SECURITIES AND EXCHANGE COMMISSION
                                    Washington, DC 20549
                                         Form 10-K

     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
X    ACT OF 1934

     For the fiscal year ended December 31, 1998

     TRANSITION  REPORT  PURSUANT  TO  SECTION  13 OR  15(d)  OF THE  SECURITIES
     EXCHANGE ACT OF 1934

      For the transition period from ___________________ to __________________

      Commission File Number 1-7978

                                  BLACK HILLS CORPORATION

      Incorporated in South Dakota         IRS Identification Number 46-0111677

                                625 Ninth Street
                         Rapid City, South Dakota 57701

               Registrant's telephone number, including area code
                                 (605) 348-1700

           Securities registered pursuant to Section 12(b) of the Act:

                                                      Name of each exchange
      Title of each class                              on which registered
      -------------------                              -------------------

Common stock of $1.00 par value                      New York Stock Exchange

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding 12 months (or for such  shorter  period that the  Registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days.

                                 YES X NO______

Indicate by check mark if disclosure of delinquent  filers  pursuant to Item 405
of Regulation  S-K is not contained  herein,  and will not be contained,  to the
best of Registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X

State the aggregate market value of the voting stock held by  non-affiliates  of
the Registrant.

                        At February 26, 1999 $461,115,553

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 26, 1999
           -----                               --------------------------------

 Common stock, $1.00 par value                         21,447,235 shares

Documents Incorporated by Reference

1.   Definitive  Proxy Statement of the Registrant  filed pursuant to Regulation
     14A for the 1999 Annual Meeting of Stockholders to be held on May 11, 1999,
     is incorporated by reference in Part III. TABLE OF CONTENTS Page
<PAGE>

ITEM 1.  BUSINESS.............................................................4
             GENERAL..........................................................4
             ELECTRIC POWER SUPPLY............................................5
             ELECTRIC SERVICE TERRITORY AND SALES.............................6
             COMPETITION IN THE ELECTRIC UTILITY BUSINESS.....................7
             ENERGY EXTRACTION AND PRODUCTION.................................7
             ENERGY MARKETING OPERATIONS......................................9
             COMMUNICATIONS OPERATIONS........................................9
             ENVIRONMENTAL REGULATION........................................10
             EMPLOYEES.......................................................12

ITEM 2.  PROPERTIES..........................................................13
             UTILITY PROPERTIES..............................................13
             ENERGY EXTRACTION AND PRODUCTION PROPERTIES.....................13

ITEM 3.  LEGAL PROCEEDINGS...................................................14

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................15

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS.................................................16

ITEM 6.  SELECTED FINANCIAL DATA.............................................16

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS.................................17
             LIQUIDITY AND CAPITAL RESOURCES.................................17
             MARKET RISK DISCLOSURES.........................................19
             RATE REGULATION.................................................21
             COMPETITION IN ELECTRIC UTILITY BUSINESS........................21
             RESULTS OF OPERATIONS...........................................24
             BUSINESS OUTLOOK STATEMENTS.....................................33

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.........................37

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
         ON ACCOUNTING AND FINANCIAL DISCLOSURE..............................59

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................59

ITEM 11. EXECUTIVE COMPENSATION..............................................60

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT......60

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................60

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.....60

         SIGNATURES..........................................................63




<PAGE>
                                        DEFINITIONS

When the  following  terms  are used in the text  they  will  have the  meanings
indicated.

Term                           Meaning

BlackHills  Power.............Black Hills Power and LightCompany, 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

Black Hills Capital Group.....Black Hills Capital Group, Inc., a wholly owned 
                              subsidiary of Wyodak Resources

Black Hills Exploration and Production......Black Hills Exploration and 
                                            Production, Inc., (formerly Western
                                            Production Company) a wholly owned 
                                            subsidiary of Wyodak Resources

Clovis                        Point Mine.............Clovis Point Mine refers to
                              coal  properties  Wyodak  Resources  acquired from
                              Kerr-McGee  Coal   Corporation   consisting  of  a
                              federal  coal  lease,  a state coal lease and real
                              property  interests  including coal processing and
                              rail loading
                              facilities.

Company.......................Black Hills Corporation

DEQ...........................Department of Environmental Quality of the State 
                              of Wyoming

FERC..........................Federal Energy Regulatory Commission

MDU...........................Montana-Dakota Utilities Co., a division of MDU 
                              Resources Group, Inc.

NS #1.........................Neil Simpson Unit #1, a 20 megawatt coal-fired 
                              electric generating plant owned by the Company and
                              located adjacent to the Wyodak Plant and Neil 
                              Simpson Unit #2

NS #2.........................Neil Simpson Unit #2, an 80 megawatt coal-fired 
                              electric generating plant owned by the Company and
                              located adjacent to the Wyodak Plant and Neil 
                              Simpson Unit #1

Pacific Power.................PacifiCorp, which operates its electric utility 
                              operations under the assumed names of Pacific 
                              Power and Utah Power

RECs..........................Rural electric cooperatives, which are owned by 
                              their customers and which rely primarily on the 
                              United States for their financing needs

SDPUC.........................The South Dakota Public Utilities Commission

WAPA..........................Western Area Power Administration, an agency of 
                              the Department of Energy of the United States of 
                              America

WPSC..........................The Wyoming Public Service Commission

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>

4

PART I

ITEM 1.   BUSINESS

                  GENERAL

Incorporated  under the laws of South  Dakota in 1941,  the Company is an energy
and communications  company primarily  consisting of four principal  businesses:
electric,   energy   extraction   and   production,    energy   marketing,   and
communications.  The Company's  mission  statement is to provide quality service
and energy and communications products at competitive prices in targeted markets
in order to build value for customers and shareholders and create  opportunities
for employees. The Company operates its public utility electric operations under
the assumed  name of Black Hills Power and Light  Company,  operates  its energy
extraction and production  businesses  through its subsidiary  Wyodak  Resources
related to coal, and Black Hills  Exploration and Production  (formerly  Western
Production Company) related to oil and natural gas, and its energy marketing and
communication operations through Black Hills Capital Group and its affiliates.

Black  Hills  Power  is  engaged  in  the  generation,  purchase,  transmission,
distribution  and sale of  electric  power and  energy to  approximately  56,900
customers  in 11  counties in western  South  Dakota,  northeastern  Wyoming and
southeastern  Montana,  an area with a  population  estimated  at  165,000.  The
largest community served is Rapid City, South Dakota, a major retail,  wholesale
and health care center,  with a  population,  including  environs,  estimated at
75,000.  Agriculture,  tourism, small stakes gambling,  mining, lumbering, small
item  manufacturing,  service  and support  businesses  and  government  support
through  Ellsworth  Air Force Base are the primary  influences  on the  economic
well-being of the region.

Wyodak Resources, incorporated under the laws of Delaware in 1956, is engaged in
the  mining  and  sale  of  low  sulfur   sub-bituminous  coal  and  is  located
approximately five miles east of Gillette, Wyoming, in the Powder River Basin.

Black  Hills  Exploration  and  Production  is an oil  and gas  exploration  and
production  company with interests located in the Rocky Mountain region,  Texas,
California and various other locations.

Black Hills Capital Group,  incorporated under the laws of South Dakota in 1997,
holds the Company's  investments in Black Hills Energy Resources,  Inc., Enserco
Energy, Inc., and Black Hills Coal Network,  Inc. The energy marketing companies
noted above market natural gas, crude oil, coal,  and/or related energy services
to customers in the East Coast, Midwest,  Southwest,  Rocky Mountain,  Northwest
and West Coast regions.

Black Hills Capital Group also holds the  Company's  investments  in Black Hills
FiberCom,  Inc.  and  Daksoft,  Inc. The  communications  companies  noted above
represent  start-up   operations  formed  to  provide  local  and  long-distance
telephone, cable, internet and data services in the Black Hills of South Dakota,
and development and marketing of software products for the utility industry.

In addition to the energy marketing  companies and  communications'  operations,
Black Hills Capital Group directs the Company's corporate development efforts in
the energy and communication areas.

Information  as to the  continuing  lines of  business  of the  Company  for the
calendar years 1996-1998 is as follows:

                                             1998           1997          1996
                                             ----           ----          ----
                                                      (in thousands)
Revenue from sales to unaffiliated customers:
  Electric ........................       $128,834       $126,194       $118,508
  Coal mining .....................         21,157         19,991         20,931
  Oil and gas .....................         12,562         13,295         12,555
  Energy marketing.................        506,043        142,790           --

Revenue from inter-company sales:
  Electric .......................        $   402        $    303        $   210
  Coal mining ........................     10,256          11,089         10,384

For additional information relating to the Company's operations by business line
see Note 11 of "NOTES TO CONSOLIDATED FINANCIAL STATEMENTS".

<PAGE>

                              ELECTRIC POWER SUPPLY

General
-------

Black Hills Power has been able to meet the needs of its  customers for electric
power  and  energy  through  its  owned  generating  capacity  and  by  contract
purchases.  Black Hills  Power's peak load of 348  megawatts was reached in July
1998.  Approximately 45 megawatts of additional load commenced  January 1, 1997,
when Black Hills  Power began  providing  wholesale  electricity  to MDU for its
Sheridan,  Wyoming electric service  territory.  (See ITEM 1.  BUSINESS-ELECTRIC
SERVICE TERRITORY AND SALES - Wholesale to MDU.) Black Hills Power estimated its
1998  required  reserves at 82  megawatts.  Black Hills Power is not presently a
member of a power pool,  but in 1998 Black Hills Power joined the Rocky Mountain
Reserve  Group.  Rocky  Mountain  Reserve Group was approved by FERC in 1998 and
becomes active January 1, 1999. Black Hills Power's 1999 reserve  requirement is
estimated to be 22 megawatts,  consisting  of 11 megawatts of spinning  reserves
and 11 megawatts of secondary reserves.

Black Hills Power owns coal-fired  generating  units having a summer  capability
rating of 214  megawatts  and 77  megawatts  of  oil-fired  diesel  and  natural
gas-fired  combustion  turbines for peaking and standby  use.  Black Hills Power
purchases  additional  resources under three  contracts with Pacific Power:  the
Power Sales  Agreement,  under which it purchases 75 megawatts of baseload power
declining to 50 megawatts  from 2000 to 2004; the Reserve  Capacity  Integration
Agreement,   under  which  33  megawatts  of  additional  reserve  capacity  are
available;  and the Capacity Contract, under which Black Hills Power has options
to be exercised seasonally to purchase up to 60 megawatts of capacity.

Pacific Power's Power Sales Agreement
-------------------------------------

This  agreement  obligates  Black Hills Power to purchase  from Pacific Power 75
megawatts of electric  power plus energy at a load factor varying from a minimum
of 41 percent to a maximum of 80 percent as scheduled  by Black Hills Power.  In
October 1997, Black Hills Power entered into a second Restated and Amended Power
Sales Agreement with Pacific Power. The Amended  Agreement  reduces the contract
capacity by 25 megawatts (5 megawatts per year beginning in 2000).  The contract
terminates  December  31,  2023.  The power and energy  delivered  is power from
Pacific  Power's  system and does not  depend on any one unit,  but the price is
generally  based on  Pacific  Power's  costs  in  Units 3 and 4 of the  Colstrip
coal-fired generating plant near Colstrip,  Montana. Black Hills Power contracts
for transmission  service from Pacific Power under Pacific Power's FERC approved
transmission  rates.  The Company has incurred  capacity  charges of $15,700 per
megawatt month and an average energy charge of $11.90 per megawatt hour over the
last three years of this agreement  with a 60 percent load factor.  (See ITEM 7.
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)

Pacific Power's Reserve Capacity Integration Agreement 
------------------------------------------------------ 

This agreement  obligates Pacific Power until the end of the contract in 2012 to
make  available  to Black Hills Power 100  megawatts  of reserve  capacity to be
acquired by Black Hills Power only at such time under prudent  utility  practice
Black  Hills Power  would have  operated  its  combustion  turbines.  In return,
Pacific  Power has the right to utilize  Black  Hills  Power's  four 25 megawatt
combustion  turbines  (with a summer  rating of 67  megawatts),  but Black Hills
Power has a prior right to use said turbines to support the transmission system.
The price for any energy  Black Hills Power  acquires  under this  agreement  is
based upon the lower of Pacific Power's  incremental  costs of generation of its
highest  price  coal-fired  plant or the cost of fuel to operate the  combustion
turbines.  Pacific Power also pays certain operating and maintenance expenses of
the  combustion  turbines,  together  with a $50,000  payment  per month for the
remaining life of the contract.

Pacific Power's Capacity Contract
---------------------------------

Under this  contract,  Pacific  Power  granted Black Hills Power an option to be
exercised for each six-month season for a period commencing  October 1, 1996 and
ending  March 31,  2007 to purchase up to 60  megawatts  of peaking  capacity at
established  prices.  Black Hills Power may  schedule the energy at a rate up to
100 percent per hour at a load factor up to 15 percent per season. Other than to
give preference to purchasing  peaking capacity from Pacific Power,  Black Hills
Power is under no obligation to exercise any of the six-month seasonal options.

<PAGE>

In addition to granting Black Hills Power options to purchase peaking  capacity,
the Pacific Power Capacity  Contract also obligates Black Hills Power to sell to
Pacific Power until  December 31, 2000,  all surplus  energy which is defined as
the  difference in Black Hills'  Resources  (all energy from Black Hills Power's
generating  resources and energy  entitlement  under Pacific Power's Power Sales
Agreement)  and Black Hills'  Loads  (non-end  user  contracts of five months or
longer and all retail  customers  as they exist from time to time).  The selling
prices are based upon economy energy spot price indices  determined daily in the
western part of the United States with a sharing between Pacific Power and Black
Hills Power of prices above certain  levels.  Black Hills Power is not obligated
to sell any  energy  below its  marginal  production  cost.  The  contract  also
provides  Black Hills Power an option to store energy with Pacific  Power and to
take that  energy  back for the  purpose of  replacing  energy  from a forced or
scheduled outage of NS #2 or Black Hills Power's share of the Wyodak Plant.

To the extent of the excess  capacity and energy  available to Black Hills Power
from its generating  resources and the Pacific Power purchased power  contracts,
Black Hills Power at this time has the  flexibility to serve the expected growth
of its  loads  in  its  service  territory  and as  opportunities  arise  in the
meantime, to increase sales of its energy and capacity.

                      ELECTRIC SERVICE TERRITORY AND SALES

Retail Service Territory
------------------------

Black Hills Power's service territory is currently protected by assigned service
area and  franchises  that  generally  grant to Black Hills Power the  exclusive
right to sell all electric power consumed therein, subject to providing adequate
service.  (See  ITEM  7.  MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF  FINANCIAL
CONDITION AND RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)

As  evidenced by a 1 percent  increase in  customers in both 1998 and 1997,  the
economy in and around  Black  Hills  Power's  service  territory  is believed by
management to be stable.  Small  businesses  and regional  plant  expansions are
continually  being  attracted  to  the  region  along  with  retirees  who  have
discovered the Black Hills region with its scenery,  recreational activities and
medical services to be an attractive place to live. Management  anticipates that
the economy will continue to experience modest growth but can give no assurances
as many economic factors will greatly influence any economy. Ellsworth Air Force
Base, a B-1 bomber  military base near Rapid City,  survived the fourth round of
base closures in 1995 but may be subject to future base closures that are beyond
the Company's  control.  The Company does not serve the air base, but it impacts
the surrounding  economy. In January 1998, Homestake Mining Company (Homestake),
the Company's third largest  customer at 4.6 percent of 1998 electric  revenues,
announced  a  reorganization  and  restructuring  plan at its gold mine in Lead,
South  Dakota.  Load  reductions  at  Homestake  were  mitigated  by  additional
off-system  sales.  Other major  industries  in and around  Black Hills  Power's
service territory have been economically stable.

Wholesale to City of Gillette
-----------------------------

Black Hills  Power sells  electric  power and energy to the  municipal  electric
system at Gillette,  Wyoming.  Service is rendered  under a long-term  contract,
recently amended,  and expiring July 1, 2012, wherein Black Hills Power sells to
the City of Gillette  its first 23 megawatts  of capacity  requirements  and the
associated  energy. In 1997, as part of a contract  amendment,  the transmission
service   component  was  unbundled  from  the  power  supply   agreement,   and
transmission  service will be provided at FERC  approved  rates.  In the amended
contract,  the City of  Gillette  has  agreed  not to apply to FERC for any rate
change to be  effective  prior to January 1, 2003,  unless and in the event that
Black Hills Power files for a rate change with FERC, which rate filing cannot be
effective prior to January 1, 2002, except under extraordinary events as defined
in the  contract.  In  addition,  Black  Hills  Power  agreed  to phase in price
reductions  for the power  purchased  by the City of  Gillette.  The most recent
average  annual   capacity   factor  for  this  23  megawatt   demand  has  been
approximately  90  percent.  Sales to Gillette  represented  9.5 percent and 9.3
percent of total firm  energy  sales and 6.1  percent and 6.6 percent of revenue
from total firm electric sales in 1998 and 1997, respectively.

<PAGE>

Wholesale to MDU
----------------

Black Hills Power and MDU entered into a Power Integration  Agreement,  dated as
of  September  9, 1994,  providing  for the sale to MDU of up to 55 megawatts of
power and associated energy to serve MDU's Sheridan,  Wyoming,  electric service
territory  for a period of 10 years  which  commenced  January 1, 1997.  The MDU
Sheridan  service  territory  has  experienced  a 47  megawatt  winter  peak and
operates at a 57 percent load factor.

The agreement provides for fixed rates for capacity and energy to be paid by MDU
during the 10-year  contract term.  Black Hills Power and MDU have agreed not to
apply to FERC for any rate changes in the  contract for the entire  10-year term
other than increases caused by governmental  direct taxes on electric generation
fired by hydrocarbons.  The agreement further provides for Black Hills Power and
MDU to  equally  share  the  costs  of  constructing  a  combustion  turbine  of
approximately 70 megawatts at such time during the 10-year term that Black Hills
Power determines in its sole discretion that such turbine is required.

Additional Off-System Sales
---------------------------

Black Hills Power sold 371,100,  279,600, and 249,100 megawatt hours of non-firm
energy in 1998, 1997, and 1996, respectively. The selling price is based on spot
market prices which have generated only a small profit margin on the sales. (See
ITEM 7. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)

Transmission Service Sales
--------------------------

Black Hills Power furnishes long-term transmission services under two contracts:
(i) the transmission  contract  terminating  December 31, 2020 (1986 Agreement),
among  Black  Hills  Power  and  Basin  Electric  and  the  other   distribution
cooperatives as it concerns the  transmission  contract (the  Cooperatives)  and
(ii) the agreement with the City of Gillette terminating July 1, 2012 (described
under  Wholesale to City of Gillette  above),  under which Black Hills Power has
agreed to deliver all of the City of Gillette's electric requirements. The rates
charged under the transmission  contract with the Cooperatives are fixed formula
rates, and the transmission rates under the Gillette contract are established by
FERC under Black Hills  Power's open access  transmission  tariff.  (See ITEM 3.
LEGAL  PROCEEDINGS  -  Transmission   Rates  -  FERC  Proceedings  and  ITEM  7.
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.)

                  COMPETITION IN THE ELECTRIC UTILITY BUSINESS

For information  relating to competition in the electric utility  business,  see
ITEM 7. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS -COMPETITION IN ELECTRIC UTILITY BUSINESS.

                        ENERGY EXTRACTION AND PRODUCTION

Coal Sales to Black Hills Power's Plants
----------------------------------------

Wyodak  Resources  sells coal to Black Hills  Power for all of its  requirements
under an agreement that limits earnings from all coal sales to Black Hills Power
(including the 20 percent share on the Wyodak Plant and all sales to Black Hills
Power's  other  plants)  to  a  return  on  Wyodak  Resources'   original  cost,
depreciated  investment  base.  The return is 4 percent (400 basis points) above
A-rated utility bonds to be applied to Wyodak  Resources' coal mining investment
base as determined each year.  Black Hills Power made a commitment to the SDPUC,
the WPSC and the City of  Gillette  that coal would be  furnished  and priced as
provided by this agreement for the life of NS #2. Earnings from the intercompany
sales of coal at this time  represent 5.9 percent of the Company's  consolidated
earnings.

