38,928
Deferred credits:
Federal income taxes . . . . . . . . 36,705 37,687
Investment tax credits . . . . . . . 6,027 6,532
Reclamation costs. . . . . . . . . . 7,290 6,651
Regulatory liability . . . . . . . . 6,912 -
Other. . . . . . . . . . . . . . . . 3,030 2,430
Total deferred credits. . . . . 59,964 53,300
Commitments and contingent liabilities
(Notes 7 and 8). . . . . . . . . . .
Capitalization, per accompanying
statements:
Common stock equity. . . . . . . . . 168,089 149,158
Long-term debt . . . . . . . . . . . 85,274 88,816
Total capitalization. . . . . . 253,363 237,974
$352,853 $330,202
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated balance sheets.
</TABLE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
December 31 1993 1992
(in thousands)
<S> <C> <C>
Common stock equity (Note 2):
Common stock, $1 par value; 50,000,000
shares authorized; 14,269,580 and
13,701,287 shares outstanding,
respectively . . . . . . . . . . . . . .$ 14,270 $ 13,701
Additional paid-in capital . . . . . . . . 43,420 30,284
Retained earnings . . . . . . . . . . . . . 110,399 105,173
Total common stock equity . . . . . . 168,089 149,158
Cumulative preferred stock:
No par value; 400,000 shares authorized;
no shares outstanding . . . . . . . . . . - -
$100 par value; 270,000 shares
authorized; no shares outstanding . . . . - -
Long-term debt (Note 3):
First mortgage bonds-
4.75% due 1993. . . . . . . . . . . . . . - 854
8.375% due 1998 . . . . . . . . . . . . . 3,340 4,005
8.05% due 1999. . . . . . . . . . . . . . 4,875 4,900
6.625% and 6.85% pollution control
and industrial development revenue
bonds, collateralized with first
mortgage bonds, due 2007 . . . . . . . 1,840 2,000
9.00% due 2003. . . . . . . . . . . . . . 11,739 12,818
9.49% due 2018. . . . . . . . . . . . . . 6,000 6,000
9.35% due 2021 . . . . . . . . . . . . . 35,000 35,000
62,794 65,577
Other-
6.7% pollution control revenue bonds,
due 2010. . . . . . . . . . . . . . . . 12,300 12,300
10.50% pollution control revenue
bonds, due 2014 . . . . . . . . . . . . 12,200 12,200
Other long-term obligations . . . . . . . 1,522 2,905
26,022 27,405
Total long-term debt 88,816 92,982
Current maturities . . . . . . . . . . . . (3,542) (4,166)
Net long-term debt . . . . . . . . . . 85,274 88,816
Total capitalization . . . . . . . . .$253,363 $237,974
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated financial statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1993, 1992, AND 1991
(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BUSINESS DESCRIPTION
Black Hills Corporation and its Subsidiaries (the Company) operate in three
primary business segments: electric, coal mining, and oil and gas
production. The Company's electric utility operation is engaged in the
generation, purchase, transmission, distribution, and sale of electric
power and energy in western South Dakota, northeastern Wyoming, and
southeastern Montana. Sales of electric power to the three largest
electric customers represented 20% of the Company's electric revenue in
1993, 22% in 1992, and 21% in 1991.
The coal mining operation of the Company, located in northeastern Wyoming,
mines and sells sub-bituminous coal primarily under long-term coal supply
agreements. As described in Note 6, a substantial portion of the coal
mining operation's sales are to the Wyodak Plant. Sales of coal to the
Company and to PacifiCorp represent 89% of total coal sales.
The Company's oil and gas exploration and production business operates and
has working interests in oil wells principally located in the Rocky
Mountain region and Texas.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Black Hills
Corporation and its wholly owned subsidiaries. All significant inter-
company balances and transactions have been eliminated in consolidation
except for revenues and expenses associated with intercompany coal sales in
accordance with the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation." Total intercompany coal sales not eliminated were
$10,047,000, $9,811,000, and $9,220,000 in 1993, 1992, and 1991,
respectively.
PROPERTY AND INVESTMENTS
Property is recorded at cost which includes an allowance for funds used
during construction where applicable. The cost of electric property
retired, together with removal cost less salvage, is charged to accumulated
depreciation. Repairs and maintenance of property are charged to
operations as incurred.
Investments, consisting principally of tax exempt municipal bonds held for
corporate development purposes, are carried at cost which approximates
market.
DEPRECIATION AND DEPLETION
Depreciation is computed using the straight-line method over the estimated
useful lives of the related assets. Depreciation provisions for the
electric property were equivalent to annual composite rates of 3.2% in 1993
and 1992, and 3.3% in 1991. Composite depreciation rates for other
property were 9.6%, 7.5%, and 8.2% in 1993, 1992, and 1991, respectively.
Depletion of coal and oil and gas properties is computed using the cost
method for financial reporting and the gross income method or cost method,
whichever is applicable, for federal income tax reporting.
CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
Cash of the Company is invested in money market investments such as
municipal put bonds, money market preferreds, commercial paper,
Euro-dollars, and certificates of deposit. The Company considers all
highly liquid investments with an original maturity of three months or less
to be cash equivalents. Cash equivalents and short-term investments are
stated at cost which approximates market.