<PAGE>

Sales and production  statistics  for the last three  calendar  years  comparing
sales to Black Hills Power to others are as follows:

                           % Revenue
                Revenue      Derived
               from Sale   from Black    Tons of
     Year       of Coal    Hills Power  Coal Sold
     ----       -------    -----------  ---------
             (in thousands, except % revenue)

     1998        $31,413         33       3,280
     1997         31,080         36       3,251
     1996         31,315         33       3,243


Coal Sales to the Wyodak Plant
------------------------------

Wyodak Resources  furnishes all of the fuel supply for the Wyodak Plant in which
Black Hills  Power owns a 20 percent  interest  and Pacific  Power an 80 percent
interest.  (See Note 6 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.) The price
for  unprocessed  coal sold to Pacific Power for its 80 percent  interest in the
Wyodak  Plant is  determined  by a coal supply  agreement  entered into by Black
Hills Power,  Pacific Power and Wyodak  Resources in 1978 and terminating in the
year 2013.  This  agreement was amended and restated in 1987.  Revenue from coal
sales to the Wyodak Plant totaled  $23,228,000  in 1998 or 74 percent of revenue
for all coal sold by Wyodak Resources. The quantity of coal sold in 1998 for the
Wyodak Plant was  2,120,000  tons,  as compared to 2,155,000  tons sold in 1997.
Barring  unusual  periods of  maintenance,  the quantity of coal for the maximum
consumption  capability  of the  Wyodak  Plant  for one  year  is  approximately
2,100,000 tons and the average yearly consumption is 1,900,000 tons. The average
consumption  is expected to continue  during the  remaining 15 years of the coal
agreement.   However,   from  time  to  time,  the  plant's  physical  operating
capabilities will affect the quantity of coal burned.

Of the 3,280,000 tons of coal sold by Wyodak  Resources in 1998,  1,463,000 tons
were sold to Black Hills Power,  1,697,000  tons were sold to Pacific  Power and
120,000 tons were sold to others.

Wyodak  Resources'  revenue from sales of coal to Pacific  Power and Black Hills
Power as compared to its revenue from all sales to total unaffiliated  customers
for the last three years was as follows:

                  1998     1997    1996
                  ----     ----    ----
                      (in thousands)
Sales to:
Pacific Power    $20,263 $19,240  $19,189
Black Hills      10,256   11,089   10,384
Power
All unaffiliated
 Customers       21,157   19,991   20,931

(See ITEM 7.  MANAGEMENT'S  DISCUSSION  AND ANALYSIS OF FINANCIAL  CONDITION AND
RESULTS OF OPERATIONS-BUSINESS OUTLOOK STATEMENTS--Future Coal Sales.)

Oil and Gas Operations
----------------------

The oil and gas  industry is highly  competitive.  Black Hills  Exploration  and
Production  (formerly Western Production  Company) encounters strong competition
from many oil and gas  producers in acquiring  drilling  prospects and producing
properties.

The Company's oil and gas production is sold at or near the wellhead,  generally
at prevailing  posted prices.  Black Hills  Exploration  and Production has been
able to market all of its oil and gas  production.  Oil and natural gas revenues
are subject to market price volatility. Operating revenue by source for the last
three years was as follows:

          Oil and Gas Gas Plant    Field
Year        Sales      Revenue    Services
----        -----      -------    --------
                   (in thousands)
1998        $9,204      $613      $2,745
1997         9,763       755       2,777
1996         9,050       875       2,630

Black Hills  Exploration and Production sold  approximately  687,000  equivalent
barrels of oil in 1998 comprised of 50 percent oil and 50 percent gas. (See ITEM
7.  MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL  CONDITION AND RESULTS OF
OPERATIONS-BUSINESS OUTLOOK STATEMENTS--Future Oil and Gas Sales.)

<PAGE>
                           ENERGY MARKETING OPERATIONS

The Company's energy marketing  operations market natural gas, crude oil, and/or
coal to customers in the East Coast, Midwest,  Southwest,  Rocky Mountain,  West
Coast  and  Northwest  regions  of the  United  States.  Natural  gas  marketing
operations are located in Houston,  Texas,  and Lakewood,  Colorado,  with sales
offices in  Allentown,  Pennsylvania,  Chicago,  Illinois and Calgary,  Alberta,
Canada. Crude oil marketing operations are headquartered in Houston,  Texas with
sales offices in Tulsa,  Oklahoma and Midland,  Texas. Coal marketing operations
are headquartered in Mason, Ohio.

In October 1998, Enserco Energy, Inc. reacquired the other shareholder interests
becoming a wholly-owned  subsidiary of Black Hills Capital  Group.  In September
1998,  Black Hills Capital Group formed Black Hills Coal Network which  acquired
the assets and hired the operational  management of Coal Network,  Inc. and Coal
Niche, Inc. based in Mason, Ohio.

In July 1997,  Black Hills  Capital  Group  acquired,  through  Wickford  Energy
Marketing,  Inc.,  the  assets  and hired the  operational  management  of Jomax
Partners, L.P. as successor and survivor of Wickford Energy Marketing,  L.C. and
Wickford  Energy  Marketing  Canada  Company.  In March  1998,  Wickford  Energy
Marketing, Inc. changed its name to Black Hills Energy Resources, Inc.

Revenues and marketed daily volumes by energy product for the last two years are
as follows:

                          1998     1997
                          ----     ----
                          (in thousands)
Revenues:
  Natural gas           $375,934 $95,980*
  Crude oil             117,185   46,810*
  Coal                   12,924*       -

Daily Volumes:
  Natural gas (mmbtus)  487,000  231,000*
  Crude oil (barrels)   19,000    12,600*
  Coal (tons)            4,400*        -

*Since date of acquisition

The  marketing   operations  are  high  volume,   low  margin  businesses  whose
contribution to  consolidated  earnings has not been  significant.  (See ITEM 7.
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS -RESULTS OF OPERATIONS - Energy Marketing Operations.)

                            COMMUNICATIONS OPERATIONS

In September 1998,  Black Hills Capital Group formed Black Hills FiberCom,  Inc.
to  provide  facilities-based  communication  services  for  Rapid  City and the
Northern Black Hills of South Dakota .

The newly formed  company is expected to invest more than  $50,000,000  over the
next three years in  state-of-the-art  technology that will offer local and long
distance telephone service,  expanded cable television service, Internet access,
and high-speed  data and video services.  System  engineering and acquisition of
equipment  began in the fourth  quarter of 1998. The network is expected to take
two to three years to build out the complete system. The Company plans to market
the communications services to schools, hospitals,  cities, economic development
groups, and business and residential customers.

The hybrid fiber coaxial cable link will enable customers to receive  telephone,
cable television,  internet,  and high-speed data and video services all through
one cable  coming into their  businesses  and homes.  The network is designed to
provide  greater  reliability  because there will be  redundancy  built into the
system. Compared with the present telecommunications network in the Black Hills,
connections to homes and businesses are expected to have  significantly  greater
capacity.

The Company is partnering  with an  international  telecommunications  firm, GLA
International,  of St. Louis, Missouri, to build a 200 mile fiber optic backbone
and a 500-mile hybrid fiber coaxial network in Rapid City and the Northern Black
Hills.  Black Hills  FiberCom's  assets and net income are  expected to comprise
less than 10 percent of consolidated assets and earnings when fully implemented.

DAKSOFT,  Inc.  develops  and markets  internally  generated  computer  software
associated with the Company's business segments and the utility industry.

<PAGE>

                            ENVIRONMENTAL REGULATION

The  Company  is  subject  to  extensive  federal,  state  and  local  laws  and
regulations  governing  discharges to the air and water, as well as the handling
and disposal of solid and hazardous  wastes,  including  without  limitation the
federal Clean Air Act (as amended in 1990), the federal Water Pollution  Control
Act ("Clean Water Act"),  the federal Toxic  Substances  Control Act and various
state laws,  including  solid waste disposal laws  (collectively  "Environmental
Regulatory Laws"). Governmental authorities have the power to enforce compliance
with  Environmental  Regulatory  Laws,  and violators may be subject to civil or
criminal  penalties,  injunctions or both. Third parties also may have the right
to sue to enforce compliance.

Air Quality
-----------

Under the federal  Clean Air Act, the federal  Environmental  Protection  Agency
("EPA")  has  promulgated   national  air  quality  standards  for  certain  air
pollutants, including sulfur oxides, particulate matter and nitrogen oxides. The
Company  was  granted  a  prevention  of   significant   deterioration   ("PSD")
construction  permit  by the DEQ  for NS #2.  The PSD  construction  permit  set
emission rate  limitations on particulate,  sulfur dioxide,  nitrogen oxides and
opacity.  Black  Hills  Power has been in  substantial  compliance  with its PSD
construction permit in its operations of NS #2 since its completion in August of
1995.  Black  Hills Power  expects to receive an  operational  PSD  construction
permit from DEQ in 1999.

Amendments to the Clean Air Act in 1990 will require a significant  reduction in
nationwide  sulfur oxide emissions by fossil  fuel-fired  generating  units to a
permanent total emissions cap in the year 2000. This reduction is to be achieved
by the allotment of allowances to emit sulfur dioxide  measured in tons per year
to each owner of a unit and  requiring the owner to hold  sufficient  allowances
each year to cover the emissions of sulfur oxide from the unit during that year.
Black  Hills  Power holds  sufficient  allowances  credited to it as a result of
sulfur removal  equipment  previously  installed on the Wyodak Plant to apply to
the  operation  of NS #2 and its  interest in the Wyodak  Plant in the year 2000
without  requiring the purchase of any additional  allowances.  Current law does
not require allowances for Black Hills Power's other plants.

All existing  generating  units of the Company are required to obtain  operating
source  permits  under  the  Clean  Air Act  amendments.  The  operating  permit
applications for the Osage and NS #1 generating units were submitted in 1995 and
received in 1997. Air quality permits for the Ben French Station were renewed in
1995 by the  Department of  Environment  and Natural  Resources of South Dakota.
Black Hills Power expects to receive a renewed permit in 1999.

Because the 1990 amendments to the Clean Air Act are scheduled to be implemented
and interpreted throughout the 1990s,  compliance with yet-to-be promulgated and
interpreted   regulations  may  require   additional   capital  and  operational
expenditures in the future,  most likely from enhanced  monitoring costs. Due to
the political  sensitivity and volatility of  environmental  issues and how they
may be implemented, management can give no assurances that unexpected additional
capital  and  operating  costs may be  required  in the future that would have a
material impact on financial results.

Water Quality
-------------

The federal Clean Water Act requires permits for discharges of effluent and that
all discharges of pollutants comply with federally  approved state water quality
standards.  Black Hills Power currently has in place all required  permits under
the Clean Water Act for  discharges  from all of the power plants in which Black
Hills  Power  has an  interest.  While  management  believes  that it is in full
compliance with all federal and state clean water laws and regulations,  for all
the same reasons as stated in the previous paragraph, no assurances can be given
of the extent of costs to comply with clean water requirements in the future.

Land Quality - Solid Waste Disposal
-----------------------------------

Black Hills Power  disposes  all solid  wastes  collected as a result of burning
coal at its power plants in approved solid waste disposal  sites.  Each disposal
site has been permitted by the state of its location in compliance with law. Ash
and wastes from flue gas and sulfur  removal from the Wyodak Plant and NS #2 are
deposited in Wyodak  Resources'  mined areas.  These  disposal areas are located
below some shallow water aquifers in the mine. None of the solid wastes from the
burning of coal is classified as hazardous  material,  but the wastes do contain
minute traces of metals that would be perceived as polluting if such metals were
leached into underground water.  Recent  investigations  have concluded that the
wastes are relatively  insoluble and will not measurably  affect the post-mining
ground water quality. While management does not believe that any substances from
the solid  waste  disposal  will  pollute  underground  water,  they can give no
assurances  that over a long  period of time such could  never  happen.  In such
event,  the Company could  experience  material  costs in mitigating any damages
from such pollution. Agreements in place require Pacific Power to be responsible
for any such costs that would be related to the solid  waste from its 80 percent
interest in the Wyodak Plant.

<PAGE>


Additional unexpected material costs could also result in the future from either
the federal or state government determining that solid waste from the burning of
coal does contain some hazardous  material that requires some special treatment,
including  solid waste  previously  disposed of, and holding those  entities who
disposed  of  such  waste  responsible  for  such  treatment.   Such  unexpected
governmental requirements are beyond the control of the Company.

Reclamation
-----------

Under federal and state laws and  regulations,  Wyodak  Resources is required to
submit to and receive  approval from the DEQ for a mining and  reclamation  plan
which  provides  for orderly  mining,  reclaiming  and  restoring of all land in
conformity  with all laws and  regulations.  Wyodak  Resources  has an  approved
mining permit and is otherwise in compliance with other land quality  permitting
programs.

One condition that could result in substantial  unexpected increases in costs of
the  reclamation  permit  relates  to  three  depressions,  the  existing  south
depression, the Peerless depression and the North Pit depression,  which have or
will result from Wyodak  Resources'  mining.  Because of the thick coal seam and
relatively shallow overburden,  the present plan for restoration leaves areas of
the mine that will have limited reclamation  potential because of their location
in  depressions  with interior  drainage  only.  While the DEQ has allowed these
depressions  in the present  plan,  the DEQ has reserved the right to review and
evaluate  future  mining  plans  proposed  by Wyodak  Resources.  Such plans are
reviewed for the  feasibility and  desirability  of causing Wyodak  Resources to
place additional  overburden generated elsewhere for the purpose of reducing the
depressions  if the DEQ  finds  that  the  placement  is  necessary  to  prevent
degradation of more areas than expected.  The DEQ has allowed the depressions at
the maximum acres  specified and subject to  maintenance of water quality at the
sites.  Exceedence of acreage  limitations or degradation of water quality could
result  in  material  additional  requirements  placed  upon  Wyodak  Resources,
including  the   placement  of  additional   quantities  of  overburden  in  the
depressions and restoring water quality. Based on extensive reclamation studies,
accruals are maintained to comply with all reclamation requirements. However, no
assurances  can be given  that  additional  requirements  in the  future  may be
imposed that cause unexpected material increases in reclamation costs.

Ben French Oil Spill
--------------------

In 1990 and 1991,  Black Hills Power discovered  extensive  underground fuel oil
contamination at the Ben French Plant site. With the help of expert consultants,
the Company  engaged in assessment and  remediation  and has worked closely with
the South Dakota Department of Environment and Natural Resources. Assessment and
remediation  efforts are  continuing  up to the present  time.  All  underground
oil-carrying  facilities  from which the  contamination  occurred  are now above
ground. There have been no significant recoveries of free fuel oil product since
1994.  Black  Hills  Power  continues  to monitor  the site.  Soil  borings  and
monitoring  wells on the  perimeters  of Black Hills  Power's  Ben French  Plant
property  are  showing no  indication  of  contamination  beyond the  property's
limits.  Management  believes that the underground  spill has been  sufficiently
remedied  so as to prevent  any oil from  migrating  off site.  However,  due to
underground  gypsum  deposits in this area,  the fuel oil has the  potential  of
migrating  to area  waterways.  In such  event,  cleanup  costs could be greatly
increased.  Management  believes that sufficient  remediation efforts to prevent
such a  migration  are  currently  in  place,  but due to the  uncertainties  of
underground geology, no assurance can be given.

Cleanup costs recognized to date total approximately  $438,000,  of which amount
$354,000  has  been   reimbursed  from  the  South  Dakota   Petroleum   Release
Compensation  Fund. To date, no penalties,  claims or actions have been taken or
threatened against the Company because of this oil spill.

<PAGE>

PCBs
----

Under the federal Toxic Substances  Control Act, the EPA has issued  regulations
that control the use and disposal of polychlorinated  biphenyls (PCBs). PCBs had
been widely used as insulating fluids in many electric utility  transformers and
capacitors  manufactured  before the Toxic Substances Control Act prohibited any
further  manufacture  of such PCB  equipment.  Black  Hills  Power  removes  and
disposes  of  PCB-contaminated  equipment  in  compliance  with  law  as  it  is
discovered.

Several  years ago,  Black  Hills  Power  began a testing  program  of  possible
PCB-contaminated transformers, and in 1997 completed testing of all transformers
and  capacitators  which  are  not  located  in  Black  Hills  Power's  electric
substations. Black Hills Power has not completed the testing of sealed potential
transformers and bushings located in its electric  substations as the testing of
such equipment will require the  destruction of the equipment.  While release of
PCB-contaminated  fluid,  if present,  from such  equipment  is unlikely and the
volume of fluid in such equipment is generally less than one gallon, any release
of such fluid would be confined to Black Hills Power's substation site.

Release of PCB-contaminated fluids, especially any involving a fire or a release
into a waterway, could result in substantial cleanup costs. As the result of the
September 18, 1996 inspection by the  Environmental  Protection  Agency of Black
Hills Power's Deadwood Avenue facility located in Rapid City, South Dakota,  the
United  States  Environmental  Protection  Agency  Region VIII filed a complaint
dated September 30, 1998, alleging three counts of violations of PCB regulations
and  proposing  a civil  penalty of  $13,600.  Black Hills Power filed an answer
contesting the complaint.  Based on Black Hills' answer and subsequent facts and
information,  the EPA withdrew  their  complaint  and an order was entered by an
administrative law judge dismissing the complaint on December 1, 1998.

Electromagnetic Fields
----------------------

A number of studies have examined the possibility of adverse health effects such
as  cancer  from  electromagnetic  fields  (EMF)  which are  caused by  electric
transmission   and   distribution   facilities.   Certain  states  have  enacted
regulations to limit the strength of magnetic fields at the edge of transmission
line  rights-of-way.  None of the  jurisdictions  in  which  Black  Hills  Power
operates  has  adopted  formal  rules or  programs  with  respect  to EMF or EMF
considerations in the siting of electric  facilities.  Black Hills Power expects
that  public  concerns  will  make it more  difficult  and  costly  to site  and
construct new power lines and substations in the future. It is uncertain whether
Black Hills  Power's  operations  may be  adversely  affected in other ways as a
result of EMF  concerns.  Black Hills Power is  designing  all new  transmission
lines under EMF standards  adopted by the State of Florida so as to minimize the
EMF effect.  The Company is unable to predict the future  costs to the  electric
utility  industry,  including  the Company,  if a  determination  is made in the
future,  either based on facts or  perception,  that EMF causes  adverse  health
effects.

The  Company  makes  ongoing  efforts  to  comply  with new as well as  existing
environmental  laws and  regulations  to which it is  subject.  It is  unable to
estimate the ultimate effect of existing and future  environmental  requirements
upon its operations.

                                    EMPLOYEES

At December 31, 1998,  the number of employees of the Company  (including  Black
Hills Power), Wyodak Resources,  Black Hills Exploration and Production,  energy
marketing  companies and communication  companies,  were 291, 44, 32, 60 and 27,
respectively, for a total of 454 employees.

Approximately  48 percent of the  employees  of Black Hills Power are covered by
union contracts with the International Brotherhood of Electrical Workers. In the
Company's opinion employee relations are satisfactory.

<PAGE>

--------------------------------------------------------------------------------

ITEM 2.   PROPERTIES

                               UTILITY PROPERTIES

The following table provides information on the generating plants of Black Hills
Power. During 1998, 98 percent of the fuel used in electric generation, measured
in Btus (British thermal units), was coal. Generating Units

                                                          Name Plate
                                             Year of        Rating     Principal
                                           Installation  (Kilowatts)     Fuel
                                           ------------  -----------     ----
    Osage Plant - Osage, Wyoming            1948-1952       34,500       Coal
    Ben French Station-Rapid City, South       1960         25,000       Coal
     Dakota
                                               1965         10,000       Oil
                                           1977-1979(a)    100,000    Oil or gas
    Neil Simpson Station - Gillette,           1969         21,760       Coal
     Wyoming
                                               1995(b)      88,900       Coal
    Wyodak Plant - Gillette, Wyoming           1978(c)      72,400       Coal
                                                           -------           
     Total                                                 352,560
                                                           =======

(a)  These combustion turbines are those referenced by ITEM 1. BUSINESS ELECTRIC
     POWER SUPPLY - Pacific Power's Reserve Capacity Integration
     Agreement.