REVENUE RECOGNITION
Revenue from sales of electric energy is based on rates filed with
applicable regulatory authorities. Electric revenue includes an accrual
for estimated unbilled revenue for services provided through year-end.
Revenue from other business segments is recognized at the time the products
are delivered or the services are rendered.
OIL AND GAS EXPLORATION
The Company accounts for its oil and gas exploration activities under the
full cost method. Capitalized costs associated with unsuccessful wells are
amortized over future periods as the reserves from successful wells are
produced.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction (AFDC) represents the
approximate composite cost of borrowed funds and a return on capital used
to finance construction expenditures and is capitalized as a component of
the electric property. The AFDC was computed at an annual composite rate
of 7.7% in 1993, 10.5% in 1992, and 12% in 1991.
INCOME TAXES
Deferred taxes are provided on all significant temporary differences,
principally depreciation. Investment tax credits have been deferred in the
electric operation and the accumulated balance is amortized as a reduction
of income tax expense over the useful lives of the related electric
property which gave rise to the credits.
(2) CAPITAL STOCK
Common Stock
Common shares issued at $1.00 par value during the years indicated were:
<TABLE>
<CAPTION>
1993 1992
<S> <C> <C>
Public offering 525,000 -
Employee Stock
Purchase Plan 16,402 24,332
Dividend Reinvestment
and Stock Purchase Plan 26,891 -
568,293 24,332
</TABLE>
There were no shares issued in 1991.
At December 31, 1993, 74,209 shares of unissued common stock were available
for future offerings under the Employee Stock Purchase Plan.
During 1993, the Board of Directors adopted a new Dividend Reinvestment and
Stock Purchase Plan, under which shareholders may purchase additional
shares of common stock through dividend reinvestment and/or optional cash
payments at 100% of the recent average market price. The Company has the
option of issuing new shares or purchasing the shares on the open market.
At December 31, 1993, 973,109 shares of unissued common stock were
available for future offerings under the Plan.
On January 30, 1992, the Board of Directors declared a three-for-two common
stock split in the form of a 50% stock dividend, payable March 2, 1992, to
shareholders of record on February 10, 1992. The common stock and per
share information in the accompanying consolidated financial statements and
notes have been restated to reflect the stock distribution.
ADDITIONAL PAID-IN CAPITAL
Changes in additional paid-in capital for the years indicated were:
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Balance, beginning of year $30,284 $29,776 $34,336
Premium, net of expenses,
received from sales of
common stock 13,136 508 -
Three-for-two stock split - - (4,560)
Balance, end of year $43,420 $30,284 $29,776
</TABLE>
(3) LONG-TERM DEBT
Substantially all of the Company's utility property is subject to the lien
of the Indenture securing its first mortgage bonds. First mortgage bonds
of the Company may be issued in amounts limited by property, earnings, and
other provisions of the mortgage indentures.
In 1992 the Company issued $12,300,000, 6.7% Unsecured Pollution Control
Refunding Revenue Bonds, due 2010. The proceeds were used to redeem
$12,300,000 of 6.625% and 6.85%, Pollution Control Revenue Bonds, due 2007.
The Company entered into a refunding agreement in 1992 to refund the
existing $12,200,000, 10.5% Pollution Control Revenue Bonds in 1994 with
7.5% Pollution Control Revenue Bonds. The refunding agreement obligates
the Company to call and satisfy in full the existing bonds in 1994,
including a redemption premium of 2% or $240,000 on the existing bonds.
Because of the forward nature of this transaction, the refunding will not
be reflected in the Company's consolidated financial statements or capital
structure until 1994.
In 1991 the Company issued two series of first mortgage bonds, $35,000,000
at 9.35% due 2021 and $13,806,000 at 9.00% due 2003. The funds were
primarily used for the purchase of the Wyodak Plant as described in Note 6.
Scheduled maturities of long-term debt for the next five years are:
$3,542,000 in 1994, $2,144,000 in 1995, $2,255,000 in 1996, $2,384,000 in
1997, and $2,196,000 in 1998.
(4) NOTES PAYABLE TO BANKS
At December 31, 1993, the Company had $40,000,000 of unsecured short-term
lines of credit. Borrowings outstanding under these lines of credit were
$11,700,000 and $6,000,000 as of December 31, 1993 and 1992, respectively.
Average borrowings during 1993, 1992, and 1991 were $11,059,000,
$5,616,000, and $4,552,000, respectively. The average interest rate on
these borrowings was 5.2%, 6.0%, and 8.3% in 1993, 1992, and 1991,
respectively. The Company has no compensating balance requirements
associated with these lines of credit. The Company pays a 0.125% facility
fee on $10,000,000 of the existing lines. The lines of credit are subject
to periodic review and renewal during the year by the banks.
(5) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of the Company's financial instruments.
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of
those instruments.
Short-Term and Other Investments
The fair value of the Company's short-term and other investments equals the
quoted market price, if available. If a quoted market price is not
available, fair value is estimated using quoted market prices for similar
securities.