(b)  NS #2 was placed into  commercial  operation  in August  1995.  The plant's
     total production may, at times, exceed its name plate rating by 11 MWs.

(c)  Black  Hills  Power's  20  percent  interest.  See  Note  6  of  "NOTES  TO
     CONSOLIDATED FINANCIAL STATEMENTS".

Black  Hills  Power  owns  transmission  lines and  distribution  systems in and
adjoining the communities served consisting of 447 miles of 230 kV, 527 miles of
69 kV, 8 miles of 47 kV and numerous  distribution lines of less voltage.  Black
Hills  Power  owns a  service  center in Rapid  City,  several  district  office
buildings at various  locations  within its service area and an eight-story home
office  building at Rapid City,  South  Dakota,  housing its home office on four
floors, with the balance of the building rented to others.

--------------------------------------------------------------------------------

                   ENERGY EXTRACTION AND PRODUCTION PROPERTIES

Coal Mining Properties
----------------------

Wyodak  Resources is engaged in mining and processing  sub-bituminous  coal near
Gillette  in  Campbell  County,  Wyoming,  and  owns or has user  rights  in the
necessary  mining,  processing  and  delivery  equipment  to  fulfill  its sales
contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal are
based upon four federal  leases and one state lease.  The estimated  recoverable
coal from the leases as of  December  31,  1998 is  280,895,000  tons,  of which
22,012,000  tons are committed to be sold to the Wyodak Plant and  approximately
25,125,000 tons to Black Hills Power's other plants.

Each federal lease grants Wyodak  Resources the right to mine all of the coal in
the land  described  therein,  but the government has the right at the end of 20
years from the date of the lease to readjust  royalty  payments  and other terms
and conditions.  All of the federal leases provide for a royalty of 12.5 percent
of the selling price of the coal.  The state lease  provides for a royalty to be
determined every five years. Currently, the royalty on the state lease, approved
in 1998,  is 9% of the selling  price of the coal.  Each federal lease and state
lease  requires  diligent  development  to produce  at least one  percent of all
recoverable  reserves  within either 10 years from the  respective  dates of the
1983 leases or 10 years from the date of adjustment  of the other  leases.  Each
lease  further  requires a  continuing  obligation  to mine,  thereafter,  at an
average annual rate of at least one percent of the recoverable reserves.  All of
the federal leases and the state lease  constitute one logical mining unit which
is treated as one lease for the purpose of determining  diligent development and
continuing operation requirements.  All coal is to be mined within 40 years from
December 31,  1991,  the date of the logical  mining  unit.  Even if federal and
state coal leases are not mined out in 40 years,  the federal  coal is likely to
be available for further  lease after the 40 years.  Wyodak  Resources'  current
coal  agreements  require  production  which should be sufficient to satisfy the
diligent development and continual operation  requirements of present law absent
any unexpected  event.  Wyodak  Resources will require  additional coal sales in
order to mine all of its state and federal coal within the 40 year requirement.

<PAGE>

The law,  which  requires  that an owner of land that is  primarily  devoted  to
agriculture  must  approve a  reclamation  plan before the state will  approve a
permit  for  open  pit  mining,  affects  approximately  3,100,000  tons  of the
recoverable coal. Wyodak Resources has excluded these tons of coal from its mine
plan and will not mine such coal until a surface  consent has been negotiated or
the right to mine has been settled by litigation.

In 1996,  Wyodak Resources  purchased the Clovis Point Mine properties from Kerr
McGee Coal Corporation.  Acquisition of the property increased Wyodak Resources'
1996 recoverable reserves to approximately 288 million tons and included a train
loadout  facility,  maintenance  and processing  facilities and a developed open
pit. (See ITEM 7.  MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL  CONDITION
AND RESULTS OF  OPERATIONS - LIQUIDITY AND CAPITAL  RESOURCES -  Acquisition  of
Clovis Point Mine Properties.)

Oil and Natural Gas Properties
------------------------------

Black Hills  Exploration  and  Production  operates 297 wells as of December 31,
1998.  The  majority of these wells are in the Finn  Shurley  Field,  located in
Weston and Niobrara  Counties,  Wyoming.  Black Hills Exploration and Production
does not  operate,  but owns a  working  interest  in 275  producing  properties
located in the western and southern United States.  Black Hills  Exploration and
Production  also owns a 44.7  percent  non-operating  interest  in a natural gas
processing plant also located at the Finn Shurley Field.

Black  Hills  Exploration  and  Production  participated  in the  drilling of 43
exploratory  and  development   wells  in  1998.  Black  Hills  Exploration  and
Production's  average  working  interest in such wells was 15 percent,  or 6 net
wells.  A  development  well  is a well  drilled  within  the  presently  proved
productive  area  of an oil  and  gas  reservoir,  as  indicated  by  reasonable
interpretation  of available  data,  with the  objective of  completing  in that
reservoir.  An  exploratory  well is a well  drilled in search of a new,  as yet
undiscovered  oil or gas  reservoir  or to greatly  extend the known limits of a
previously  discovered  reservoir.  Twenty-three  out of the 43 wells drilled in
1998 were completed as producing wells for an overall  drilling  success rate of
53 percent.

See the table in Note 10 of "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS" for
Black  Hills  Exploration  and  Production's   estimated  quantities  of  proved
developed  and  undeveloped  oil and natural gas  reserves at December 31, 1998,
1997 and 1996,  and a  reconciliation  of the changes  between these dates using
constant product prices for the respective years.

ITEM 3.   LEGAL PROCEEDINGS

Transmission Rates - FERC Proceedings
-------------------------------------

The  FERC   approved  a  settlement  in  Black  Hills'  Order  888  open  access
transmission  tariff  filing.  This  settlement  allows  Black  Hills to use the
revenues received under the long-term transmission agreement between the Company
and the Cooperatives which terminates on December 31, 2020 (SEE ITEM 1. BUSINESS
-ELECTRIC SERVICE TERRITORY AND SALES-Transmission Service Sales) as being equal
to the  cost  of  providing  service  to  the  Cooperatives.  The  Cooperatives'
transmission  loads are not considered when calculating Black Hills' open access
transmission  tariff rates;  and as such, the  Cooperatives are paying less than
their fully allocated cost for use of the transmission  system.  But as a result
of allowing the revenue credit  methodology,  the open access transmission rates
still allow Black Hills to earn a just and reasonable  rate on its  transmission
facilities.  The settlement with the FERC is consistent with past actions of the
SDPUC and WPSC,  which  similarly  have  allowed  Black Hills to use the revenue
credit methodology in determining bundled rates for retail customers.

<PAGE>

In the  settlement,  Black  Hills  has  agreed  to  file  for  new  open  access
transmission  tariff rates in the event that: (1) either the South Dakota or the
Wyoming   legislatures   adopt  retail  access  which  would  allow  alternative
electricity  suppliers  to have access to  existing  franchised  retail  service
territories;  (2) an entity  other than Black  Hills  Power or the  Cooperatives
establishes  generation tied to a Cooperative's  transmission line as identified
in the 1986 Black Hills Power-Basin Electric Transmission  Agreement for service
to that entity's existing retail customers within the joint  transmission  area;
(3) an AC/DC/AC tie is established near Rapid City, South Dakota, to connect the
western electric  transmission and eastern  electric  transmission  grids of the
United  States;  or (4) the FERC revises the rates Black Hills Power charges the
Cooperatives.  Finally,  to the extent that a transmission  customer (other than
Black Hills Power or the Cooperatives)  arranges for transmission service on the
Cooperatives'  transmission  facilities as defined in the 1986 Agreement for the
purposes of serving the  transmission  customer's  retail  customers  within the
joint transmission area as defined within the 1986 Agreement,  Black Hills Power
shall provide a credit,  not to exceed its tariff rate,  against their rates for
transmission service it charges to such transmission customer for its use of the
Cooperatives'  transmission  facilities  to serve  the  transmission  customer's
retail customers within the joint transmission area.

Because Order 888 now gives the  cooperatives  the full use of the  transmission
system, Black Hills Power had filed a complaint against the Cooperatives. In its
complaint, Black Hills Power had requested that the FERC modify the transmission
contract  between  Black  Hills  Power  and  the   Cooperatives,   so  that  the
Cooperatives  would be  obligated to pay a just and  reasonable  rate that would
fairly  allocate  the  capital  cost of the  transmission  system to reflect the
Cooperatives' use. Black Hills Power withdrew its complaint,  without prejudice,
against the Cooperatives.

Black Hills  Power does not  anticipate  any  material  use of its  transmission
system by third-parties  until such time that retail wheeling may be instituted.
It is uncertain at this date as to what extent the FERC or the state  regulatory
jurisdictions  will have  jurisdiction  over determining  retail wheeling rates.
(See Item 7.  MANAGEMENT'S  DISCUSSION  AND ANALYSIS OF FINANCIAL  CONDITION AND
RESULTS OF OPERATIONS - COMPETITION IN ELECTRIC UTILITY BUSINESS.)

Other Legal Proceedings
-----------------------

The Company and its  subsidiaries  are involved in minor routine  administrative
proceedings and litigation  incidental to the businesses,  none of which, in the
opinion  of  management,   are  expected  to  have  a  material  effect  on  the
consolidated financial statements of the Company. .

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of security  holders during the fourth quarter
of 1998.

<PAGE>

PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The  Company's  Common  Stock ($1 par  value)  is  traded on The New York  Stock
Exchange.  Quotations for the Common Stock are reported under the symbol BKH. At
year-end, the Company had 6,315 common shareholders of record. All 50 states and
the District of Columbia plus 11 foreign countries are represented.

The Company has  declared  Common Stock  dividends  payable in cash in each year
since its  incorporation  in 1941.  At its January  1999  meeting,  the Board of
Directors raised the quarterly  dividend to 26.0 cents per share,  equivalent to
an annual increase of 4.0 cents per share.  This regular  quarterly  dividend is
payable  March 1, 1999.  Dividend  payment  dates are normally  March 1, June 1,
September 1, and December 1.

Quarterly  dividends  paid and the high and low Common Stock prices for the last
two years  reflecting  the  3-for-2  Common  Stock  split in March  1998 were as
follows:

                                Year ended December 31, 1998
                              1st       2nd       3rd       4th
Dividends paid     
  per share                   $0.25     $0.25     $0.25     $0.25
Common stock
  prices
   High                       $25.56    $24.25    $26.88    $27.94
   Low                        $21.00    $20.69    $22.31    $24.13

                               Year ended December 31, 1998
                              1st       2nd       3rd       4th
Dividends paid
  per share                   $0.237    $0.237    $0.237    $0.237
Common stock
  prices
   High                       $19.25    $19.67    $19.75    $24.29
   Low                        $17.50    $17.58    $17.92    $19.50


--------------------------------------------------------------------------------
ITEM 6.  SELECTED FINANCIAL DATA

The following data was derived from the Company's audited financial statements.

<TABLE>
<CAPTION>

Years ended December 31            1998        1997        1996       1995        1994
-----------------------            ----        ----        ----       ----        ----
                                         (in thousands, except per share amounts)

<S>                              <C>         <C>         <C>        <C>        <C>     
Operating revenues               $679,254    $313,662    $162,588   $149,817   $145,402
Net income                         25,808*     32,359      30,252     25,590     23,805
Per share of common stock:
   Earnings - basic and diluted      1.19*       1.49        1.40      1.19        1.11
   Dividends paid                    1.00        0.95        0.92      0.89        0.88
Total assets                      559,417     508,741     467,354    448,830    436,877
Long-term debt                    162,030     163,360     164,691    166,069    128,925

</TABLE>

Quarterly  financial data for the years  indicated (are summarized in thousands,
except per share amounts) as follows:

<TABLE>
<CAPTION>
                                                1st         2nd        3rd         4th
                                                ---         ---        ---         ---
<S>                                          <C>         <C>         <C>        <C>
Year ended December 31, 1998
Operating revenues                           $153,837    $161,334    $170,158   $193,925
Operating income                               14,875      13,915      17,603      2,840*
Net income                                      8,544       7,497       9,616        151*
Earnings per share                                .39         .35         .45        .01*

Year Ended December 31, 1997
Operating revenues                            $43,879     $40,259     $98,182   $131,342
Operating income                               15,629      12,742      15,573     14,495
Net income                                      8,586       6,762       8,644      8,367
Earnings per share                               0.39        0.31         0.40      0.39

</TABLE>

*Includes $8.8 million, or 41 cents per share, non-cash writedown of certain oil
and gas properties.

<PAGE>

ITEM 7.  MANAGEMENT'S  DISCUSSION  AND ANALYSIS OF FINANCIAL  CONDITION AND
         RESULTS OF OPERATIONS

                         LIQUIDITY AND CAPITAL RESOURCES

The Company  generated cash from operations  sufficient to meet operating needs,
pay  dividends  on common stock and finance its capital  requirements.  Property
additions  from  1996  through  1998  were  primarily  for  the  replacement  of
equipment,  modernization of facilities, oil and gas investment and expansion of
energy marketing operations. The primary capital requirements of the Company for
the past three years were as follows:

                                           1998         1997          1996
                                           ----         ----          ----
                                                   (in thousands)
      Property additions                 $25,265      $21,087       $24,388
      Common stock dividends              21,737       20,540        19,930
      Energy marketing assets              1,960        7,232             -
      Maturities/redemptions of
      long-term debt                      1,331        1,534         1,405
                                          -----        -----         -----
                                         $50,293      $50,393       $45,723
                                         =======      =======       =======

Capital requirements for projected construction,  capital improvements,  oil and
gas investments,  communications  network construction and corporate development
activities for the next three years are estimated to be as follows:

                                          1999          2000          2001
                                          ----          ----          ----
                                                   (in thousands)
      Electric:
         Production                      $3,316      $  1,291        $1,415
         Transmission                     3,956         2,479         2,807
         Distribution                     8,731         7,937         8,008
         General                          1,804         2,414         1,749
                                          -----         -----         -----
                                         17,807        14,121        13,979
      Energy Extraction and
      Production:
         Coal mining                      4,245         5,211         1,233
         Oil and gas                      9,700        10,000        10,000
                                          -----        ------        ------
                                         13,945        15,211        11,233
      Communications                     38,556         5,389         6,644
      Corporate development              20,000        10,000        10,000
                                         ------        ------        ------
                                        $90,308       $44,721       $41,856
                                        =======       =======       =======

-------------------------------------------------------------------------------

The electric and coal mining  operations'  forecasted  expenditures  include the
replacement   of  equipment  and   modernization   of   facilities.   Forecasted
expenditures for the oil and gas operations are dependent upon future cash flows
and  include  an  active  development  and  exploratory   drilling  program  and
acquisition  of  existing  producing   properties.   Forecasted   investment  in
communications infrastructure represents the communications network build-out in
Rapid City and the Northern  Black  Hills.  Forecasted  investment  in corporate
development  activities  are dependent on market  conditions at the time and the
Company's  ability  to  identify  opportunities  consistent  with its  corporate
strategy.  Black Hills Generation,  Inc.  (formerly WYGEN,  Inc.) and the energy
marketing  companies do not have any forecasted  capital  expenditures  that are
significant.  The energy marketing companies are generally not capital intensive
businesses.  Black Hills Generation was formed as an exempt wholesale  generator
and will not incur  substantial  costs  until and  unless  long-term  power sale
contracts  are obtained.  If long term sales  agreements  are reached  requiring
capital expenditures, such expenditures will be evaluated at that time.

<PAGE>

Electric operations is the only segment of the Company's business with long-term
debt.  Long-term  debt  sinking  fund  requirements  are:  $1,330,000  in  1999,
$1,330,000 in 2000,  and  $3,029,000 in 2001.  Under its mining  permit,  Wyodak
Resources is required to reclaim all land where it has mined coal reserves.  The
cost of  reclaiming  the  land  is  accrued  as the  coal is  mined.  While  the
reclamation  process takes place on a continual  basis,  much of the reclamation
occurs over an extended period after the area is mined.  Approximately  $700,000
is charged to operations as  reclamation  expense  annually.  As of December 31,
1998, accrued  reclamation costs were  approximately  $17,000,000 which includes
$7,957,000  for the 1996 Clovis  Point Mine  Acquisition.  (See  Acquisition  of
Clovis Point Mine Properties following this section.)

The Company has a Dividend  Reinvestment  and Stock Purchase  Plan,  under which
shareholders  may purchase  additional  shares of Common Stock through  dividend
reinvestment  or optional  cash  payments  at 100 percent of the recent  average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market.  The Company used the open market purchase option for
all of 1998, 1997 and 1996.

The debt component of the Company's  capital  structure at December 31, 1998 and
1997, was 44 percent.  The Company does not anticipate any additional  long-term
debt  financings  in the next  three  years and would  expect  the debt ratio to
decrease to  approximately  40 percent over the next 3 to 5 year period unless a
Black Hills Generation  project is constructed or significant  other development
opportunities   are   consummated.   The  Company   anticipates   financing  the
communications  construction  through  operating cash flow and short-term  debt.
(See ITEM 7.  MANAGEMENT'S  DISCUSSION  AND ANALYSIS OF FINANCIAL  CONDITION AND
RESULTS OF  OPERATIONS-RESULTS  OF  OPERATIONS-Independent  Power Business;  and
BUSINESS OUTLOOK STATEMENTS - Future Corporate Development Activities.)

The Company had $12,000,000 of unsecured  short-term lines of credit at December
31, 1998 and 1997, which provide for interim  borrowings and the opportunity for
timing of permanent  financing.  There was  $3,850,000  outstanding  under these
lines of credit as of  December  31,  1998.  There are no  compensating  balance
requirements associated with these lines of credit.

In addition to the above lines of credit,  Black Hills  Energy  Resources  has a
$65,000,000  uncommitted  line of credit with a national bank  ($50,000,000  for
letters of credit and $15,000,000 for working capital) to provide credit support
for  purchases  and sales of natural  gas and crude oil.  The  Company  does not
provide  credit  support for this  agreement.  At December 31, 1998,  there were
outstanding letters of credit totaling approximately $28,000,000,  which reduced
the available credit to $37,000,000.

In addition to the above lines of credit,  Wyodak  Resources  has  guaranteed  a
$15,000,000  line of credit for Enserco to use to  guarantee  letters of credit.
Enserco pays a 0.125  percent  facility fee on this line of credit.  At December
31, 1998, there were no balances outstanding on this line of credit.

In the past, the Company has relied upon internally generated funds, issuance of
short and  long-term  debt and sales of common stock to finance its  activities.
The Company  expects an  appropriate  mix of  financing  options will be used to
finance future activities.

Credit  ratings for the  Company's  First  Mortgage  Bonds are at an A1 level at
Moody's Investors Service, Inc. and at an A+ at Standard & Poor's. These ratings
reflect the respective agencies' opinions of the credit quality of the Company's
first mortgage bonds.

Acquisition of Clovis Point Mine Properties
-------------------------------------------

In September 1996,  Wyodak Resources  purchased the Clovis Point Mine properties
from Kerr-McGee Coal  Corporation.  The Clovis Point Mine properties are located
adjacent to Wyodak Resource's current reserves in Campbell County,  Wyoming, and
consist of State of Wyoming and federal leased coal reserves.

<PAGE>

Acquisition of the property  increased the Company's 1996  recoverable  reserves
from 170 million  tons to  approximately  288 million  tons and included a train
loadout  facility,  maintenance  and processing  facilities and a developed open
pit. (See NOTES TO CONSOLIDATED  FINANCIAL STATEMENTS - Note 7 - Commitments and
Contingent Liabilities - Acquisition of Clovis Point Mine Properties.)

                             MARKET RISK DISCLOSURES

Commodity Risk
--------------

The Company is exposed to market risk stemming from changes in commodity prices.
These changes could cause fluctuations in the Company's earnings and cash flows.
In the normal course of business,  the Company  actively manages its exposure to
these market  risks by entering  into various  hedging  transactions,  which are
authorized  under its policies  that place clear  controls on these  activities.
Hedging  transactions  involve  the use of a  variety  of  derivative  financial
instruments.

The Company has adopted a Risk Management  Policies and Procedures,  approved by
the Board of Directors,  which  include,  but are not limited to, risk tolerance
levels relating to authorized derivative financial instruments, position limits,
authorization of transactions and credit exposure.

Trading Activities
------------------

The Company,  through its energy marketing  companies,  utilizes derivatives for
its energy marketing services.  These financial  instruments include fixed price
swap agreements, variable price swap agreements,  exchange-traded energy futures
contracts,  and  swaps and  collars  traded  in the  over-the-counter  financial
markets.

The majority of derivatives  have been  designated for hedging  purposes and are
not held for speculative purposes.  For trading transactions that do not qualify
for hedge accounting, the Company utilizes marked-to-market accounting, and such
financial  instruments  are recorded at fair value with realized and  unrealized
gains  (losses)  recorded as a component of income.  The  quantities and maximum
terms of derivative financial  instruments held for trading purposes at December
31, 1998 and 1997 are not  significant  to the Company's  financial  position or
results of operations.

Non-trading activities
----------------------

To  reduce  risk from  fluctuations  in the price of oil and  natural  gas,  the
Company enters into futures and swap transactions.  The transactions are used to
hedge  price  risk  from  sales  of the  Company's  crude  oil and  natural  gas
production,  and from fixed price sales from the Company's  retail gas marketing
activities. For such transactions,  the Company utilizes hedge accounting.  (See
NOTES TO CONSOLIDATED  FINANCIAL  STATEMENTS - Note 1 - BUSINESS DESCRIPTION AND
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Price Risk Management Activities).

The notional  quantities and maximum terms of derivative  financial  instruments
held for non-trading activities at December 31, 1998 are presented below:

                               Volume       Max.
                               Purchased    Term      Fair Value
                               (MMBtu's)   (Years)  (in thousands)
                               ---------   -------  --------------
Natural gas futures
 contracts purchased          1,470,000      2         $(409)
Natural gas swap
 contracts purchased          7,989,096      3         $(2,601)
Natural gas swap
 contracts sold               1,473,000      1         $432

Because  these  contracts  are entered  into for hedging  purposes,  the Company
expects  that  the  gains/(losses)  will be  offset  by  gains  (losses)  on the
underlying  physical  transactions;  Such physical  transactions  are subject to
weather  trends,  transportation  and delivery  risks and other factors that the
Company  monitors on a regular basis.  The notional  amounts  detailed above are
intended  to  be  indicative  of  the  Company's   level  of  activity  in  such
derivatives.

At December 31, 1998, the Company did not have material crude oil derivatives in
its non-trading activities.  At December 31, 1997, the company had price collars
and fixed rate for  floating  rate price swaps to hedge crude oil price risk for
15,000  barrels of oil per month,  resulting in the  recognition  of $939,000 of
gains during 1998.  In  addition,  the Company had fixed rate for floating  rate
price swaps on 3.9 bcf of natural gas to hedge fixed price sales  commitments in
a similar quantity.

<PAGE>

Trading and Non-trading--General Policy
---------------------------------------

In addition to the risk  associated  with price  movements,  credit risk is also
inherent in the Company's risk management activities. Credit risk relates to the
risk of loss  resulting from non  performance  of  contractual  obligations by a
counterparty.  While the Company has not experienced  significant  losses due to
the credit risk associated with these arrangements,  the Company has off-balance
sheet risk to the extent that the  counterparties to these transactions may fail
to perform as required by the terms of each such contract.

Interest Rate Risk
------------------

The  Company's  exposure to market risk for  changes in interest  rates  relates
primarily  to  the  Company's   short-term   investments   and  long-term   debt
obligations.  The Company does not use derivative  financial  instruments in its
available for sale securities. As stated in its policy, the Company is averse to
principal  loss and ensures the safety and  preservation  of its  investments by
limiting default risk, market risk, and reinvestment risk. The Company mitigates
default risk by investing in high credit quality securities consisting primarily
of  tax-exempt  Federal,  state and local agency  obligations  and by constantly
monitoring  the  credit  rating of any  investment  issuer or  guarantor  and by
limiting the amount of exposure to any one issuer.  The portfolio  includes only
securities  with  active   secondary  or  resale  markets  to  ensure  portfolio
liquidity. All short-term investments mature, by policy, in three years or less.

The effect of a 100 basis  point  increase  in  interest  rates would not have a
material effect to the Company's  results of operations or financial  condition,
due to the short-term duration of the investment portfolio.

The Company has no cash flow  exposure  due to rate changes for  long-term  debt
obligations.  The  Company  primarily  enters into debt  obligations  to support
general corporate  purposes  including capital  expenditures and working capital
needs.
-------------------------------------------------------------------------------

The table below presents  principal (or notional)  amounts and related  weighted
average  interest  rates  by  year of  maturity  for  the  Company's  short-term
investments and long-term debt  obligations,  including  current  maturities (in
thousands). <TABLE> <CAPTION>
                                1999    2000     2001     2002     2003    Thereafter  Total
                                ----    ----     ----     ----     ----    ----------  -----
<S>                           <C>      <C>      <C>     <C>       <C>     <C>        <C>
Cash equivalents
   Fixed rate                 $14,764  $  --    $  --   $    --   $  --   $     --   $ 14,764
   Average interest rate        3.40%     --       --        --      --         --      3.40%
Available for sale securities
   Fixed rate                  11,834   9,006    1,835       --      --         --     22,675
   Average interest rate        4.18%   4.14%    4.26%       --      --         --      4.17%
Total investment securities    26,598   9,006    1,835       --      --         --     37,439
   Average interest rate         3.75    4.14    4.26%       --      --         --      3.87%

Long-term debt
   Fixed rate                   1,330   1,330    3,029   18,018   3,068    136,585    163,360
   Average interest rate        9.11%   9.11%    9.24%    6.96%   9.24%       8.2%       8.2%
</TABLE>


<PAGE>

                                 RATE REGULATION

Existing Rate Regulation 
------------------------ 

In 1995,  Black Hills Power and the South Dakota and Wyoming  regulatory  bodies
reached settlement relating to the inclusion of NS #2 into rate base.

The  South  Dakota  and  Wyoming  settlements  further  provide  that  unless an
extraordinary event occurs,  Black Hills Power will not file for any increase in
rates or invoke any fuel and purchased power automatic adjustment tariff to take
effect  during  a  freeze  period   ending   January  1,  2000.   The  specified
extraordinary events are: new governmental  impositions  increasing annual costs
in South Dakota above $1,000,000 or $325,000 in Wyoming,  forced outages of both
the  Wyodak  Plant and NS #2  projected  to  continue  at least 60 days in South
Dakota and three  months in Wyoming,  forced  outages  occurring to either plant
which are  continued  for a period of three months or projected to last at least
nine months and an increase in the  Consumer  Price Index at a monthly  rate for
six  consecutive  months  which  would  result in a 10  percent  or more  annual
inflation rate.

During  the  freeze  period,  Black  Hills  Power is  undertaking  the  risks of
machinery failure, load loss caused by either an economic downturn or changes in
regulation,  increased costs under existing power purchase  contracts over which
the Company has no control,  government interferences,  acts of nature and other
unexpected  events that could cause  material  losses of income or  increases in
costs of doing business.  However,  the settlements  anticipate that Black Hills
Power  will  retain  during  that  period of time  earnings  realized  from more
efficient operations,  sales from load growth, and off-system sales of power and
energy,  including the sale to MDU.  (See ITEM 7.  MANAGEMENT'S  DISCUSSION  AND
ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF  OPERATIONS - BUSINESS  OUTLOOK
STATEMENTS.)

Long-Term Contracts
-------------------

As a result of rate  negotiations,  Black  Hills  Power has been  successful  in
entering  into  long-term  contracts  with  most  of its  industrial  and  large
commercial  customers.  The all  requirements  electric  service  agreement with
Homestake Mining Company expires September 9, 2002, and the other contracts have
terms of five years that begin to expire in 2000. However, each of the contracts
provides options for the customer to keep the term of the contract  extended for
at least three years,  with the proviso that if the customer  allows the term to
reduce to less than two years, Black Hills Power may invoke a planning surcharge
on that customer. If deregulation in retail electric sales occurs, the contracts
give Black Hills Power  notice to allow for planning to make the  transition  to
full competition,  guard against stranded investment and protect other customers
from rate impacts of unexpected load loss. However, management cannot predict if
the notice  period would be  sufficient  to fully adapt for  competition.  These
industrial and large  commercial  customers,  together with the wholesale  power
sales  agreements to the City of Gillette and MDU,  result in  approximately  40
percent of Black Hills Power's firm load under these term contracts.

Business Development Rates
--------------------------

Both the SDPUC and the WPSC  authorized  Black  Hills Power to  negotiate  rates
above its marginal  costs but below full cost with any  customer  with a load of
over 250 KVA if that customer has a legal choice of its electric supplier. Black
Hills  Power  expects  to utilize  this  tariff in those  instances  where a new
business  would have a choice of  locating in the  service  territory  of either
Black  Hills Power or a  competing  REC or enticing a new  business to locate or
relocate  in Black  Hills  Power's  service  territory.  Black  Hills  Power has
available  resources  to compete for new large load  customers  through this new
tariff.

                    COMPETITION IN ELECTRIC UTILITY BUSINESS

Current Status of Competition for Service at Retail
---------------------------------------------------

In addition to Black Hills Power, RECs and the federal  government  through WAPA
provide  electric  service in and around the  service  territory  of Black Hills
Power.  Black Hills Power's  transmission  system is  interconnected  to Pacific
Power's  transmission system near Gillette,  Wyoming,  and to WAPA's system near
Scottsbluff,  Nebraska.  Pacific Power  provides  electric  service at retail to
large  portions of Wyoming.  Black Hills Power and the RECs serve in territories
which are  protected  by state laws or  regulations  which  generally  give each
entity  the  exclusive  right  to  serve  retail  customers  in  its  respective
territory;  however,  these laws or regulations  are subject to change and there
are certain exceptions. In South Dakota, the SDPUC may allow a new customer with
a load of over 2,000  kilowatts  to choose to be served by a utility  other than
the utility in whose  territory  the new customer  locates.  In Wyoming,  public
utilities operate in service  territories  assigned by the WPSC, and a franchise
granted by the  municipality's  governing  body is  required  to serve  within a
municipality.  Black  Hills Power may apply for and obtain the right to serve in
another utility's  electric service territory if it is found to be in the public
interest to do so, but such applications are rarely granted.

<PAGE>

The  respective  service  territories  of Black  Hills  Power  and the RECs were
originally  assigned  based on where each was serving at the time of assignment.
Since the RECs were  serving  in rural  areas (the  purpose  for which they were
formed),  a large portion of the rural area  surrounding the  municipalities  in
which Black Hills Power serves constitutes REC service territory. Although Black
Hills  Power  has  traditionally   served  considerable   territory  outside  of
municipalities  and,  therefore,  has  been  assigned  a  large  amount  of such
territory,  the RECs have the largest  portion of such area and, if the laws are
not changed, will over a long period of time tend to receive a larger portion of
the growth of the population centers.

Every  municipality in Black Hills Power's service territory has the right, upon
meeting certain conditions, to acquire or construct a municipally owned electric
system and to serve customers within its city. As a wholesaler of electric power
and  energy,  such  municipality  would  have the  power to demand  and  receive
transmission access over Black Hills Power's transmission system consistent with
its open access transmission  tariff. The FERC has recognized the principle that
a city,  which  establishes  a municipal  electric  system and buys power from a
supplier other than its former electric  utility,  should  compensate the former
supplier  for any  stranded  costs  caused by the change in the power  supplier.
However,  the Company can give no  assurances  to what extent the stranded  cost
provisions  will be  administered  or how they would be  applied to Black  Hills
Power. Black Hills Power is not aware of any movement by any municipality in its
service  territory  which does not already  have a  municipally  owned  electric
system to establish one.

The primary competing fuel in Black Hills Power's territory is natural gas which
is available to approximately 80 percent of its customers.

Competition in Electric Generation
----------------------------------

The business of electric  generation is no longer  reserved  exclusively for the
traditional  public utility such as Black Hills Power.  The Energy Policy Act of
1992 exempted  independent  power producers  engaged  exclusively in the sale of
power at wholesale from the onerous  restrictions  of the Public Utility Holding
Company  Act.  The  Public  Utility  Regulatory  Policies  Act of  1978  (PURPA)
authorizes entities generating electricity from waste fuel and renewable fuel or
utilizing steam for both generation and other purposes to force a public utility
to purchase the energy at an avoided  cost.  These laws,  together with the FERC
mandating all public utilities under its jurisdiction to file tariffs  providing
transmission  access  for sales of energy at  wholesale,  have  caused  electric
generation and the marketing of electric energy at wholesale to become extremely
competitive. While independent power producers, other than qualifying facilities
under PURPA,  are regulated by the FERC, the FERC is allowing rates for the sale
of  generation  to be  determined  by the  market  rather  than by  costs if the
producer or  marketer  can  demonstrate  no market  power.  As a result of these
changes in the law and  regulations,  the traditional  public  utility,  such as
Black Hills Power, is more likely to purchase energy required for its franchised
service  territories  through competitive bidding and either not expand its rate
base  generating  capabilities  or engage in the  electric  generation  business
through independent power producers by selling to other utilities.  (See ITEM 7.
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS -RESULTS OF OPERATIONS - Independent Power Business.)

<PAGE>

Future  generation,  whether  constructed  by a public utility or an independent
power  producer,  is  likely  to be  justified  strictly  on  the  basis  of the
marketability  of the capacity  and energy from the new source in a  competitive
market.

Black Hills Power could face the competition of industrial and public  customers
constructing  self-generation  facilities using alternative fuels, such as waste
material,  natural  gas or oil.  To date,  Black  Hills  Power has not faced any
material competition from such sources and management does not believe that such
sources are cost  effective  and the  company  believes  its rate design  allows
flexibility in rates should  competition  become a threat, but no assurances can
be given that material competition from these sources will not occur.

Transmission Access
-------------------

In 1996,  the FERC adopted Order 888 that requires each public utility under its
jurisdiction to file open access  transmission  tariffs that provide rates which
are comparable to the same transmission  costs of the public utility to transmit
power over its system. The rates provide for various transmission services to be
provided for any competitor but apply to the  transmission of electric power for
wholesale  purposes only. FERC has  established  Black Hills Power's open access
transmission  tariffs (See ITEM 3. LEGAL PROCEEDINGS - Transmission Rates - FERC
Proceedings).  The regulations further require the public utility to keep posted
for public access,  on an electronic  bulletin  board,  all current  information
concerning the availability  and rates for these  transmission  services.  Black
Hills Power was granted an extension by FERC to delay establishing an electronic
bulletin board until WAPA,  which operates the control area in which Black Hills
Power is located,  establishes or participates in an electronic  bulletin board.
The public  utilities are further required by FERC to adopt standards of conduct
which require the functional  separation of those persons who operate and market
the  transmission  system from those persons who buy and sell power for the same
utility;  however,  the FERC  granted a waiver  to Black  Hills  Power  from the
requirement  to adopt the  standards  of conduct in view of Black Hills  Power's
small  transmission   system  and  lack  of  significant  market  control.   The
regulations  are  designed to attempt to eliminate  any market  advantage of the
utility owning transmission over others engaged in the sale of electric power at
wholesale.

The new FERC  regulations  requiring the filing of open access  tariffs does not
apply to the  nonjurisdictional  utilities  such as the RECs and publicly  owned
electric utilities.  However, these  nonjurisdictional  utilities are subject to
the law that allows the FERC to force them to provide transmission services upon
application,  and the  FERC  has  adopted  reciprocity  regulations  that  would
authorize  a   jurisdictional   utility  to  deny   transmission   access  to  a
nonjurisdictional utility which has denied access.

Black Hills Power currently  furnishes  transmission  service for competing RECs
through  contract.  As long as the states in which Black  Hills  Power  operates
continue to grant exclusive service territories, the federal government does not
preempt  this state  jurisdiction  and  municipalities  in Black  Hills  Power's
service territory do not establish  municipal electric systems,  the increase in
transmission   access  for  wholesale   purposes  through  Black  Hills  Power's
transmission system is not likely to have any material adverse effect upon Black
Hills  Power.  Such  open  access  may  have  a  beneficial  effect  by  opening
opportunities  for the Company to further the  marketing  of  coal-fired  energy
outside of its service territory.

Retail Wheeling
---------------

Legislative  proposals  requiring a public  utility to allow its  competitors to
utilize the utility's  electric  distribution  system to serve end-use customers
who are  located in service  areas  assigned to that  public  utility,  commonly
referred to as retail  wheeling,  are getting serious  consideration in Congress
and  in  many  states.  Since  the  duplication  of  electric  transmission  and
distribution systems would neither be efficient nor tolerable by the public, the
transmission and  distribution  portion of the business is likely to continue to
be regulated  with rates based on costs.  The Company cannot predict when and if
mandated retail wheeling will come to the areas where it now provides  exclusive
retail electric  service.  Major problems should be resolved first,  such as the
preservation  of reliable  service,  compensation  to a utility  for  investment
incurred  to fulfill  its duty to serve but  stranded  because  of  competition,
fairness of market pricing between large industrial users and small business and
residential  users and assurances  that all  utilities,  including the RECs, are
bound to operate under the same rules.

<PAGE>

The SDPUC and WPSC continue to monitor the potential impacts of electric utility
industry  restructuring and retail  competition in South Dakota and Wyoming.  At
this time, South Dakota does not have any legislative  activity regarding retail
wheeling. During the 1999 legislative session, the Wyoming State Senate rejected
a bill which would have required the WPSC to hold formal  hearings and provide a
report  regarding the effects of retail  wheeling in Wyoming.  Several  credible
studies,  including a study for the US Department of Energy, have indicated that
electric  rates for  residential  customers  in South  Dakota  and  Wyoming  may
increase  if there is  national  retail  competition.  The  Company is unable to
predict whether Congress or the states may in the future require electric retail
competition  and, if they do, whether the ground rules for  competition  will be
fair to all participants including its related impacts on customers rates.

Management is unable to predict the effect of full electric  retail  competition
on the Company's  earnings.  Management does anticipate that a transition period
of at least five years will be required to achieve a fully competitive  electric
energy retail market. During that five years, Black Hills Power will endeavor to
increase its earnings through  additional sales and cost management.  Based upon
the FERC's expressed positions concerning open access transmission  regulations,
electric utilities which will lose revenues due to competition should be allowed
recovery  of stranded  costs.  The market  price of  electric  energy in a fully
competitive  market is expected to be based upon a much wider  geographical area
than just Black Hills Power's service  territory.  Because energy  providers are
likely to seek the markets  where the highest  profit  margins can be  realized,
today's  rates  designed  to  serve   exclusive   service   territories  may  be
substantially  different for service to a fully competitive market.  Lower rates
today are partially caused by excess generation  capacity which allows providers
to sell energy above their marginal costs but below full costs.

However, the Company is unable to predict future markets and economic conditions
and government  actions or inaction that could have a materially  adverse affect
on Black Hills Power's ability to compete in a fully competitive  electric power
market  and  to  maintain  its  equity  return  on  investment.   (See  ITEM  7.
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS - BUSINESS OUTLOOK STATEMENTS.)

Regulatory Accounting
---------------------

Black Hills Power follows Statement of Financial Accounting Standards (SFAS) No.
71,  "Accounting  for the  Effects  of  Certain  Types of  Regulation,"  and its
financial statements reflect the effects of the different ratemaking  principles
followed by the various jurisdictions  regulating Black Hills Power. As a result
of Black Hills Power's recent regulatory  activity,  a 50-year  depreciable life
for NS #2 is used for financial  reporting  purposes.  If Black Hills Power were
not following SFAS 71, a 35 to 40 year life would  probably be more  appropriate
which would increase depreciation expense by approximately $600,000 per year. If
rate recovery of generation-related  costs becomes unlikely or uncertain, due to
competition or regulatory action, these accounting standards may no longer apply
to Black Hills  Power's  generation  operations.  In the event Black Hills Power
determines  that it no longer  meets the  criteria  for  following  SFAS 71, the
accounting  impact to the Company would be an  extraordinary  noncash  charge to
operations  of an amount that could be material.  Criteria that give rise to the
discontinuance  of SFAS 71 include  increasing  competition  that could restrict
Black Hills Power's ability to establish  prices to recover specific costs and a
significant  change in the  manner in which  rates  are set by  regulators  from
cost-based  regulation to another form of regulation.  The Company  periodically
reviews  these  criteria  to ensure  the  continuing  application  of SFAS 71 is
appropriate.