Long-Term Debt
The fair value of the Company's long-term debt is estimated based on quoted
market rates for utility debt instruments having similar maturities and
similar debt ratings, with an exception for debt associated with the
federal coal lease modifications. The fair value of the bonus payments for
the federal coal lease modifications equals the discounted future cash
flows using the prime rate as the discount rate. The final federal bonus
payment is due February 1, 1994.
The estimated fair values of the Company's financial instruments are as
follows:
<TABLE>
<CAPTION>
1993
(in thousands)
Carrying Fair
Amount Value
<S> <C> <C>
Cash and cash equivalents $ 7,866 $ 7,866
Short-term investments 24,217 24,217
Other investments 7,250 7,257
Long-term debt 88,816 105,639
</TABLE>
<TABLE>
<CAPTION>
1992
(in thousands)
Carrying Fair
Amount Value
<S> <C> <C>
Cash and cash equivalents $ 5,767 $ 5,767
Short-term investments 16,099 16,177
Other investments 21,974 22,023
Long-term debt 92,982 101,885
</TABLE>
The majority of the Company's outstanding bonds are currently subject to
make-whole provisions which would eliminate any economic benefits for the
Company to call and refinance the bonds.
(6) WYODAK PLANT
On April 8, 1991, the Company purchased a 20% interest and PacifiCorp an
80% interest in the Wyodak Plant (the Plant), a 330 MW coal-fired electric
generating station located in Campbell County, Wyoming. PacifiCorp is the
operator of the Plant. The total acquisition cost of the Company's 20%
interest was approximately $42,022,000. The Company financed its 20%
interest through the issuance of first mortgage bonds.
The Company and PacifiCorp had leased the Plant since 1978 under a
leveraged lease agreement. The lease was recorded by the Company as a
capital asset with corresponding debt at the present value of the lease
payments.
Non-cash investing and financing activities associated with the acquisition
were as follows:
Acquisition of interest in Wyodak Plant
through debt issuance and assumption $42,022,000
Elimination of capital lease asset and
obligation relating to the Wyodak Plant 30,694,000
The Company received a rate order from the South Dakota Public Utilities
Commission that allows the capitalization of the full cost of the Plant for
rate making purposes in South Dakota. Electric sales to South Dakota
customers represent approximately 82% of total electric sales.
The Company receives 20% of the Plant's capacity and is committed to pay
20% of its additions, replacements, and operating and maintenance expenses.
As of December 31, 1993, the Company's investment in the Plant included
$71,207,000 in electric plant and $18,844,000 in accumulated depreciation.
The Company's share of direct expenses of the Plant is included in the
corresponding categories of operating expenses in the accompanying
consolidated statements of income.
Wyodak Resources Development Corp. (WRDC) supplies coal to the Plant under
an agreement expiring in 2013 with a 10 year renewal option. This coal
supply agreement is collateralized by a mortgage on and a security interest
in some of WRDC's coal reserves. At December 31, 1993, approximately
32,250,000 tons were covered under this agreement. WRDC's sales to the
Plant were $21,438,000, $20,317,000, and $17,775,000 for the years ended
December 31, 1993, 1992, and 1991, respectively.
(7) COMMITMENTS AND CONTINGENT LIABILITIES
NEW POWER PLANT
Construction of Neil Simpson Unit #2 (NSS #2), an 80 MW coal fired
generating plant located adjacent to the Wyodak coal mine, commenced in
August 1993. The Company has committed to the South Dakota Public
Utilities Commission and the Wyoming Public Service Commission to construct
NSS #2 at a capital cost not to exceed $124,889,000 including AFDC and to
not include in rate base any capital costs in excess thereof. The
construction of the plant is scheduled to be completed by the end of 1995.
The Company has incurred approximately $15,000,000 of costs related to the
plant as of December 31, 1993.
WRDC has committed to supply all of the coal requirements for the life of
the plant. The coal pricing methodology would restrict WRDC's earnings on
all coal sales to the Company to a return on its investment base. WRDC has
committed to further reduce the price for coal to be used in any of the
Company's power plants during a period of time that under prudent dispatch
that power plant would not have been operated if it were not for the
discounted price of coal.
COAL OBLIGATIONS
In addition to the 32,250,000 tons of coal reserved under the agreement
with the Wyodak Plant, WRDC has reserved 30,000,000 tons of coal under
existing contracts and 52,000,000 tons of coal under future purchase
options. None of the purchase options are expected to be exercised because
the option price is substantially higher than the market price. An option
for 50,000,000 tons can be exercised only if WRDC has not committed the
coal reserves to other buyers prior to the exercise of the option.
POWER PURCHASE AGREEMENT
In 1983 the Company entered into a 40 year power agreement with PacifiCorp
providing for the purchase of 75 megawatts of electric capacity and energy.
Although the price paid for the capacity and energy is based on the
operating costs of one of PacifiCorp's coal-fired electric generating
plants, the power can come from anywhere in PacifiCorp's system. Costs
incurred under this agreement were $21,106,000, $21,507,000, and
$22,280,000 in 1993, 1992, and 1991, respectively.
RECLAMATION
Under its mining permit, WRDC is required to reclaim all land where it has
mined coal reserves. The cost of reclaiming the land is accrued as the
coal is mined. While the reclamation process takes place on a continual
basis, much of the reclamation occurs over an extended period after the
area is mined. Approximately $650,000 is charged to operations as
reclamation expense annually. As of December 31, 1993, accrued reclamation
costs were approximately $7,290,000.