                              RESULTS OF OPERATIONS

Consolidated Results
--------------------

The  Company  reported  record  earnings  for 1998  (before a  special  non-cash
charge),  due to sales growth in electric operations and record coal and oil and
gas  production,   partially  offset  by  lower  oil  and  natural  gas  prices.
Consolidated net income for 1998 was $25,808,000 compared to $32,359,000 in 1997
and  $30,252,000 in 1996 or $1.19 per average common share in 1998,  compared to
$1.49 and $1.40 per averaged common share in 1997 and 1996,  respectively.  This
equates to a 12.5 percent return on year-end common equity in 1998, 15.8 percent
return on year-end common equity in 1997, and 15.7 percent in 1996.

<PAGE>

In 1998, the Company  recorded an $8.8 million  (net-of-tax)  charge to earnings
related to a write down of oil and natural gas  properties.  Absent this charge,
the Company's  earnings per average common share for 1998 would have been $1.60,
a 7 percent increase as compared to 1997, and a return on year-end common equity
of 16.1 percent.

Consolidated  revenue  and net  income  (loss)  provided  by the  four  business
segments as a percentage of the total were as follows:


                          1998     1997      1996 
                          ----     ----      ---- 
Revenue:
  Electric                19%      40%       73% 
  Energy  extraction 
   and production:  
   Coal mining             5       10        19 
   Oil and gas             2        4         8 
Energy Marketing          74       46         - 
                          --       --        --    
                         100%     100%      100%
                         ===      ===       === 

                         1998     1997      1996 
                         ----     ----      ---- 
Net Income (Loss):
  Electric                96%      68%       61%
   Energy extraction
    and production:
    Coal mining           37       28        32
    Oil and gas          (31)       7         7
  Energy marketing        (1)      (2)        -
  Communications
      and other           (1)      (1)        -
                          --       --        --  
                         100%     100%      100%
                         ===      ===       === 

Dividends  paid on common stock totaled $1.00 per share in 1998.  This reflected
increases  approved by the Board of  Directors  from $0.95 per share in 1997 and
$0.92 per share in 1996.  All dividends were paid out of current  earnings.  The
Company's  dividend  objective  is to  increase  the  dividend  at or above  the
electric  utility average and reduce the Company's payout ratio to the low 60's.
Management  believes this objective is attainable  through earnings growth.  The
Company's  three year dividend  growth rate was 4.0 percent and the payout ratio
for 1998 was 63 percent, excluding the effect of the special non-cash charge.

In January  1999 the Board of Directors  increased  the  quarterly  dividend 4.0
percent to 26 cents per share.  If this dividend is  maintained  during 1999, it
will be equivalent to $1.04 per share, an annual increase of 4 cents per share.

Electric Operations
-------------------

                   1998     1997     1996
                   ----     ----     ----
                       (in thousands)

Revenue          $129,236 $126,497 $118,718
Operating
  expenses         79,340   81,886   79,628
                 -------- -------- --------
Operating income $ 49,896 $ 44,611 $ 39,090
                 ======== ======== ========
Net income       $ 24,825 $ 22,106 $ 18,333
                 ======== ======== ========


Electric  revenue  increased  2.2  percent  in 1998  compared  to a 6.6  percent
increase in 1997 and a 9.1 percent  increase in 1996.  Firm  kilowatthour  sales
decreased  0.4 percent in 1998  compared to a 13 percent  increase in 1997 and a
3.9 percent increase in 1996 and have averaged an annual 5.5 percent growth rate
over the last three years.

The  increase  in  electric  revenue in 1998 was  primarily  due to a 60 percent
increase  in  non-firm  sales  and a 2  percent  increase  in  commercial  sales
partially  offset by 4 percent  decrease in  industrial  sales  primarily due to
Homestake's  restructuring.  Firm  kilowatthour  sales declined  slightly due to
Homestake but total kilowatthour sales increased 4 percent primarily due to a 33
percent increase in off-system sales.  Degree days, a measure of weather trends,
were 2 percent below 1997 and 4 percent below normal.

The  increase  in  electric  revenue  and  firm  kilowatthour  sales in 1997 was
primarily due to the additional load to serve MDU's energy  requirements for its
customers in the Sheridan,  Wyoming  area.  Partially  offsetting  the increase,
residential  sales declined 3 percent  primarily due to milder  weather.  Degree
days were 15 percent below 1996 and 2 percent below normal.

<PAGE>

The  increase in electric  revenue in 1996 was due to strong sales growth in all
sectors of the Company's electric business,  including the industrial sector and
the  inclusion  of NS #2 in the  Company's  rate base (See ITEM 7.  MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL  CONDITION AND RESULTS OF OPERATIONS - RATE
REGULATION).

Revenue  per  kilowatthour  sold was 5.4 cents in 1998  compared to 5.5 cents in
1997 and 5.8  cents  in 1996.  The  number  of  customers  in the  service  area
increased to 56,856 in 1998 from 56,269 in 1997 and 55,601 in 1996.  The revenue
per  kilowatthour  sold in 1998  reflects  the 33 percent  increase in wholesale
non-firm sales to 371,100  megawatthours.  The revenue per kilowatthour  sold in
1997 reflects the increased wholesale sales to MDU's Sheridan, Wyoming customers
and  279,600   megawatthours  of  wholesale  non-firm  sales.  The  revenue  per
kilowatthour sold in 1996 reflects the increase in electric rates and the strong
growth in the higher margin  sectors of Black Hills Power's  business  offset by
the impact of 249,100 megawatt hours of wholesale non-firm sales in 1996.

Operating  expenses  have  remained  fairly  stable  over the last three  years.
Operating  expenses  decreased in 1998,  primarily due to lower  purchased power
costs and  strong  operating  cost  management,  partially  offset by  increased
property  taxes and fuel  expense.  Purchased  power costs  declined  due to the
renegotiated  Pacific  Power Sales  Agreement  (SEE ITEM 1.  BUSINESS - ELECTRIC
POWER SUPPLY - Pacific Power's Power Sales Agreement). The increase in operating
expenses in 1997 are primarily due to the increased load  requirements  to serve
MDU's  Sheridan,  Wyoming energy needs.  The increase in operating  expenses and
depreciation  associated  in 1996 with the  commercial  operation  of NS #2 were
offset by a decrease in fuel and purchased power costs.

Depreciation  expense  decreased  9  percent  in 1997 as a  result  of the  1996
accelerated depreciation of the Kirk Power Plant.

Firm energy sales are forecasted to increase over the next 10 years at an annual
compound  growth  rate  of  approximately  1  percent  with  the  system  demand
forecasted to increase 2 percent. The Company currently has a winter peak of 344
MWs  established  in December 1998 and a summer peak of 348 MWs  established  in
July 1998.  These  forecasts are from studies  conducted by the Company with the
help of outside  consultants  whereby Black Hills Power's  service  territory is
examined and analyzed to estimate changes in the needs for electrical energy and
demand over a 20-year period. These forecasts are only estimates, and the actual
changes in electric sales may be substantially  different.  However, in the past
the forecasts tracked actual sales within a band of reasonableness over a period
of several  years.  Weather  deviations  can adversely  effect energy sales when
compared to forecasts based on normal weather.

Coal Mining Operations
----------------------

                       1998     1997     1996
                       ----     ----     ----
                            (in thousands)

Revenue              $31,413   $31,080  $31,315
Expenses              18,690    18,863   19,081
                      ------    ------   ------
Operating income     $12,723   $12,217  $12,234
                     =======   =======  =======
Net income           $ 9,585   $ 9,073  $ 9,934
                     =======   =======  =======

Revenue and operating expenses have been fairly stable over the last three years
reflecting stable production and long-term coal contracts.  Wyodak Resources had
record coal  production of 3,280,000  tons in 1998 compared to 3,251,000 tons in
1997 and 3,243,000 tons in 1996.

Non-operating  income was  $1,063,000 in 1998 and $1,066,000 in 1997 compared to
$2,725,000 in 1996.  Non-operating  income  includes  gains or losses on sale or
disposal  of property  and  equipment  and  interest  income  from  investments.
Non-operating  income in 1996  included a $700,000 gain realized on the disposal
of equipment and an increase in cash available for investment.

Wyodak  Resources  expects  relatively  stable  sales in 1999  absent  unplanned
outages at the Wyodak Plant or Black Hills Power's plants.

<PAGE>


Oil and Gas Operations
----------------------

                           1998     1997      1996
                           ----     ----      ----
                               (in thousands)

Revenue                   $12,562  $13,295  $12,555
Expenses                   11,356   10,388    9,574
                           ------   ------    -----
Operating income
   before non-cash 
   charge                   1,206    2,907    2,981
Ceiling test write down    13,546     -           -
                           ------   ------   ------              
Operating income
 (loss)                  $(12,340) $ 2,907  $ 2,981
                         ========  =======  =======
Net income (loss)        $ (7,976) $ 2,147  $ 2,198
                         ========  =======  =======

In 1998,  Western Production Company changed its name to Black Hills Exploration
and Production, Inc. to more closely identify it's activities with the Company.

Net income before the special  non-cash charge and assets related to oil and gas
operations  have been 7 percent or less of the  Company's  consolidated  amounts
over the last three years.

Black Hills  Exploration and  Production's  product sales and product prices for
the last three  years were as  follows:  1998 1997 1996  Barrels of oil  344,000
299,000  286,000  sold Mcf of natural  2,056,000  1,747,000  1,718,000  gas sold
Equivalent  barrels  687,000 590,000 572,000 of oil sold Price per barrel $12.19
$19.05 $21.09 of oil Price per mcf of natural gas $1.97 $2.42 $2.05

Revenue decreased 5.5 percent in 1998 primarily due to 36 percent and 19 percent
lower oil and natural gas prices,  respectively,  partially offset by 15 percent
and 18  percent  increases  in oil  and  natural  gas  sales,  respectively.  In
addition,  to mitigate the risk of declining product prices,  the company hedged
certain oil production in Wyoming (excluded from the product prices noted above)
and  recognized  $939,000 in hedging gain (See NOTES TO  CONSOLIDATED  FINANCIAL
STATEMENTS  - Note 7 -  Commitments  and  Contingent  Liabilities  - Price  Risk
Management Activities).

Black Hills  Exploration  and  Production's  production  expenses  increased 9.3
percent in 1998,  8.5  percent  in 1997,  and 1.1  percent  in 1996.  Production
expenses  increased in 1998 and 1997 due to  increased  depletion as a result of
increased  oil and gas  production  and lower  crude  oil  prices.  Black  Hills
Exploration and Production recognized $4,850,000,  $3,920,000, and $3,434,000 of
depletion expense in 1998, 1997, and 1996, respectively.  Low oil and gas prices
reduce the cash flow and value of the Company's oil and gas assets and cause the
Company to increase its depletion expense.

Black Hills  Exploration and Production  accounts for its oil and gas activities
using  the full  cost  method  of  accounting  (See  NOTES  TO THE  CONSOLIDATED
FINANCIAL  STATEMENTS - Note 1 - Business Description and Summary of Significant
Accounting Policies - Oil and Gas Operations).

In  December  1998,  Black  Hills   Exploration  and  Production   recognized  a
$13,546,000  pretax loss related to a write down of oil and gas properties.  The
write down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties.  Absent other
factors  impacting  depletion  expense,  the Company  expects  future  depletion
expense per unit of production to be reduced because of this write down.

Black Hills  Exploration  and  Production's  proved  reserves  and the  revenues
generated from  production  decline as production  occurs,  except to the extent
successful exploration,  development,  and production enhancement activities are
conducted or additional  proved reserves are acquired.  Black Hills  Exploration
and Production has been active in exploration  and  development  drilling during
the past three years.

Black Hills Exploration and Production's drilling results were as follows:

                    1998       1997       1996
                 ---------------------------------
                 Gross Net  Gross Net  Gross Net
Wells drilled     43   6.4   37   7.1   52   7.0
Producing         23   2.3   22   3.5   35   4.7
Success rate      53%        59%        67%


<PAGE>

In April 1998, Black Hills Exploration and Production acquired approximately 3.7
billion  cubic  feet of natural  gas in Wyoming  for  $1,836,000.  In 1998,  the
Company  also  acquired  88,000  barrels  of oil and 0.1  billion  cubic feet of
natural gas in the Finn Shurley Field for $404,000.

In 1997, Black Hills Exploration and Production acquired  approximately  121,000
barrels  of oil  and  0.2 bcf of  natural  gas in the  Finn  Shurley  Field  for
$455,000.

In 1997 and 1996,  Black Hills  Exploration and Production sold certain interest
in natural gas  properties for $165,000 and $380,000,  respectively.  Such sales
are not expected to materially impact future production.

Black  Hills  Exploration  and  Production  intends to  increase  its net proved
reserves by selectively  increasing its oil and gas  exploration and development
activities  and by  acquiring  producing  properties  primarily  with the use of
internally generated funds and short-term borrowings.

Black Hills Exploration and Production's  reserves are based on reports prepared
by Ralph E. Davis  Associates,  Inc.  Reserves were  determined  using  constant
product prices at the end of the  respective  years.  Estimates of  economically
recoverable  reserves and future net revenues are based on a number of variables
which may differ from actual results.  Black Hills  Exploration and Production's
unaudited   reserves,   principally  proved  developed  and  proved  undeveloped
properties,  were  estimated to be 2.4, 2.5, and 2.4 million  barrels of oil and
16.0,  9.1, and 11.0 billion  cubic feet of natural gas as of December 31, 1998,
1997 and 1996, respectively.  The increase in reserves at December 31, 1998, was
due to natural gas  acquisitions  and drilling  results  despite  lower  product
prices.  The  decrease in reserves at December 31, 1997 was due to lower oil and
gas prices and reductions in engineering  estimates of recoverable  reserves for
certain natural gas properties.

Independent Power Business
--------------------------

In  1998,  WYGEN,  Inc.  changed  its  name to  Black  Hills  Generation,  Inc.,
reflecting  its  alignment  with the Company and its stated  mission to build or
acquire electric  generating  assets.  Black Hills Generation was formed in 1994
for the sole purpose of engaging in the generating and selling of electric power
and energy at wholesale and has exempt wholesale  generator status under Section
32 of the  Public  Utility  Holding  Company  Act.  At  this  time  Black  Hills
Generation is proposing to build an 80 megawatt  coal-fired  electric generating
plant to be known as the WYGEN project  adjacent to NS #2. In 1996,  Black Hills
Generation  received a  prevention  of  significant  deterioration  air  quality
construction  permit from the DEQ. In addition,  Black Hills Generation  renewed
its prevention of significant  deterioration air quality construction permit for
the WYGEN  project with the DEQ in September  1998.  Construction  must commence
within one year of the renewal of the permit or Black Hills  Generation  will be
required to reapply. As an independent power project,  the air quality permit is
the only major permit required. Viable markets for the electric power and energy
from the WYGEN  project  will  depend  partially  upon the cost of  transmission
rights to deliver the electric power and energy to higher priced energy markets.
While  the  FERC's  open  access  transmission   regulations  should  make  such
transmission  legally  available,   physical  transmission  constraints  or  the
perception   of  such   constraints   may  require   Black  Hills   Generation's
participation in transmission  improvements  which,  together with  transmission
rates for access across transmission systems,  could make the WYGEN project less
economical.  The economics of delivering power over multiple-owned  transmission
systems will depend upon how  successful  the FERC is in bringing about regional
transmission systems operated independently of the interest of any one provider,
with mechanisms to pool costs and cause transmission  system  improvements to be
constructed, on a timely basis, with broad participation.

In addition to the WYGEN  project,  the Company is exploring  opportunities  for
participating  in the acquisition of existing or new independent  power projects
fueled by coal or natural gas and located at Wyodak  Resources' mine or at other
locations  in the United  States.  To date,  such  efforts  have not resulted in
successful bids for such projects.

<PAGE>

Energy Marketing Operations
---------------------------

                              1998      1997
                              ----      ----
Revenue                     $506,043  $142,790
Expenses                     506,002   143,615
                            --------  --------
Operating income            $     41  $   (825)
                            ========  ======== 
Net loss                    $   (346) $   (749)
                            ========  ======== 

The  substantial  increase  in  revenues  and  operating  expenses  and  related
increases in accounts  receivable and accounts payable balances is primarily due
to recording  twelve  months of operations  for Black Hills Energy  Resources in
1998.  Black Hills Energy  Resources was acquired in July 1997.  Enserco Energy,
Inc.'s revenues and operating  expenses were recorded using the equity method in
1997 and due to the acquisition of the shareholder  interests in 1998 (discussed
below),  include all 1998 revenues and operating  expenses and related increases
in accounts  receivable and accounts payable  balances.  Net income was adjusted
for the other shareholder interests prior to the reacquisition. Black Hills Coal
Network was formed in September  1998  (discussed  below) and reflects  activity
from the acquisition's effective date.

Energy marketing operations revenues and daily volumes by energy product for the
last two years are as follows:

                          1998      1997
                          ----      ----
                          (in thousands)  
Revenues:  
  Natural gas            375,934   95,980* 
  Crude oil              117,185   46,810* 
  Coal                    12,924*       - 
Daily Volumes:  
  Natural gas (mmbtus)   487,000   231,000*  
  Crude oil (barrels)     19,000    12,600* 
  Coal (tons)              4,400*        -

*Since the acquisition date.

The  marketing   operations  are  high  volume,   low  margin  businesses  whose
contribution to consolidated earnings has not been significant.

Within the context of this report, an energy marketing company is a company that
sells and buys natural gas, crude oil, coal, and electric power at market prices
and ordinarily does not participate in the production of energy.

Black Hills  Capital  Group,  Inc. was  incorporated  by the Company to hold the
Company's  equity and debt  investments  in Black Hills Energy  Resources,  Inc.
VariFuel,  Inc.,  Enserco  Energy,  Inc., and Black Hills Coal Network,  Inc. In
addition to the energy  marketing  companies,  Black Hills Capital Group will be
the primary vehicle for future corporate  development  activities outside of the
internal company specific activities.

Energy marketing operations expanded  considerably in 1998 in terms of products,
customers,  and volume.  In  September  Black Hills Coal Network  acquired  Coal
Network and Coal Niche, Mason, Ohio-based coal marketing companies with customer
and supplier  relationships  east of the Mississippi.  Enserco Energy, our Rocky
Mountain,  Northwest  and West Coast  regions'  natural gas  marketing  company,
reacquired  the shares not owned by the company and expanded its Rocky  Mountain
region  service  to  retail  customers  with  an  acquisition  of  Platte  River
Solutions' retail  operations.  Black Hills Energy Resources  expanded its crude
oil marketing operations with additional sales from its 1997 expansion in Tulsa,
Oklahoma and  Midland,  Texas,  and East Coast region  retail gas sales with the
opening of an Allentown, Pennsylvania office.

Cost of natural gas,  crude oil and coal sold  (included  in Fuel and  Purchased
Power in the  CONSOLIDATED  STATEMENTS OF INCOME) relating to the above revenues
totaled  $498,580,000 in 1998 and  $141,726,000 in 1997. The increase in cost of
sales is primarily due to increased volumes as described in the revenue increase
above.

In 1998, the energy marketing  companies  incurred a net loss of $346,000 due to
mild  weather  conditions  in  certain  markets  and  additional  administrative
expenses incurred to expand its operations.

In 1997,  the  energy  marketing  companies  incurred  a net loss of  $(749,000)
primarily  due to  mild  weather  conditions  in its  target  markets,  start-up
expenses and additional  administrative  expenses to expand its energy marketing
operations.

<PAGE>

In July  1997,  Black  Hills  Capital  Group  acquired  the assets and hired the
operational  management  of Jomax  Partners,  L.P. as successor  and survivor of
Wickford Energy  Marketing,  L.C. and Wickford Energy  Marketing Canada Company.
Black Hills Energy  Resources,  Inc., is headquartered in Houston,  Texas with a
natural gas sales office in Calgary, Alberta, Canada and crude oil sales offices
in Tulsa,  Oklahoma,  and  Midland,  Texas.  Black Hills  Energy  Resources is a
"niche"  wholesale natural gas and crude oil marketing company with expertise in
Gulf Coast and Canadian supply,  targeting natural gas markets in the East Coast
and Midwest and crude oil markets primarily in the Southwest.

Black Hills Energy Resources has a $65,000,000 uncommitted line of credit with a
national bank  ($50,000,000  for letters of credit and  $15,000,000  for working
capital) to provide  credit  support for  purchases and sales of natural gas and
crude oil. The Company does not provide credit support for this agreement.

In November 1997, Black Hills Capital Group,  Inc. acquired the assets and hired
the  operational  management  of VariFuel,  Inc.  (VariFuel).  VariFuel  targets
commercial  and  industrial  natural  gas  customers  located  primarily  in the
Chicago,  Illinois and  northern  Indiana  area.  VariFuel is  headquartered  in
Houston, Texas with a sales office in Chicago, Illinois.

In 1996, Wyodak Resources,  with the participation of three individuals,  formed
an energy  marketing  startup  company  under the name of Enserco  Energy,  Inc.
(Enserco), headquartered in Lakewood, Colorado. Wyodak Resources also acquired a
convertible debenture from Enserco.

To provide Enserco with the financial backing to participate in the purchase and
sale of natural gas and electric power, Wyodak Resources has agreed to guarantee
up to  $15,000,000  of  letters  of credit  to be  issued by banks to  guarantee
purchases and sales of natural gas.

Enserco has acquired the approval from the FERC of a tariff which allows Enserco
to sell  electric  power at market  prices.  With the  reacquisition  of shares,
Enserco's FERC approval to market electric power needs  recertification of FERC.
The company has not  actively  pursued the  electricity  market to date.  Should
wholesale electricity market conditions  stabilize,  the company will review its
options at that time. Enserco is also qualified to purchase and sell natural gas
at market prices.

Although the energy marketing business is highly  competitive,  management is of
the opinion that due to the increasing competition in the energy business, it is
essential  for many  reasons to be active  with the energy  marketing  business,
including the  knowledge the Company gains in the marketing of energy,  which is
required  for the  Company to  effectively  compete in all aspects of its energy
business.

The  energy   marketing   companies   generate  large  amounts  of  revenue  and
corresponding expense related to buying and selling energy products.  Associated
with the purchase and sale of energy products,  the energy  marketing  companies
use  derivatives   (exchange  traded  and   over-the-counter   energy  financial
instruments)  to manage  risk  associated  with the buying and selling of energy
products whose prices can be extremely  volatile.  The use of derivatives  helps
mitigate risk in the trading of energy products but does not eliminate the risk.
Black Hills Capital Group and the energy  marketing  companies have adopted risk
management  policies  and  established  risk  management  committees  to further
mitigate risk  associated  with the sale and purchase of energy  products.  Some
purchasers  and  sellers  with  whom the  energy  marketing  companies  transact
business  require the  utilization of letters of credit to assure the underlying
performance of the  obligations  between the parties.  The failure of a party to
perform  may  result  in a  significant  risk of loss  to the  energy  marketing
companies  and  corresponding  loss  to  Wyodak  Resources  as it  concerns  the
outstanding letters of credit to Enserco.

<PAGE>

Communication and Technology Operations
---------------------------------------

In September 1998,  Black Hills Capital Group formed Black Hills FiberCom,  Inc.
to provide  facilities-based  communication  services  for Rapid  City,  and the
Northern Black Hills of South Dakota .

The newly formed  company is expected to invest more than  $50,000,000  over the
next three years in  state-of-the-art  technology that will offer local and long
distance telephone service,  expanded cable television service, Internet access,
and high-speed data and video services. Construction began in the fourth quarter
of 1998 and will take two to three years to build out the complete  fiber optics
system.  The Company  expects to begin serving  customers by the summer of 1999.
The company plans to market the communications  services to schools,  hospitals,
cities, economic development groups, and business and residential customers.

Black Hills  FiberCom is  partnering  with an  international  telecommunications
firm, GLA International,  of St. Louis,  Missouri, to build 200 mile fiber optic
backbone  and a  500-mile  hybrid  fiber  coaxial  network in Rapid City and the
Northern  Black Hills.  GLA was the firm that helped  develop the fiber networks
for Brooks  Fiber  Properties  which was recently  purchased by WorldCom.  Black
Hills FiberCom is expected to have positive cash flow from operating  activities
in its second  year of  operation  and assets  and net  income are  expected  to
comprise  less than 10 percent of  consolidated  assets and earnings  when fully
implemented.

DAKSOFT,  Inc. was  incorporated  by the Company in 1994,  to develop and market
internally  generated  computer software  associated with the Company's business
segments.  Additionally,  DAKSOFT has developed internet/intranet products which
are currently being used  internally and marketed to third parties.  In 1998 and
1997,  DAKSOFT  entered into  agreements for the customized  installation of its
Customer  Information System (CIS) product.  DAKSOFT's assets and net income are
expected to comprise less than 3 percent of consolidated assets and earnings.

Other Segments of Business
--------------------------

Landrica  was  incorporated  by the  Company  in March  1984,  and  holds  minor
interests in real estate.

The financial  position and results of operations of Black Hills  Generation and
Landrica are not material to the Company.

Year 2000 Issues
----------------

What is referred to as the Year 2000 problem ("Year 2000 problem") is the result
of computer  programs  being written using two digits rather than four to define
the  applicable  year. Any of the Company's  computer  systems and products that
have  date-sensitive  software may  recognize a date using "00" as the Year 1900
rather  than  the  Year  2000.   This  could  result  in  a  system  failure  or
miscalculations  causing  disruptions  of  operations,  including,  among  other
things, a temporary inability to process transactions,  send invoices, or engage
in similar normal business activities.

Management  has  formed a Year  2000  Committee  to  establish  and  ensure  the
Company's compliance with what is commonly known as the "Year 2000 problem".  In
addition,  consultants  have been  engaged  in  certain  areas to assist  with a
comprehensive  review of the Company's state of readiness and to assist with any
necessary  remedial  plans for the Year 2000 date change.  The Company's  review
encompassed supporting  information  technology systems,  product generation and
distribution systems, and business supply chain systems and infrastructure.

Management  presently  believes that with the  modifications it is making to the
Company's  existing  software and  conversions  to new  software,  the Year 2000
problem can be mitigated. However, if such modifications and conversions are not
made, or are not completed on a timely basis, the Year 2000 problem could have a
material  adverse  effect on the  Company's  business,  financial  condition and
results of operations.

Management  further  believes  that the cost of either  repairing  or  replacing
certain business systems to ensure business  continuance beyond Year 2000 should
not have a significant impact on the results of operations. The cost of the Year
2000 project is currently  estimated at less than $1 million and is being funded
through  operating  cash flows.  These costs are primarily  attributable  to the
purchase of new software and equipment  which are expensed or  capitalized  on a
basis consistent with the Company's accounting policies for capital assets.

Other than  seeking  representations  and  assurances  from third  parties,  the
Company has not made an assessment as to whether any of its customers, suppliers
or  service  providers  will be  affected  by the  date  change.  The  Company's
business,  financial  condition  and  results  of  operations  may be  adversely
impacted should the efforts of customers, suppliers or service providers for the
Company to address the Year 2000 issue  prove to be  inadequate.  The  Company's
risk management program includes emergency backup and recovery  procedures to be
followed in the event of failure of a business-critical system. These procedures
are being  expanded  to include  specific  procedures  for  potential  Year 2000
issues.  Contingency  plans to  protect  the  business  from  Year  2000-related
interruptions are being developed. These plans will be complete by June 1999 and
will include, for example,  development of backup procedures,  identification of
alternate suppliers and possible increases in safety inventory levels.

<PAGE>

Accounting Pronouncements
-------------------------

FASB  Statement  No. 130,  "Reporting  Comprehensive  Income,"  adopted in 1998,
establishes   standards  of  disclosure  and  financial  statement  display  for
reporting  total  comprehensive  income and the individual  components  thereof.
Adoption of Statement No. 130 did not impact the Company's financial position or
results of operations in 1998.

FASB Statement No. 131 "Disclosures  about Segments of an Enterprise and Related
Information"   requires  that  a  publicly-held  company  report  financial  and
descriptive  information  about its operating  segments in financial  statements
issued to  shareholders  for  interim and annual  periods.  The  Statement  also
requires   additional   disclosures  with  respect  to  products  and  services,
geographic  areas of operation,  and major  customers.  The Company adopted this
Statement in the fourth quarter of 1998.  (See NOTES TO  CONSOLIDATED  FINANCIAL
STATEMENTS  - Note 11 - Summary  of  Information  Relating  to  Segments  of the
Company's Business.)

FASB  Statement  No.  132  "Employers'  Disclosures  about  Pensions  and  Other
Postretirement  Benefits - an amendment of FASB  Statements No. 87, 88, and 106"
requires  revised  disclosures  about pension and other  postretirement  benefit
plans.  The Company  adopted this Statement in the fourth quarter of 1998.  (See
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Note 8 - Employee Benefit Plans.)

In March 1998, the Accounting  Standards Executive Committee issued Statement of
Position  98-1,  "Accounting  for the Costs of Computer  Software  Developed  or
Obtained  for  Internal  Use." The  Statement  is  effective  for  fiscal  years
beginning after December 15, 1998.  Earlier  application is encouraged in fiscal
years for which annual financial  statements have not been issued. The Statement
defines which costs of computer software  developed or obtained for internal use
are  capitalized  and which costs are  expensed.  The Company will adopt the new
Statement in 1999.  The effect of adoption is not expected to materially  affect
the Company's financial position or results of operations.

In May 1998, the Accounting  Standards  Executive  Committee issued Statement of
Position 98-5, "Reporting on the Costs of Start-Up Activities." The Statement is
effective  for fiscal years  beginning  after  December 15, 1998.  The Statement
defines  one-time  start up costs and  requires  such  costs to be  expensed  as
incurred.  The  Company  will  adopt the new  Statement  in 1999.  The effect of
adoption is not expected to materially affect the Company's  financial  position
or results of operations.

As a  result  of  recent  pronouncements  issued  by  the  Financial  Accounting
Standards Board and the Emerging Issues Task Force, the Company's  comprehensive
method of accounting for energy-related  contracts and/or derivative instruments
and hedging transactions is changing effective January 1, 1999. The Company does
not  anticipate   that  its  current   mark-to-market   accounting  for  certain
fixed-price natural gas contracts will be significantly affected by the adoption
of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments
and Hedging  Activities"  ("Statement  No. 133") or by the Emerging  Issues Task
Force's  conclusions  in EITF  98-10,  "Accounting  for Energy  Trading and Risk
Management Activities" ("EITF 98-10"). However,  provisions in Statement No. 133
and in EITF 98-10 will affect the  accounting  for other  trading and  marketing
operations that are currently  accounted for under the accrual method.  Further,
provisions in Statement No. 133 will affect the accounting for and disclosure of
other contractual arrangements and operations of the Company.

<PAGE>

The Company is required to adopt the provisions of EITF 98-10 effective  January
1, 1999,  while the transition  rules under  Statement No. 133 provide for early
adoption as of the beginning of any fiscal quarter  subsequent to June 15, 1998.
Management  anticipates that implementation of the provisions of these standards
will not have a material impact on the Company's  financial  position at January
1, 1999.  However,  management  believes that the adoption of the  provisions of
these standards may affect the variability of future periodic  results  reported
by the Company, as well as its competitors.  Such earnings variability,  if any,
will likely result  principally  from valuation  issues arising from  imbalances
between supply and demand created by  illiquidity in certain  commodity  markets
resulting  from,  among  other  things,  the lack of  mature  trading  and price
discovery mechanisms,  transmission and/or transportation  constraints resulting
from  regulation  or  other  issues  in  certain  markets  and  the  need  for a
representative number of market participants maintaining the financial liquidity
and other resources necessary to compete  effectively.  Management will continue
to monitor exposure to these and other market and business risks and will adjust
valuation reserves accordingly as indicated by changing circumstances.

                           BUSINESS OUTLOOK STATEMENTS

The following statements are based on current expectations. The statements under
this Business Outlook Statements section are forward-looking, and actual results
may differ materially.

Pacific Power's Power Sales Agreement
-------------------------------------

Pacific   Power's  Power  Sales   Agreement   represents   Black  Hills  Power's
highest-cost electric power resource. Black Hills Power has been able to utilize
the 75 MW resource from Pacific  Power's Power Sales  Agreement at a load factor
of only 60  percent.  Black  Hills  Power  expects to reduce  these costs in the
future through better  utilization of the resource  through a marketing  program
and as a result  of the  Second  Restated  and  Amended  Power  Sales  Agreement
executed  between  Pacific Power and Black Hills Power.  This marketing  program
will include the use of the Pacific  Power's Power Sales  Agreement  under which
Black Hills Power has the right to cause the power and energy to be delivered at
any point on  Pacific  Power's  transmission  system  (defined  as both  Pacific
Power's owned and  contracted  transmission  paths) where capacity is available.
This Second  Restated and Amended  Power Sales  Agreement,  effective  August 1,
1997, and  terminating  December 31, 2023,  supersedes  the Restated  Agreement,
which was intended to be effective January 1, 2000.

The Second  Restated  Agreement  provides  (i) that 25 megawatts of the contract
capacity amount and the charges  thereof will be deleted,  5 megawatts each year
commencing  in the year 2000,  (ii) Black  Hills  Power  shall pay no  levelized
annual  charges  for  Colstrip  Plants'  additions  and  replacements  which are
completed  after January 1, 1997,  (iii) that  commencing  January 1, 1997,  the
company's  fixed cost  components  of the  Variable  Costs  shall be based on an
assumption that the Colstrip Plants operated at an 80 percent load factor,  (iv)
beginning  August 1, 1997 and continuing  until  December 31, 1999,  Black Hills
Power shall pay Pacific Power annual fixed cost of $164.59 per kW-yr  multiplied
by the capacity  purchased,  (v) commencing  January 2000 and  continuing  until
December 2018, Black Hills Power shall pay Pacific Power's initial investment in
Colstrip Units 3 and 4 using Pacific  Power's then most current  applicable cost
of capital  consisting  of Pacific  Power's then current FERC  approved  capital
structure,  Pacific Power's then current weighted average cost of long-term debt
and preferred stock using FERC approved methods and Pacific Power's then current
FERC  approved  cost of common  equity,  (vi) that the monthly  invoices for the
fixed  amount  calculated  above  shall be reduced by $95,564 for the years 2000
through 2009, and (vii) unbundling of the transmission charge in the contract to
Pacific Power's FERC-filed rates. Future cost reductions or increases related to
these  amendments  will depend on Pacific  Power's future capital  structure and
cost of capital  and the cost of  replacement  power  starting in the year 2000.
However,  the Company  believes the  reduction  of the 25 MWs of capacity  which
begins  in the year  2000 at a rate of 5 MW a year is  positive  as the  Company
enters a deregulated electricity market and believes Pacific Power's future cost
of capital under the FERC approved capital structure will be lower than the cost
of capital formulas embedded in the existing contract.

Future Electric Sales
---------------------

Future  earnings  from all  power  sales  are  dependent  on many  economic  and
political  factors,  including the move toward  competition at the retail level,
the market  price of  electricity,  the ability of Black Hills Power to generate
and  deliver  electric  power at a cost that will allow a profit  margin and the
regulatory  treatment of electric  utilities during the transition period toward
competition.

<PAGE>

In order to  realize  a higher  margin of  profit  than  from  sales on the spot
market,  Black Hills Power  continues  to look for  opportunities  to sell power
off-system . The highly competitive wholesale electric power market, the lack of
an open  retail  market at this time,  the cost of  transmission  to deliver the
power to markets where prices are higher, the current low natural gas prices and
the  availability  of surplus  capacity  and energy are the current  competitive
conditions  that make it  difficult  to find new  markets.  However,  management
believes that Black Hills Power's  marginal  production costs are low enough and
the  quantity  of power Black  Hills  Power has  available  high enough that new
opportunities for off-system sales are feasible.

Future Retail Wheeling
----------------------

Management is unable to predict the effect of full electric  retail  competition
(if it comes about) on the Company's earnings. Management does anticipate that a
transition  period of at least five years  will be  required  to achieve a fully
competitive  electric  energy  retail  market.  Black Hills Power  continues  to
endeavor to increase its earnings through additional sales and cost containment.
Based upon the FERC's expressed  positions  concerning open access  transmission
regulations,  electric  utilities  which will lose  revenue  due to  competition
should be allowed to recover stranded costs. The market price of electric energy
in a  fully  competitive  market  is  expected  to be  based  upon a much  wider
geographical area than just Black Hills Power's service  territory.  Because the
energy  providers are likely to seek the markets where the highest profit margin
can be realized,  today's rates designed to serve exclusive service  territories
may be substantially  different for service to a fully competitive market. Based
upon  industry  predictions,  management  believes  that the  industry's  excess
capacity  will be more fully  utilized in the future.  Management  believes that
coal-fired  plants will become more competitive with natural gas-fired plants in
the future as natural gas prices increase.

However, the Company is unable to predict future markets and economic conditions
and government  actions or inactions that could have a materially adverse effect
on Black Hills Power's ability to compete in a fully competitive  electric power
market and to maintain its equity return on investment.

Rate Regulation
---------------

Management's expectation is that the rate settlements made with the South Dakota
and  Wyoming  Commissions  in 1995 are  beneficial  in that (i)  management  has
confidence  in the  operational  capability of Black Hills Power's power plants;
(ii)  management  does not  anticipate  purchasing  any  substantial  amount  of
capacity and energy during the freeze  period  except for its existing  purchase
power  agreements;  and (iii) Wyodak Resources' mining costs are not expected to
materially   increase.   Absent  unplanned  state  or  Federal  requirements  to
deregulate the electric utility industry in South Dakota or Wyoming, the Company
expects its electric operations to be regulated by the SDPUC and WPSC.

Future Coal Sales
-----------------

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,  including a material  breach of an obligation  under
existing contracts.

The coal  mining  industry  is  highly  competitive  and  significant  new sales
opportunities are limited.  Wyodak Resources operates in an area with many other
mining  companies  which have  substantial  unused  capacity.  They, like Wyodak
Resources,  have the permits and capability  for large  increases in production.
Currently, Wyodak Resources' coal sales are confined to sales for consumption at
or near the mine.  Wyodak  Resources is a relatively small coal mine in relation
to others in the area and its current  production  costs exceed the current spot
market price for coal.

<PAGE>

Because of an  acquisition  of unit train  load-out  facilities  with the Clovis
Point  Mine  Properties,   Wyodak  Resources  expects  to  increase  its  market
opportunities. However, the heating value (approximately 8,000 Btu per pound) of
the coal at Wyodak  Resources'  mine and the  Clovis  Point Mine  Properties  is
approximately  400 to 800 Btus less than Powder  River Basin coal  available  at
other locations.  This difference in the Btu value combined with relatively high
mining  costs  due  to low  production  volumes  makes  Wyodak  Resources'  coal
noncompetitive  in the  current  market for coal to be shipped by rail over long
distances  because  of  higher  freight  rates  per  Btu.  Notwithstanding  this
limitation,  the acquisition of a unit train loadout facility has led management
to investigate opportunities for Wyodak Resources to ship coal by rail at closer
distances  where the Btu  difference  would not be a major factor,  to ship coal
that is enhanced at the coal mine site by various processes,  one of the results
of which  would  remove  some of the  moisture  content of the coal and  thereby
increase the Btu per pound content and to the  acquisition of the coal marketing
companies to enhance future coal sale opportunities.