OTHER
The Company is subject to various legal proceedings and claims which arise
in the ordinary course of operations and in the sales of formerly owned
companies. In the opinion of management, the amount of liability, if any,
with respect to these actions would not materially affect the consolidated
financial position or results of operations of the Company.
(8) EMPLOYEE BENEFIT PLANS
The Company has a defined benefit pension plan (the Plan) covering
substantially all employees. The benefits are based on years of service
and compensation levels during the highest five consecutive years of the
last ten years of service. The Company's funding policy is in accordance
with the federal government's funding requirements. The Plan's assets
consist primarily of equity and debt securities and cash equivalents.
Net pension expense (income) for the Plan was as follows:
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Service cost $ 651 $ 535 $ 499
Interest cost 1,899 1,687 1,510
Return on assets:
Actual (2,852) (2,224) (5,210)
Deferred 333 (215) 3,203
Net pension expense (income) $ 31 $ (217) $ 2
</TABLE>
Funding information for the Plan as of October 1 of each year was as
follows:
<TABLE>
<CAPTION>
1993 1992
(in thousands)
<S> <C> <C>
Fair value of plan
assets $25,186 $23,602
Projected benefit
obligation 28,367 22,969
(3,181) 633
Unrecognized:
Net loss (gain) 3,779 (13)
Prior service cost 1,105 1,204
Transition asset (631) (721)
Prepaid pension cost $ 1,072 $ 1,103
Accumulated benefit
obligation $22,464 $18,885
Vested benefit obligation $21,507 $18,123
Actuarial assumptions:
Discount rate 7.5% 8.5%
Expected long-term rate of
return on assets 11% 11%
Rate of increase in
compensation levels 5% 5%
</TABLE>
The change in the assumed discount rate from 8.5% in 1992 to 7.5% in 1993
resulted in an increase in the accumulated benefit obligation and projected
benefit obligation of $2,260,000 and $3,403,000, respectively.
The Company has various supplemental retirement plans for outside directors
and key executives of the Company. The plans are nonqualified defined
benefit plans. Costs incurred under the plans were $633,000, $735,000, and
$570,000 in 1993, 1992, and 1991, respectively.
On January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions. The new standard requires that the expected cost of these
benefits must be charged to expense during the years that the employees
render service. Prior to adopting the standard the Company expensed these
benefits as they were paid. The Company is amortizing the transition
obligation of $2,996,000 over a 20 year period.
Employees retiring from the Company on or after attaining age 55 who have
rendered at least five years of service to the Company are entitled to
postretirement healthcare benefits coverage. These benefits are subject to
premiums, deductibles, copayment provisions, and other limitations. The
Company may amend or change the plan periodically. The Company is not pre-
funding its retiree medical plan.
The net periodic postretirement cost for the Company was as follows:
<TABLE>
<CAPTION>
1993
(in thousands)
<S> <C>
Service cost $127
Interest cost 250
Amortization of transition
obligation 150
Net periodic postretirement
benefit cost $527
</TABLE>
Funding information as of October 1 was as follows:
<TABLE>
<CAPTION>
1993
(in thousands)
<S> <C>
Accumulated postretirement benefit
obligation:
Retirees $1,316
Fully eligible active participants 865
Other active participants 1,921
Unfunded accumulated postretirement
benefit obligation 4,102
Unrecognized net loss (892)
Unrecognized transition obligation (2,846)
Accrued postretirement benefit cost $ 364
</TABLE>
For measurement purposes, an 11.5% annual rate of increase in healthcare
benefits was assumed for 1994; the rate was assumed to decrease gradually
to 6% in 2005 and remain at that level thereafter. The healthcare cost
trend rate assumption has a significant effect on the amounts reported. A
1% increase in the healthcare cost trend assumption would increase the net
periodic postretirement cost by approximately $140,000 annually or 20.8%.
The weighted-average discount rate used in determining the accumulated
postretirement benefit obligation was 7.5%.
(9) INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, which requires
the use of the liability method in accounting for income taxes. Under the
liability method, deferred income taxes are recognized, at currently
enacted income tax rates, to reflect the tax effect of temporary
differences between the financial reporting and tax basis of assets and
liabilities. Such temporary differences are the result of provisions in
the income tax law that either require or permit certain items to be
reported on the income tax return in a different period than they are
reported in the financial statements. To implement the statement, certain
adjustments were made to accumulated deferred income taxes. To the extent
such income taxes are recoverable or payable through future rates,
regulatory assets and liabilities have been recorded in the accompanying
consolidated balance sheets. Initial application of the statement had no
material impact on the Company's results of operations.