Processes for the enhancement of Powder River Basin coal are being developed and
seriously  considered  for commercial  operations by the coal  industry.  Wyodak
Resources  continues to investigate  several coal enhancement  opportunities but
has not invested  significant  capital in any of the  processes.  Management can
give no  assurances  at this  time  that any coal  enhancement  process  will be
economically  viable at Wyodak Resources' mine due to several factors including:
the  current  low spot  market  price of  Powder  River  Basin  coal,  technical
limitations of many of the coal enhancement  processes developed to date, and an
uncertain market demand for enhanced Powder River Basin coal.

Freight rates to ship coal by rail are also a material factor in determining the
economic feasibility of selling either raw run-of-the-mine coal or enhanced coal
products.  At this time  only one rail  carrier,  the  Burlington  Northern,  is
available to Wyodak  Resources  for such sales.  Reasonable  freight rates are a
requirement for any rail transported sales from Wyodak Resources' mine.

Future Oil and Gas Sales
------------------------

Many  factors  can  significantly  affect  sales of oil and  natural gas and the
corresponding  revenues  under  existing  or  future  agreements.  Such  factors
include,  but are not limited to, the  seller's or buyer's  inability to perform
due to equipment malfunctions,  damage to equipment, and transportation problems
which could result from the Company or third party  providers of such  services,
governmental impositions,  labor problems,  weather problems,  economic factors,
and other unexpected events.

The oil and natural gas industry is highly competitive and the Company's ability
to obtain  rights to drill future oil and natural gas wells and/or  acquire such
properties is subject to the Company's availability to obtain such opportunities
on an economic basis.

The Company is unable to predict future markets, technological advancements, and
economic  conditions  that could effect the  profitability  and  probability  of
success of the oil and natural gas operations.

Future Energy Marketing Sales
-----------------------------

The profitability of the Company's energy marketing  operations depends in large
part  on  management's   ability  to  assess  and  respond  to  changing  market
conditions.  Such conditions  include,  but are not limited to,  availability of
supply,  availability  of  transportation  capacity  from supply area to markets
served,  operating  margins  on sales  and  market  demand.  In  addition,  such
operations are highly sensitive to weather conditions in the markets served. The
Company is unable to predict future markets and economic  conditions  that could
effect the profitability of the energy marketing operations.

Future Communication and Technology Activities
----------------------------------------------

The Company's start-up communications  operations are expected to have operating
losses for two to four  years.  The  recovery of capital  investment  and future
profitability  are dependent  primarily on the ability of the Company to attract
new  customers  and  customers  from  incumbent  providers  including  U.S. West
Communications and  Telecommunications,  Inc. (TCI) the incumbent  telephone and
cable  television  providers.  Although  the Company does not  anticipate  being
regulated in the local markets it is unable to predict  future  markets,  future
government  impositions,  and future  economic  conditions that could effect the
profitability of the communication and technology operations.

Future Corporate Development Activities
---------------------------------------

The Company's corporate  development  activities are accomplished  through Black
Hills  Capital  Group.  Black Hills  Capital  Group's  focus is to increase  the
Company's   earnings  and  assets  through  energy  and  communication   related
investments  that  position  the  Company  to  earn  multiple  revenue  streams.
Potential  investments  could be comprised of independent  power projects,  coal
reserves,  oil and gas reserves,  energy transportation assets, energy marketing
assets, communication assets or other related assets. The success of Black Hills
Capital Group acquiring such assets will depend on future market conditions. The
market for such  assets is very  competitive.  The  Company is unable to predict
future markets and economic  conditions that could effect the  profitability and
probability of the success of corporate development activities.

Risks and Uncertainties
-----------------------

The forward  looking  statements  contained in the  Management's  Discussion and
Analysis of Financial  Condition and Results of  Operations  involve a number of
risks and  uncertainties.  In addition to factors discussed above, other factors
that could cause actual  results to differ  materially  are the  following:  the
extent to which  the  federal  government  or the  state  governments,  or both,
institute  competition  in the electric  utility  business;  the market value of
electric power at the time of full  competition,  of including any  competitor's
delivery  costs to Black Hills Power's  current  markets and Black Hills Power's
ability to produce and deliver power at those market prices; the extent to which
the  surplus  electric  generation  continues;  the  extent  that  any  electric
generating   surplus  is  exhausted  and  customers  are  again   entering  into
longer-term purchased power contracts with prices relating more to the full cost
of generating and  delivering  electric power than to spot market energy prices;
the future  market  prices of crude oil,  natural  gas and coal;  the  Company's
ability to produce  coal,  oil and natural gas at costs  maintaining  historical
profit  margins  consistent  with  contractual  sales  obligations;   government
regulations  of the  environment,  especially  to the  extent  to which  further
financial  burdens  may be placed upon coal  versus  natural gas and  additional
governmental  burdens  that may be placed upon the burning of all fossil  fuels;
the extent to which competition will be fairly  administered for participants in
the  electric  utility  business  and  whether  it will be  applied  equally  to
investor-owned companies, rural electric cooperatives, public power agencies and
municipalities;  technological  advances  in  the  generation  and  delivery  of
electric power; the general economy as it affects the use of electric power; the
market price of competing fuels to electricity,  such as natural gas; the extent
to which coal beneficiation programs are efficiently developed and the extent to
which the new coal  products  will be  accepted  by the  market;  the  Company's
ability and success in implementing its communications  strategy;  technological
advances in  communications  delivery  equipment;  the general  economy of Black
Hills  Power's  retail  service  territory;  and other  risk  factors  which are
referenced in this report and other SEC reports filed prior hereto.

<PAGE>

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

      Report of Independent Public Accountants                               37

      Consolidated Statements of Income and Retained Earnings
        for the three years ended December 31, 1998                          38

      Consolidated Statements of Cash Flows for
        the three years ended December 31, 1998                              39

      Consolidated Balance Sheets as of December 31, 1998 and 1997           40

      Consolidated Statements of Capitalization as of
        December 31, 1998 and 1997                                           41

      Notes to Consolidated Financial Statements                             42



                    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,
1998 and 1997,  and the  related  consolidated  statements  of income,  retained
earnings and cash flows for each of the three years in the period ended December
31, 1998.  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,  1998  and  1997,  and the  results  of their
operations  and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.

                                                       ARTHUR ANDERSEN LLP



Minneapolis, Minnesota,
January 27, 1999

<PAGE>
<TABLE>

                                  BLACK HILLS CORPORATION
                             CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>
Years ended December 31                       1998         1997         1996
-----------------------                       ----         ----         ----
                                        (in thousands, except per share amounts)
<S>                                        <C>           <C>         <C>    
Operating revenues:
   Electric                                $129,236      $126,497    $118,718
   Coal mining                               31,413        31,080      31,315
   Oil and gas                               12,562        13,295      12,555
   Energy marketing                         506,043       142,790           -
                                            -------       -------     -------       
                                            679,254       313,662     162,588
                                            -------       -------     -------
Operating expenses:
   Fuel and purchased power                 531,518       177,071      34,195
   Operations and maintenance                32,701        31,743      30,343
   Administrative and general                15,747        12,113       8,491
   Depreciation, depletion and amortization  24,037        22,311      22,794
   Oil and gas ceilings test write down      13,546             -           -
   Taxes, other than income taxes            12,472        11,985      12,460
                                             ------        ------      ------
                                            630,021       255,223     108,283
                                            -------       -------     -------

Operating income                             49,233        58,439      54,305
                                             ------        ------      ------

Other income (expense):
   Interest expense                         (14,707)      (14,123)    (13,942)
   Investment income                          2,861         2,136       1,373
   Other, net                                   129           233       2,094
                                            -------       -------     -------
                                            (11,717)      (11,754)    (10,475)
                                            -------       -------     ------- 
Income before income taxes                   37,516        46,685      43,830
Income taxes                                (11,708)       (14,326)   (13,578)
                                            -------        -------    ------- 
       Net income                          $ 25,808      $ 32,359    $ 30,252
                                           ========      ========    ========

Earnings per share of common stock:
   Basic and diluted                         $1.19         $1.49        $1.40
                                             =====         =====        =====
Weighted average common shares outstanding:
   Basic                                     21,623        21,692      21,660
                                             ======        ======      ======
   Diluted                                   21,665        21,706      21,660
                                             ======        ======      ======
</TABLE>
<TABLE>

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<CAPTION>
Years ended December 31                       1998         1997         1996
-----------------------                       ----         ----         ----
                                                      (in thousands)
<S>                                        <C>           <C>         <C>
Balance, beginning of year                 $143,703      $131,884    $121,562
Net income                                   25,808        32,359      30,252
Cash dividends on common stock ($1.00,
  $0.95 and$0.92 per share, respectively)   (21,737)      (20,540)    (19,930)
                                            -------       -------     ------- 

Balance, end of year                       $147,774      $143,703    $131,884
                                           ========      ========    ========
</TABLE>

The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.

<PAGE>

                                 BLACK HILLS CORPORATION
                           CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31                          1998        1997        1996
                                                 ----        ----        ----
                                                        (in thousands)

Operating activities:
   Net income                                   $25,808      $32,359    $30,252
   Principal non-cash items-
    Depreciation, depletion and amortization     24,037       22,311     22,794
    Oil and gas ceilings test write down         13,546            -          -
    Deferred income taxes and investment tax   
     credits                                     (2,535)       2,457      1,872
   Increase in receivables, inventories and
     other current assets                       (49,775)     (27,067)      (373)
   Increase (decrease) in current liabilities    43,709       26,015     (1,412)
   Other, net                                       (60)         (26)     2,264
                                                 ------       ------     ------
                                                 54,730       56,049     55,397
                                                 ------       ------     ------
Investing activities:
   Property additions, excluding allowance
    for other funds used during construction    (25,265)     (21,087)   (24,388)
   Energy marketing assets                       (1,960)      (7,232)         -
   Available for sale securities purchased      (22,361)     (31,944)   (40,894)
   Available for sale securities sold            13,655       29,433     36,189
                                                (35,931)     (30,830)   (29,093)

Financing activities:
   Dividends paid                               (21,737)     (20,540)   (19,930)
   Treasury stock, net                           (3,081)           -          -
   Common stock issued                              273          409        511
   Increase (decrease) in short-term borrowings   5,067         (120)      (475)
   Long-term debt issued                              -            -        156
   Long-term debt retired                         (1,331)     (1,534)    (1,405)
                                                 -------     -------    ------- 
                                                 (20,809)    (21,785)   (21,143)
                                                 -------     -------    ------- 

    Increase (decrease) in cash and cash
     equivalents                                  (2,010)      3,434      5,161

Cash and cash equivalents:
   Beginning of year                              16,774      13,340      8,179
                                                  ------      ------      -----
   End of year                                   $14,764     $16,774    $13,340
                                                 =======     =======    =======

Supplemental disclosure of cash flow information:

   Cash paid during the period for-
    Interest                                    $14,742      $14,167    $13,996
    Income taxes                                $13,135      $11,840    $12,616

   Assumption of reclamation liability in
     acquisition of Clovis Point properties     $     -      $     -    $ 7,957

The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.

<PAGE>
                                 BLACK HILLS CORPORATION
                                CONSOLIDATED BALANCE SHEETS

At December 31,                                           1998          1997
---------------                                           ----          ----
                                                            (in thousands)
   ASSETS
Current assets:
   Cash and cash equivalents                         $  14,764       $  16,774
   Securities available for sale                        22,675          13,969
   Receivables, net
    Customers                                           87,068          39,639
    Other                                                2,919           3,414
   Materials, supplies and fuel                          9,733           8,642
   Prepaid expenses                                      3,321           1,571
                                                       -------          ------
                                                       140,480          84,009
                                                       -------          ------
Property and equipment:
   Electric                                            496,883         487,424
   Coal mining                                          51,889          52,804
   Oil and gas                                          62,581          52,412
   Other                                                 8,196           5,666
                                                       619,549         598,306
   Less accumulated depreciation and depletion        (229,942)       (197,179)
                                                      --------        -------- 
                                                       389,607         401,127
                                                      --------        --------
Deferred charges:
   Federal income taxes                                 12,347           8,061
   Regulatory asset                                      3,978           3,776
   Other                                                13,005          11,768
                                                      --------        --------
                                                        29,330          23,605
                                                      --------        --------
                                                      $559,417        $508,741
                                                      ========        ========
   LIABILITIES AND CAPITALIZATION
Current liabilities:
   Current maturities of long-term debt              $   1,330      $    1,331
   Notes payable                                         5,090              23
   Accounts payable                                     74,087          32,622
   Accrued liabilities-
    Taxes                                                9,950           8,040
    Interest                                             3,956           3,991
    Other                                                8,169           7,800
                                                       -------          ------
                                                       102,582          53,807
                                                       -------          ------
Deferred credits:
   Federal income taxes                                 55,107          53,010
   Investment tax credits                                3,514           4,014
   Reclamation liability                                17,000          16,664
   Regulatory liability                                  5,661           6,152
   Other                                                 6,857           6,331
                                                        ------          ------
                                                        88,139           8,171
                                                        ------          ------
Commitments and contingent liabilities (Notes 6, 7 and 8)

Capitalization, per accompanying statements:
   Common stock equity                                 206,666         205,403
   Long-term debt                                      162,030         163,360
                                                      --------        --------
                                                       368,696         368,763
                                                      --------        --------
                                                      $559,417        $508,741
                                                      ========        ========

The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.

<PAGE>
<TABLE>

                                 BLACK HILLS CORPORATION
                         CONSOLIDATED STATEMENTS OF CAPITALIZATION
<CAPTION>
At December 31,                                          1998          1997
---------------                                          ----          ----
                                                            (in thousands)
<S>                                                  <C>            <C>
Common stock equity:
   Common stock $1 par value; 50,000,000 shares
     authorized; 21,719,465 and 21,704,592 shares 
     outstanding, respectively                       $  21,719      $  21,705
   Additional paid-in capital                           40,254         39,995
   Retained earnings                                   147,774        143,703
   Treasury stock                                       (3,081)             -   
                                                       -------        -------          

      Total common stock equity                        206,666        205,403
                                                       -------        -------


Long-term debt:
   First mortgage bonds-
    6.50% due 2002                                      15,000         15,000
    9.00% due 2003                                       5,295          6,336
    8.06% due 2010                                      30,000         30,000
    9.49% due 2018                                       5,710          6,000
    9.35% due 2021                                      35,000         35,000
    8.30% due 2024                                      45,000         45,000
                                                       -------        -------
                                                       136,005        137,336
                                                       -------        -------

Other-
   6.7% pollution control revenue bonds, due 2010       12,300         12,300
   7.5% pollution control revenue bonds, due 2024       12,200         12,200
   Other long-term obligations                           2,855          2,855
                                                        ------         ------
                                                        27,355         27,355
                                                        ------         ------

    Total long-term debt                               163,360        164,691

Current maturities                                      (1,330)        (1,331)
                                                        ------         ------ 

    Net long-term debt                                 162,030        163,360
                                                       -------        -------

    Total capitalization                              $368,696       $368,763
                                                      ========       ========

</TABLE>

The accompanying notes to consolidated financial statements are an integral part
of these consolidated financial statements.

<PAGE>

1

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        December 31, 1998, 1997 and 1996

 (1)  BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills  Corporation and its  subsidiaries  operate in four primary business
segments:  electric,  energy extraction and production (includes coal mining and
oil and natural gas  operations),  energy  marketing,  and  communications.  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  17 percent of the
Company's  electric  revenue in 1998, 18 percent in 1997 and 17 percent in 1996.
The coal mining operation of the Company, located in northeastern Wyoming, mines
and sells  sub-bituminous coal primarily under long-term coal supply agreements.
As discussed in Note 6,  approximately 74 percent of the coal mining operation's
sales are to the Wyodak Plant.  Sales of coal to the Company and to  PacifiCorp,
herein referred to as Pacific Power, represent 97 percent of total coal sales in
1998. The Company's oil and gas exploration and production business operates and
has working  interests in properties  located in the western and southern United
States. The Company's energy marketing  businesses market natural gas, crude oil
and coal and provide  related  energy  services to  customers in the West Coast,
Northwest,  Rocky  Mountain,  Southwest,  Midwest  and East Coast  markets.  The
Company's  communication  operations  represent  a start-up  business to provide
communication  services  to Rapid  City and the  Northern  Black  Hills of South
Dakota and a software development and marketing company.

Principles of Consolidation

The  consolidated  financial  statements  include  the  accounts  of Black Hills
Corporation  and its wholly owned  subsidiaries.  All  significant  intercompany
balances and  transactions  have been  eliminated  in  consolidation  except for
revenues and expenses associated with intercompany coal sales in accordance with
the  provisions of Statement of Financial  Accounting  Standards  (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation."  Total intercompany
coal sales not eliminated  were  $10,256,000,  $11,089,000,  and  $10,384,000 in
1998, 1997, and 1996, respectively.

In 1998,  Enserco Energy,  Inc.  ("Enserco")  reacquired the other  shareholders
interests effectively becoming a wholly-owned subsidiary. For the 1998 financial
statements,  the Company  consolidated Enserco as if it was wholly owned for the
entire year and  reported a minority  interest for the portion of net income due
the other  shareholders.  Investments in Enserco,  in which in 1997 and 1996 the
Company had a 50 percent  ownership  interest,  were accounted for on the equity
method of accounting.

The  Company  uses the  proportionate  consolidation  method to account  for its
working interests in oil and gas properties.

Regulatory Accounting

Black  Hills  Power  follows the  provisions  of SFAS No. 71, and its  financial
statements reflect the effects of the different  ratemaking  principles followed
by the various jurisdictions  regulating Black Hills Power. As a result of Black
Hills Power's 1995 rate case settlement, a 50-year depreciable life for NS #2 is
used for financial reporting  purposes.  If Black Hills Power were not following
SFAS 71, a 35 to 40 year life would be more  appropriate  which  would  increase
depreciation  expense by  approximately  $600,000 per year.  If rate recovery of
generation-related  costs becomes  unlikely or uncertain,  due to competition or
regulatory action, these accounting standards may no longer apply to Black Hills
Power's generation operations. In the event Black Hills Power determines that it
no longer meets the criteria for following SFAS 71, the accounting impact to the
Company  would be an  extraordinary  non-cash  charge to operations of an amount
that could be material. Criteria that give rise to the discontinuance of SFAS 71
include  increasing  competition that could restrict Black Hills Power's ability
to establish  prices to recover  specific costs and a significant  change in the
manner in which  rates  are set by  regulators  from  cost-based  regulation  to
another form of regulation.  The Company  periodically reviews these criteria to
ensure the continuing application of SFAS 71 is appropriate.

<PAGE>

Property 

Property is recorded at cost which  includes an allowance  for funds used during
construction where applicable.  The cost of electric property retired,  together
with removal cost less salvage, is charged to accumulated depreciation.  Repairs
and maintenance of property are charged to operations as incurred.

The Company  periodically  evaluates assets under SFAS No. 121,  "Accounting for
the Impairment of Long-Lived  Assets and  Long-Lived  Assets to Be Disposed Of,"
which imposes a stricter  criterion for assets by requiring  that such assets be
probable of future recovery at each balance sheet date.

Depreciation and Depletion

Depreciation  is computed  using the  straight-line  method  over the  estimated
useful lives of the related  assets.  Depreciation  provisions  for the electric
property were  equivalent to annual  composite rates of 3.0 percent in 1998, and
1997 and 3.4 percent in 1996.  Composite  depreciation  rates for other property
were  7.9  percent,  8.1  percent,  and 7.7  percent  in 1998,  1997  and  1996,
respectively. Depletion of coal and oil and gas properties is computed using the
cost method for financial reporting.

Available for Sale Securities

The Company has  investments  in marketable  securities  which are classified as
available-for-sale  securities  and are  carried at fair value.  The  difference
between the  securities'  fair value and cost basis and the  realized  gains and
losses  on  sales  of the  securities  were  not  significant  for  the  periods
presented.

Revenue Recognition

Revenue  from sales of electric  energy is based on rates filed with  applicable
regulatory  authorities.  Electric  revenue  includes an accrual  for  estimated
unbilled  revenue for services  provided  through  year-end.  Revenue from other
business  segments is  recognized  at the time the products are delivered or the
services are rendered.