Income tax expense for the years indicated was:
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Current $7,923 $7,745 $9,350
Deferred 1,547 1,273 (289)
Investment tax credits, net (505) (512) (512)
$8,965 $8,506 $8,549
</TABLE>
The sources of temporary differences and the tax effect of each are
summarized as follows:
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Tax in excess of book depreciation $ 662 $ 566 $ 257
Inventory accounting method (184) (179) (308)
Mining development and oil
exploration costs 1,315 848 61
Other (246) 38 (299)
$1,547 $1,273 $ (289)
</TABLE>
The temporary differences which gave rise to the net deferred tax liability
at December 31, 1993 were as follows:
<TABLE>
<CAPTION>
Net Deferred
Income
Tax Asset
Assets Liabilities (Liability)
(in thousands)
<S> <C> <C> <C>
Accelerated depreciation and
other plant-related differences $ - $32,507 $(32,507)
AFUDC-equity - 461 (461)
Regulatory asset 2,350 - 2,350
Unamortized investment tax credits 2,109 - 2,109
Mining development and oil
exploration 746 2,383 (1,637)
Employee benefits 1,227 455 772
Other 839 899 (60)
$7,271 $36,705 $(29,434)
</TABLE>
The effective tax rate differs from the federal statutory rate for the
years ended December 31, as follows:
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Federal statutory rate 35.0% 34.0% 34.0%
Percentage depletion in
excess of cost (2.8) (2.3) (2.3)
Amortization of investment
tax credits (1.6) (1.5) (1.6)
Tax exempt interest income (1.7) (2.3) (2.8)
Other (0.8) (1.4) 0.1
28.1% 26.5% 27.4%
</TABLE>
(10) OIL AND GAS RESERVES (Unaudited)
The following table summarizes Western Production Company's (WPC) estimated
quantities of proved developed and undeveloped oil and natural gas reserves
at December 31, 1993 and 1992, and a reconciliation of the changes between
these dates using constant product prices for the respective years. These
estimates are based on reserve reports by an independent engineering
company selected by the Company. Such reserve estimates are based upon a
number of variable factors and assumptions which may cause these estimates
to differ from actual results.
<TABLE>
<CAPTION>
1993 1992
Oil Gas Oil Gas
(in thousands of barrels of oil and MCF of gas)
<S> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Balance at beginning of year 2,199 3,243 2,524 4,799
Production (327) (777) (247) (379)
Additions 259 1,847 193 272
Revisions to previous
estimates due to changed
economic conditions (1,015) (1,554) (271) (1,449)
Balance at end of year 1,116 2,759 2,199 3,243
Proved developed reserves at end
of year included above 1,116 2,759 1,630 2,633
Year end prices $13.00 $ 2.35 $18.75 $ 1.65
</TABLE>
WPC has interests in 386 oil and gas properties in seven states. WPC
operates a total of 347 wells in Wyoming, Colorado, and South Dakota.
WPC's non-operated properties are located in Wyoming, Colorado, North
Dakota, Montana, Kansas, and Texas. WPC also holds leases on approximately
74,000 gross and 50,000 net undeveloped acres.
(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS
The three primary segments of the Company's business are its electric, coal
mining, and oil and gas production operations. The following table
summarizes certain information specifically identifiable with each segment
as of or for the years ended December 31.
<TABLE>
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Assets at year end:
Electric $259,680 $238,378 $228,788
Coal mining 72,328 71,194 71,873
Oil and gas production 20,845 20,630 19,234
$352,853 $330,202 $319,895
Depreciation, depletion, and
amortization:
Electric $ 9,952 $ 9,614 $ 8,644
Coal mining 1,953 1,482 1,572
Oil and gas production 4,146 2,764 1,796
$ 16,051 $ 13,860 $ 12,012
Capital expenditures:
NSS #2 (includes AFDC) $12,792 $ 2,227 $ -
Other electric 13,140 15,507 29,865*
Coal mining 7,425 5,001 1,129
Oil and gas production 6,933 5,180 5,987
$ 40,290 $ 27,915 $ 36,981
<FN>
* Includes the acquisition of the Wyodak Plant (See Note 6).
</TABLE>
(12) SUPPLEMENTARY INCOME STATEMENT INFORMATION
PACIFICORP COAL SETTLEMENT
In 1987 WRDC entered into an agreement with PacifiCorp which (a) settled
PacifiCorp's obligation to purchase coal commencing in 1990 for a second
plant to be located at Wyodak, the construction of which had been canceled,
(b) provided for, among other things, increases in the coal price and
minimum coal purchase obligations by PacifiCorp for the Wyodak Plant, and
(c) provided for payments to WRDC of $2,000,000 each on January 2, 1988
through 1991 for an option to purchase additional coal. These settlements
resulted in an increase in the Company's net income in 1993, 1992, and 1991
of approximately $1,500,000, $2,800,000, and $2,600,000 or $0.11, $0.20,
and $0.19 per share of common stock, respectively.
OTHER COAL SETTLEMENTS
In late 1987 WRDC agreed to the termination of a long-term coal supply
agreement with the city of Grand Island, Nebraska. Grand Island was
granted a 14 year option to purchase coal and in return WRDC will receive
payments of approximately $155,000 each year.
<TABLE>
TAXES OTHER THAN INCOME TAXES
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Property $ 3,549 $2,996 $2,366
Production and severance 2,982 2,622 2,820
Payroll 1,195 1,225 1,164
Black lung 1,256 1,191 1,099
Federal reclamation 1,060 1,035 960
Other 167 195 170
$10,209 $9,264 $8,579
</TABLE>
<TABLE>
COMPONENTS OF OTHER INCOME (EXPENSE):
<CAPTION>
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Coal settlements
PacifiCorp $ - $ 940 $ 802
Grand Island 155 155 125
Other 319 138 (296)
$ 474 $1,233 $ 631
</TABLE>
(13) QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data for the years indicated are summarized as follows:
<TABLE>
<CAPTION>
First Second Third Fourth
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1993
Operating revenues $34,375 $32,924 $36,304 $35,770
Operating income 9,980 7,793 10,087 9,926
Net income 6,103 4,575 6,011 6,257
Earnings per share of common
stock 0.45 0.33 0.44 0.44
Common stock prices
High $28-1/4 $27-1/4 $27-1/8 $26-1/8
Low $24-7/8 $24-5/8 $25-1/8 $21-7/8
Dividends paid per share
of common stock $ 0.32 $ 0.32 $ 0.32 $ 0.32
YEAR ENDED DECEMBER 31, 1992
Operating revenues $32,463 $32,175 $35,359 $35,346
Operating income 8,826 7,608 10,050 9,865
Net income 5,588 5,581 6,276 6,193
Earnings per share of common
stock 0.41 0.41 0.46 0.45
Common stock prices
High $29-1/2 $32-1/4 $29-5/8 $29-1/4
Low $25-3/8 $25-1/2 $27-1/2 $23-3/4
Dividends paid per share
of common stock $ 0.31 $ 0.31 $ 0.31 $ 0.31
</TABLE>
<PAGE>
<TABLE>
SELECTED FINANCIAL DATA
(unaudited)
<CAPTION>
Years ended December 31 1993 1992 1991 1990 1989
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Operating revenues $139,373 $135,343 $133,373 $127,498 $120,004
Net income from
continuing operations 22,946 23,638 22,681 22,938 21,957
Per share of common
stock:
Earnings from
continuing operations 1.66 1.73 1.66 1.68 1.60
Dividends paid 1.28 1.24 1.17 1.09 1.01
Total assets 352,853 330,202 319,895 294,929 272,523
Total long-term
obligations 85,274 88,816 92,982 78,978 78,939
</TABLE>
<PAGE>
<TABLE>
FINANCIAL STATISTICS
<CAPTION>
Years ended December 31 1993 1992 1991
<S> <C> <C> <C>
TOTAL ASSETS (in thousands) $352,853 $330,202 $319,895
PROPERTY AND INVESTMENTS (in thousands)
Total property and investments . . .$433,143 $413,192 $390,766
Accumulated depreciation
and depletion. . . . . . . . . . . . 144,492 132,890 122,574
Capital expenditures
(includes AFDC) . . . . . . . . . . 40,290 27,915 36,981
CAPITALIZATION (in thousands)
Long-term debt . . . . . . . . . . .$ 85,274 $ 88,816 $ 92,982
Common stock equity . . . . . . . . . 168,089 149,158 141,963
Total . . . . . . . . . . . . .$253,363 $237,974 $234,945
CAPITALIZATION RATIOS
Long-term debt . . . . . . . . . . . 33.7% 37.3% 39.6%
Common stock equity . . . . . . . . . 66.3 62.7 60.4
Total . . . . . . . . . . . . . . 100.0% 100.0% 100.0%
AVERAGE INTEREST RATE ON LONG-TERM DEBT 9.0% 8.9% 8.9%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) . . . . $ 22,946 $ 23,638 $ 22,681
DIVIDENDS PAID ON COMMON STOCK
(in thousands) . . . . . . . . . . . $ 17,720 $ 16,977 $ 16,045
COMMON STOCK DATA (in thousands)*
Shares outstanding, average. . . . . . 13,811 13,689 13,675
Shares outstanding, end of year. . . . 14,270 13,701 13,675
Earnings per average share,
in dollars. . . . . . . . . . . . . $ 1.66 $ 1.73 $ 1.66
Dividends paid per share, in dollars $ 1.28 $ 1.24 $ 1.17
Book value per share, end of
year, in dollars. . . . . . . . . . $ 11.78 $ 10.89 $ 10.38
RETURN ON COMMON STOCK EQUITY. . . . . 13.7% 15.8% 16.0%
ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION AS PERCENT OF NET
INCOME. . . . . . . . . . . . . . . . 3.2% 1.6% 0.8%
(continued)
<CAPTION>
Years ended December 31 1990 1989 1988
<S> <C> <C> <C>
TOTAL ASSETS (in thousands) $294,929 $272,523 $270,258
PROPERTY AND INVESTMENTS (in thousands)
Total property and investments. . . .$355,276 $331,310 $304,445
Accumulated depreciation
and depletion. . . . . . . . . . . . 111,111 101,591 92,661
Capital expenditures
(includes AFDC) . . . . . . . . . . 22,336 10,176 12,950
CAPITALIZATION (in thousands)
Long-term debt . . . . . . . . . . .$ 78,978 $ 78,939 $ 82,709
Common stock equity . . . . . . . . . 135,329 127,338 120,100
Total . . . . . . . . . . . . .$214,307 $206,277 $202,809
CAPITALIZATION RATIOS
Long-term debt . . . . . . . . . . . 36.9% 38.3% 40.8%
Common stock equity . . . . . . . . . 63.1 61.7 59.2
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0%
AVERAGE INTEREST RATE ON LONG-TERM DEBT 8.6% 8.5% 8.5%
NET INCOME AVAILABLE FOR
COMMON STOCK (in thousands) . . . . $ 22,938 $ 21,096 $ 22,191
DIVIDENDS PAID ON COMMON STOCK
(in thousands) . . . . . . . . . . . $ 14,947 $ 13,858 $ 12,756
COMMON STOCK DATA (in thousands)*
Shares outstanding, average. . . . . . 13,675 13,675 13,665
Shares outstanding, end of year. . . . 13,675 13,675 13,675
Earnings per average share,
in dollars. . . . . . . . . . . . . $ 1.68 $ 1.54 $ 1.62
Dividends paid per share, in dollars.$ 1.09 $ 1.01 $ 0.93
Book value per share, end of
year, in dollars . . . . . . . . . $ 9.90 $ 9.31 $ 8.78
RETURN ON COMMON STOCK EQUITY . . . . 16.9% 16.6% 18.5%
ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION AS PERCENT OF
NET INCOME . . . . . . . . . . . . 1.2% 0.5% 0.7%
<FN>
* Common stock data have been adjusted retroactively to reflect the three-
for-two stock split in March 1992.
</TABLE>
<PAGE>
<TABLE>
ELECTRIC OPERATION STATISTICS
<CAPTION>
Years ended December 31 1993 1992 1991
<S> <C> <C> <C>
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt hours)
Generated, net station output . . . 1,227,084 1,226,153 1,148,259
Purchased and net interchange . . . 435,990 397,478 444,848
Total generated and purchased . 1,663,074 1,623,631 1,593,107
Non-firm sales . . . . . . . . . . . (7,780) (10,405) (1,040)
Company use and losses . . . . . . . (61,336) (73,627) (59,896)
Total electric energy sales . . 1,593,958 1,539,599 1,532,171
ELECTRIC ENERGY SALES (megawatt hours)
Residential . . . . . . . . . . . . 370,736 339,341 355,691
General and commercial . . . . . . . 469,496 446,036 440,043
Industrial . . . . . . . . . . . . . 568,316 572,244 550,999
Public authorities . . . . . . . . . 22,621 21,798 21,347
Sales for resale . . . . . . . . . . 162,789 160,180 164,091
Total electric energy sales . . 1,593,958 1,539,599 1,532,171
ELECTRIC REVENUE (in thousands)
Residential . . . . . . . . . . . . $ 27,064 $ 25,366 $ 27,053
General and commercial . . . . . . . 32,295 30,742 31,227
Industrial . . . . . . . . . . . . . 25,901 27,106 26,812
Public authorities . . . . . . . . . 1,537 1,586 1,593
Sales for resale . . . . . . . . . . 7,122 7,002 7,223
Total electric revenue . . . . 93,919 91,802 93,908
Other revenue. . . . . . . . . . . . 4,236 5,646 4,250
Total revenue $ 98,155 $ 97,448 $ 98,158
ELECTRIC CUSTOMERS (end of year)
Residential . . . . . . . . . . . . 44,657 44,100 43,539
General and commercial . . . . . . . 8,507 8,279 8,083
Industrial . . . . . . . . . . . . . 41 38 40
Public authorities . . . . . . . . . 124 117 112
Other electric utilities . . . . . . 1 1 1
Total . . . . . . . . . . . . . 53,330 52,535 51,775
RESIDENTIAL STATISTICS
Average annual KWH usage:
With electric heating. . . . . . . 17,601 15,380 16,773
Without electric heating . . . . . 6,428 6,172 6,502
All residential. . . . . . . . . . 8,351 7,743 8,218
Average price per KWH, in cents . . 7.2 7.6 7.6
AVERAGE PRICE PER KWH, ALL CUSTOMERS
(in cents) . . . . . . . . . . . . . . 6.0 6.2 6.1
(continued)
<CAPTION>
Years ended December 31 1990 1989 1988
<S> <C> <C> <C>
ELECTRIC ENERGY GENERATED
AND PURCHASED (megawatt hours)
Generated, net station output . . . 1,169,054 1,046,971 1,119,073
Purchased and net interchange . . . 379,268 468,768 388,394
Total generated and purchased . 1,548,322 1,515,739 1,507,467
Non-firm sales . . . . . . . . . . . (5,576) (29,087) (45,943)
Company use and losses . . . . . . . (64,031) (53,282) (56,869)
Total electric energy sales . . 1,478,715 1,433,370 1,404,655
ELECTRIC ENERGY SALES (megawatt hours)
Residential . . . . . . . . . . . . 338,391 343,645 337,375
General and commercial . . . . . . . 415,635 395,712 396,366
Industrial . . . . . . . . . . . . . 542,312 529,703 509,036
Public authorities . . . . . . . . . 20,819 20,980 24,574
Sales for resale . . . . . . . . . . 161,558 143,330 137,304
Total electric energy sales . . 1,478,715 1,433,370 1,404,655
ELECTRIC REVENUE (in thousands)
Residential . . . . . . . . . . . . $ 25,498 $ 25,456 $ 24,768
General and commercial . . . . . . . 29,027 27,815 26,884
Industrial . . . . . . . . . . . . . 25,917 25,153 23,359
Public authorities . . . . . . . . . 1,540 1,563 1,656
Sales for resale . . . . . . . . . . 6,532 5,745 5,740
Total electric revenue . . . . 88,514 85,732 82,407
Other revenue . . . . . . . 3,762 4,650 3,838
Total revenue $ 92,276 $ 90,382 $ 86,245
ELECTRIC CUSTOMERS (end of year)
Residential . . . . . . . . . . . . 43,020 42,505 41,880
General and commercial . . . . . . . 7,866 7,703 7,512
Industrial . . . . . . . . . . . . . 44 40 37
Public authorities . . . . . . . . . 114 111 105
Other electric utilities . . . . . . 1 1 1
Total . . . . . . . . . . . . . 51,045 50,360 49,535
RESIDENTIAL STATISTICS
Average annual KWH usage:
With electric heating. . . . . . . 15,978 16,881 16,218
Without electric heating . . . . . 6,288 6,421 6,461
All residential. . . . . . . . . . 7,897 8,171 8,056
Average price per KWH, in cents . . 7.5 7.4 7.3
AVERAGE PRICE PER KWH, ALL CUSTOMERS
(in cents) . . . . . . . . . . . . . . 6.0 6.0 5.9
</TABLE>
<PAGE>
DIRECTORY
COMMON STOCK
Transfer Agent, Registrar, and Dividend Disbursing Agent
Chemical Bank
450 West 33rd Street
New York, New York 10001
FIRST MORTGAGE BONDS
Trustee and Paying Agent
Chemical Bank
450 West 33rd Street
New York, New York 10001
POLLUTION CONTROL AND INDUSTRIAL DEVELOPMENT REVENUE BONDS
Trustee and Paying Agent
Norwest Bank Minnesota, N.A.
Eighth Street and Marquette Avenue
Minneapolis, Minnesota 55479
GENERAL COUNSEL
Morrill Brown & Thomas
P.O. Box 8108
Rapid City, South Dakota 57709
CORPORATE OFFICES
Black Hills Corporation
P.O. Box 1400
Rapid City, South Dakota 57709
(605) 348-1700
The Company's common stock ($1 par value) is traded on The New York Stock
Exchange. Quotations for the common stock are reported under the symbol
BKH. At year-end the Company had 7,243 common stockholders of record. All
fifty states and the District of Columbia plus twelve foreign countries are
represented.
The continued interest and support of equity owners is appreciated. The
Company has declared common stock dividends payable in cash in each year
since its incorporation in 1941. At its January 1994 meeting the Board of
Directors raised the quarterly dividend to 33 cents per share, equivalent
to an annual increase of 4 cents per share. This regular quarterly
dividend is payable March 1, 1994. All dividends are reportable for
federal income tax purposes as ordinary dividend income.
The Annual Report is mailed to each shareholder in accordance with
government rules. Dividend payments and interim reports of the Company are
mailed quarterly. Dividend payment dates are March 1, June 1, September 1,
and December 1. You may receive more than one copy of the Annual Report if
there are variations in your name or address in which your stock is
registered. Duplicate mailings of annual and interim reports can be
eliminated upon written request of the shareholder.
A COPY OF THE COMPANY'S ANNUAL REPORT ON FORM 10-K, FILED WITH THE
SECURITIES AND EXCHANGE COMMISION, IS AVAILABLE TO SHAREHOLDERS WITHOUT
CHARGE UPON WRITTEN REQUEST TO ROXANN R. BASHAM, SECRETARY, P.O. BOX 1400,
RAPID CITY, SOUTH DAKOTA 57709.
1994 ANNUAL MEETING
The Annual Meeting of Stockholders will be held at the Holiday Inn -
Rushmore Plaza Hotel, 505 North Fifth Street, Rapid City, South Dakota, at
9:30 A.M., on May 24, 1994. Prior to the meeting, formal notice, proxy
statement, and proxy will be mailed to shareholders.
DIRECT DEPOSIT OF DIVIDENDS
The Company encourages you to consider the direct deposit of your
dividends. With direct deposit, your quarterly dividend payment can be
automatically transferred on the dividend payment date to the bank, savings
and loan, or credit union of your choice. Direct deposit assures payments
are credited to shareholders' accounts without delay. A form is attached
to your dividend check where you can request information about this method
of payment. Questions regarding direct deposit should be directed to
Chemical Bank, Security Holder Relations, P. O. Box 24935, Church Street
Station, New York, New York 10249.
DIVIDEND REINVESTMENT PLAN
A Dividend Reinvestment and Stock Purchase Plan (the Plan) is available to
common shareholders. The Company revised its plan in November 1993. The
new Plan provides a method of investing common stock dividends and optional
cash payments in additional shares of common stock of the Company at 100
percent of the recent average market price. The participant may elect to
continue to receive cash dividends on shares registered in their names and
invest by making optional cash payments only. Questions regarding the Plan
should be directed to the Secretary of the Company or Chemical Bank,
Dividend Reinvestment Department, J.A.F. Building, P.O. Box 3069, New York,
New York 10116-3069 or by calling the Bank toll free at 1-800-279-1246.