Fuel and Purchased Power Adjustment Tariffs

The Company's  Montana  Retail  Tariffs  contain a clause that allow recovery of
certain  fuel and  purchased  power  costs in excess of the level of such  costs
included in base rates. The cost adjustment  tariff is revised  periodically for
any  difference  between  the total  amount  collected  under the clause and the
recoverable costs incurred.  The adjustments are recognized as current assets or
current liabilities until adjusted through future billings to customers.

The  Company's  South Dakota,  Wyoming and  wholesale  tariffs do not include an
automatic fuel and purchased power adjustment tariff.

Use of Estimates

The preparation of financial  statements in conformity  with generally  accepted
accounting principles requires management to make estimates and assumptions that
affect  the  reported  amounts  of assets  and  liabilities  and  disclosure  of
contingent  assets and  liabilities at the date of the financial  statements and
the reported amounts of revenues and expenses during the reporting period.
Ultimate results could differ from those estimates.

Oil and Gas Operations

The Company  accounts for its oil and gas activities under the full cost method.
Under the full cost method,  all productive and  nonproductive  costs related to
acquisition,  exploration and development  drilling  activities are capitalized.
These costs are  amortized  using a  unit-of-production  method based on volumes
produced and proved reserves.  Under the full cost method, net capitalized costs
may not exceed the present value of proved reserves.

Allowance for Funds Used During Construction

Allowance for funds used during  construction  (AFDC) represents the approximate
composite  cost of  borrowed  funds  and a return  on  capital  used to  finance
construction  expenditures  and is  capitalized  as a component  of the electric
property.  The AFDC was computed at an annual  composite rate of 10.1 percent in
1998 and 10.0 percent in 1997 and 1996.

<PAGE>

Income Taxes

The Company  follows the  provisions  of SFAS No.  109,  "Accounting  for Income
Taxes," which requires the use of the liability  method in accounting for income
taxes.  Under the liability  method,  deferred income taxes are  recognized,  at
currently  enacted  income tax rates,  to  reflect  the tax effect of  temporary
differences between the financial and tax bases of assets and liabilities.  Such
temporary  differences  are the result of  provisions in the income tax law that
either  require or permit  certain items to be reported on the income tax return
in a different period than they are reported in the financial statements. To the
extent  such income  taxes are  recoverable  or payable  through  future  rates,
regulatory  assets  and  liabilities  have  been  recorded  in the  accompanying
consolidated balance sheets.

Deferred  taxes  are  provided  on  all   significant   temporary   differences,
principally  depreciation  and  depletion.  Investment  tax  credits  have  been
deferred in the electric operation and the accumulated balance is amortized as a
reduction of income tax expense  over the useful  lives of the related  electric
property which gave rise to the credits.

Price Risk Management

The Company  utilizes  deferral  (hedge)  accounting  in  conjunction  with such
financial  instruments;  gains or losses from changes in the market value of the
financial  instruments are deferred until the gain or loss on the hedged item is
recognized.

Financial  instruments  are  classified  as being  used for a hedge  only if the
instrument  reduces the risk of the underlying  hedged item and is designated at
the inception as a hedge with respect to the hedged item.

Accounting Pronouncements

FASB  Statement  No. 130,  "Reporting  Comprehensive  Income,"  adopted in 1998,
establishes   standards  of  disclosure  and  financial  statement  display  for
reporting  total  comprehensive  income and the individual  components  thereof.
Adoption of Statement No. 130 did not impact the Company's financial position or
results of operations in 1998.

In March, 1998, the Accounting Standards Executive Committee issued Statement of
Position  98-1,  "Accounting  for the Costs of Computer  Software  Developed  or
Obtained  for  Internal  Use." The  Statement  is  effective  for  fiscal  years
beginning after December 15, 1998.  Earlier  application is encouraged in fiscal
years for which annual financial  statements have not been issued. The statement
defines which costs of computer software  developed or obtained for internal use
are  capitalized  and which costs are  expensed.  The Company will adopt the new
Statement in 1999.  The effect of adoption is not expected to materially  affect
the Company's financial position or results of operations.

In May 1998, the Accounting  Standards  Executive  Committee issued Statement of
Position 98-5, "Reporting on the Costs of Start-Up Activities." The Statement is
effective  for fiscal years  beginning  after  December 15, 1998.  The Statement
defines  one-time  start up costs and  requires  such  costs to be  expensed  as
incurred.  The  Company  will  adopt the new  statement  in 1999.  The effect of
adoption is not expected to materially affect the Company's  financial  position
or results of operations.

As a  result  of  recent  pronouncements  issued  by  the  Financial  Accounting
Standards Board and the Emerging Issues Task Force, the Company's  comprehensive
method of accounting for energy-related  contracts and/or derivative instruments
and hedging transactions is changing effective January 1, 1999. The Company does
not  anticipate  that its  current  mark-to-market  accounting  for  fixed-price
natural  gas  contracts  will  be  significantly  affected  by the  adoption  of
Financial  Accounting Standard No. 133,  "Accounting for Derivative  Instruments
and Hedging  Activities"  ("Statement  No. 133") or by the Emerging  Issues Task
Force's  conclusions  in EITF  98-10,  "Accounting  for Energy  Trading and Risk
Management Activities" (EITF 98-10").  However,  provisions in Statement No. 133
and in EITF 98-10 will affect the  accounting  for other  trading and  marketing
operations that are currently  accounted for under the accrual method.  Further,
provisions in Statement No. 133 will affect the accounting for and disclosure of
other  contractual  arrangements  and operations of the company.  The Company is
required to adopt the provisions of EITF 98-10 effective  January 1, 1999, while
the  transition  rules under  Statement No. 133 provide for early adoption as of
the  beginning of any fiscal  quarter  subsequent  to June 15, 1998.  Management
anticipates  that  implementation  of the provisions of these standards will not
have a material impact on the Company's financial position at January 1, 1999.

<PAGE>

Reclassifications

Certain 1997 and 1996 amounts in the financial statements have been reclassified
to  conform to the 1998  presentation.  These  reclassifications  did not have a
material  effect  on  the  Company's  stockholders'  investment  or  results  of
operations.

(2) CAPITAL STOCK

In January,  1998, the Board of Directors  declared a 3-for-2 Common Stock Split
effected in the form of a stock dividend.  The stock dividend was paid March 10,
1998 to  shareholders of record on February 13, 1998. The common stock share and
per share information in the accompanying  consolidated financial statements and
notes reflect the stock distribution.

Net Income Per Share

The Company  follows  SFAS No. 128  "Earnings  Per Share",  which  requires  the
presentation of basic and diluted  earnings per share.  Basic earnings per share
is computed by  dividing  net income  available  to common  shareholders  by the
weighted average number of common shares  outstanding  during each year. Diluted
earnings per share is computed under the treasury stock method and is calculated
to compute the dilutive effect of outstanding stock options.

A reconciliation of these amounts is as follows (in thousands,  except per share
data):

                              1998       1997        1996
                              ----       ----        ----
Net income                  $25,808     $32,359    $30,252
                            =======     =======    =======
Weighted average
  common shares
  outstanding-basic          21,623      21,692     21,660
Dilutive effect of
  option plan                    14          42          -
                             ------      ------     ------      
Common and
  potential common
  shares outstanding-    
  diluted                    21,665      21,706     21,660
                             ======      ======     ======
Basic and diluted net                 
  income per share            $1.19       $1.49      $1.40
                              =====       =====      =====


Common Stock

The Company has a stock option plan ("the 1996 Stock Option  Plan") which allows
for the  granting of stock  options  with  exercise  prices equal to the stocks'
market value on the date of grant and an employee stock purchase plan ("the ESPP
Plan").  The Company accounts for such plans under  Accounting  Principles Board
Opinion No. 25, under which no compensation cost has been recognized.

Had  compensation  cost  been  determined  consistent  with  SFAS No.  123,  the
Company's  net  income and  earnings  per share  would have been  reduced to the
following proforma amounts:

                              1998       1997        1996
                              ----       ----        ----
                                    (in thousands)
Net income:
  As reported               $25,808     $32,359     $30,252
  Proforma                  $25,717     $32,308     $30,215

Earnings per share (basic and diluted):
  As reported                 $1.19       $1.49       $1.40
  Performa                    $1.19       $1.49       $1.39

The Company may grant options for up to 300,000 shares of common stock under the
Stock  Option  Plans.  The  Company has  granted  options on 292,700  shares and
182,700  shares  through  December 31, 1998 and 1997,  respectively.  The option
exercise  price  equals  the fair  market  value of the  stock on the day of the
grant. The options granted have an exercise price range of $16.67 to $25.00. The
options  granted vest  one-third a year for three years and all expire after ten
years from the grant date. At December 31, 1998,  84,800  options were available
for  exercise at an exercise  price range of $16.67 to $22.50.  At December  31,
1997, 27,900 options were available for exercise at an exercise price of $16.67.
There were no options available for exercise at December 31, 1996.

<PAGE>

The fair value of each option  grant is estimated on the date of grant using the
Black  Scholes  option   pricing  model  with  the  following   weighted-average
assumptions used for the grants:

                             1998       1997        1996
                             ----       ----        ----
                                    (in thousands)

Risk free interest rate      5.50%      6.09%       6.15%
Expected dividend yield      4.20%      5.00%       5.50%

Expected life                10 years   10 years   10 years
Expected volatility          16.67%    16.71%      17.66%
Weighted average fair value  $0.61     $1.09       $0.49

The Company  issued 12,824 and 29,294 shares of common stock under the ESPP Plan
in 1998 and 1997,  respectively.  At  December  31,  1998,  267,135  shares  are
reserved and available for issuance  under the ESPP Plan.  The Company sells the
shares to  employees  at 90 percent of the stock's  market price on the offering
date. The fair value per share of shares sold in 1998 was $19.38.

The  Company has a Dividend  Reinvestment  and Stock  Purchase  Plan under which
shareholders  may purchase  additional  shares of common stock through  dividend
reinvestment  and/or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market.  The Company  purchased  shares on the open market in
1998, 1997 and 1996. At December 31, 1998,  1,290,797  shares of unissued common
stock were available for future offerings under the Plan.

Additional Paid-in Capital

Changes in additional paid-in capital for the years indicated were:

                             1998       1997        1996
                             ----       ----        ----
                                    (in thousands)

Balance, beginning
  of year                   $39,995    $46,841     $46,355
Stock Dividend for 3-for-2 
  Common Stock split              -     (7,235)          -
Premium, net of expenses
  from sales of stock           259        389         486
                            -------    -------     -------
Balance, end of year        $40,254    $39,995     $46,841
                            =======    =======     =======

Treasury Stock

In 1998, a subsidiary of the Company was  authorized to repurchase up to 300,000
shares  of  common  stock to be used for  acquisitions,  development  and  other
corporate  purposes.  At December 31, 1998, the Company had  reacquired  141,251
shares at an average price of $22.50 per share.

(3)   LONG-TERM DEBT

Substantially  all of the Company's  utility  property is subject to the lien of
the Indenture  securing its first  mortgage  bonds.  First mortgage bonds of the
Company  may be  issued in  amounts  limited  by  property,  earnings  and other
provisions of the mortgage  indentures.  Scheduled  maturities of long-term debt
for the next five years are: $1,330,000 in 1999,  $1,330,000 in 2000, $3,029,000
in 2001, $18,018,000 in 2002, and $3,068,000 in 2003.

(4)   NOTES PAYABLE

The Company had $12,000,000 of unsecured  short-term lines of credit at December
31, 1998 and 1997. There was $3,850,000  outstanding under these lines of credit
at December 31, 1998. There were no outstanding borrowings at December 31, 1997.
The Company has no compensating balance requirements associated with these lines
of credit. The lines of credit are subject to periodic review and renewal during
the year by the banks.

In 1998, Black Hills Coal Network acquired the assets of Coal Network,  Inc. and
Coal Niche,  Inc.  The Company  issued a  $1,240,000  note  payable to partially
finance the purchase.  Black Hills Capital Group provided credit support for the
1999 and 2000  principal  and  interest  payments  due under  this note  payable
totaling $1,100,000.

In addition to the above lines of credit,  Black Hills  Energy  Resources,  Inc.
(formerly  Wickford Energy  Marketing,  Inc.),  has a $65,000,000,  uncommitted,
discretionary credit facility consisting of a $50,000,000  transactional line of
credit and a $15,000,000  overdraft line of credit.  The  transactional  line of
credit provides credit support for the purchases of natural gas and crude oil of
Black  Hills  Energy  Resources.  The Company  and its  subsidiaries  provide no
guarantee  to the Lender.  At December 31,  1998,  and 1997,  Black Hills Energy
Resources had letters of credit  outstanding  of  $27,990,000  and  $29,000,000,
respectively, and no balance outstanding on the overdraft line of credit.

<PAGE>

In addition to the above lines of credit,  Wyodak  Resources  has  guaranteed  a
$15,000,000  line of credit for Enserco to use to  guarantee  letters of credit.
Enserco pays a 0.125  percent  facility fee on this line of credit.  At December
31, 1998 and 1997, there were no balances outstanding on this line of credit.

(5)   FAIR VALUE OF FINANCIAL INSTRUMENTS

Cash of the Company is invested in money  market  investments  such as municipal
put  bonds,   money  market  preferreds,   commercial  paper,   Eurodollars  and
certificates  of deposit.  The Company  considers all highly liquid  investments
with an original  maturity of three months or less to be cash  equivalents.  The
following  methods and assumptions  were used to estimate the fair value of each
class of the Company's financial instruments.

Cash and Cash Equivalents

The carrying amount  approximates  fair value due to the short maturity of these
instruments.

Available for Sale Securities

The fair value of the Company's  investments equals the quoted market price when
available  and a quoted  market price for similar  securities if a quoted market
price  is not  available.  The  Company  has  classified  all of its  marketable
securities as  available-for-sale as of December 31, 1998 and 1997, and the fair
value approximates cost.

Long-Term Debt 

The fair value of the  Company's  long-term  debt is  estimated  based on quoted
market rates for utility debt instruments  having similar maturities and similar
debt ratings. The Company's  outstanding bonds are either currently not callable
or are subject to  make-whole  provisions  which would  eliminate  any  economic
benefits for the Company to call and refinance the bonds.

The estimated fair values of the Company's financial instruments are as follows:

                                                1998
                                 (in thousands)
                                         Carrying     Fair
                                          Amount      Value
                                          ------      -----
Cash and cash equivalents               $ 14,764    $ 14,764
Securities available for sale:
  Corporate debt securities                1,997       1,997
  Federal, state and local
    agency obligations                    20,678      20,678
Long-term debt                           163,360     189,767

                                                1997
                                 (in thousands)
                                         Carrying     Fair
                                          Amount      Value
                                          ------      -----

Cash and cash equivalents               $16,774     $16,774
Securities available for sale:
  Corporate debt securities                 997         997
  Federal, state and local
    agency obligations                   12,972      12,972
Long-term debt                          164,691     189,649

(6)   WYODAK PLANT

The Company owns a 20 percent  interest and Pacific Power an 80 percent interest
in the Wyodak Plant (the Plant), a 330 megawatt  coal-fired  electric generating
station located in Campbell  County,  Wyoming.  Pacific Power is the operator of
the Plant.  The  Company  receives  20 percent of the  Plant's  capacity  and is
committed to pay 20 percent of its  additions,  replacements  and  operating and
maintenance  expenses.  As of December 31, 1998, the Company's investment in the
Plant  included  $72,979,000  in electric  plant and  $28,121,000 in accumulated
depreciation.   The  Company's  share  of  direct  expenses  of  the  Plant  was
$5,835,000,  $5,934,000,  and  $6,458,000 for the years ended December 31, 1998,
1997 and 1996, respectively,  and is included in the corresponding categories of
operating expenses in the accompanying consolidated statements of income. Wyodak
Resources  supplies coal to the Plant under an agreement expiring in 2013 with a
Pacific  Power  option to renew for 10 years.  This  coal  supply  agreement  is
collateralized  by a  mortgage  on and a  security  interest  in some of  Wyodak
Resources' coal reserves.  At December 31, 1998,  approximately  22,012,000 tons
were covered under this  agreement.  Wyodak  Resources'  sales to the Plant were
$23,228,000, $22,688,000, and $22,643,000 for the years ended December 31, 1998,
1997 and 1996, respectively.

<PAGE>

(7)   COMMITMENTS AND CONTINGENT LIABILITIES

MDU Power Sale

On January 1, 1997,  the  Company  began  service  under a ten year  contract to
supply up to 55 megawatts of electric  power and associated  energy  required by
MDU for its Sheridan,  Wyoming,  service territory. In both 1998 and 1997, MDU's
Sheridan  service area  experienced a 47 megawatt peak, and had a load factor of
approximately 57 percent.

Coal Obligations

In addition to the  22,012,000  tons of coal  reserved  under the  agreement  to
supply coal to the Wyodak Plant,  Wyodak Resources has reserved  25,125,000 tons
of coal under existing contracts.

Coal Leases

Wyodak  Resources'  mining rights to its coal are based upon four federal leases
and one state lease. The federal leases provide for a royalty of 12.5 percent of
the selling price of the coal. The state lease provides for a royalty,  approved
in 1998,  currently at 9 percent.  Wyodak Resources paid royalties in the amount
of $4,009,000, $3,969,000, and $3,995,000 in 1998, 1997, and 1996, respectively.
Each federal lease requires diligent development to produce at least one percent
of all recoverable  reserves within either 10 years from the respective dates of
the leases or 10 years from the date of  adjustment  of the  leases.  Each lease
further  requires a continuing  obligation  to mine,  thereafter,  at an average
annual  rate of at least one  percent of the  recoverable  reserves.  All of the
federal leases  constitute one logical mining unit which is treated as one lease
for the purpose of determining  diligent  development  and continuing  operation
requirements.

Pacific Power's Power Sales Agreement

In 1983 the Company  entered into a 40 year power  agreement  with Pacific Power
providing  for the purchase by the Company of 75 megawatts of electric  capacity
and energy from  Pacific  Power's  system.  The price paid for the  capacity and
energy is based on the  operating  costs of one of  Pacific  Power's  coal-fired
electric   generating   plants.   Costs   incurred  under  this  agreement  were
$17,458,000, $20,251,000, and $19,777,000 in 1998, 1997 and 1996, respectively.

Acquisition of Clovis Point Mine Properties

In 1996,  Wyodak  Resources  purchased  a portion of the  Clovis  Point and East
Gillette Mine properties from Kerr-McGee Coal Corporation. The Clovis Point Mine
properties  are  located  adjacent  to Wyodak  Resources'  current  reserves  in
Campbell  County,  Wyoming,  and consist of State of Wyoming and federal  leased
coal reserves.

Acquisition of the property in 1996 increased  Wyodak  Resources'  reserves from
170 million tons to approximately  288 million tons and included a train loadout
facility, maintenance and processing facilities and a developed open pit.

The purchase price consisted of the assumption of the  responsibility to reclaim
the existing Clovis Point open pit of which the Company  recorded a liability of
$7,957,000  and the payment of  overriding  royalties  to Kerr McGee if and when
coal is produced from the acquired properties. Wyodak Resources is not obligated
to mine the coal.

Reclamation

Under its mining permit,  Wyodak Resources is required to reclaim all land where
it has mined coal  reserves.  The cost of reclaiming  the land is accrued as the
coal is mined.  While the reclamation  process takes place on a continual basis,
much of the reclamation  occurs over an extended period after the area is mined.
Approximately $700,000 is charged to operations as reclamation expense annually.
As  of  December  31,  1998,   accrued   reclamation  costs  were  approximately
$17,000,000 which includes $7,957,000 for the Clovis Point Mine Acquisition.

Price Risk Management Activities

The Company  utilizes a variety of financial  instruments to hedge the impact of
price   fluctuations  on  its  oil  and  gas  production  and  energy  marketing
operations.  The Company does not hold or issue derivative financial instruments
for trading purposes.

<PAGE>

The primary  financial  instruments  the Company uses in managing its price risk
exposure are exchange  traded  natural gas futures  contracts,  over-the-counter
natural gas and crude oil swaps, collar and option contracts.  The Company would
be exposed to credit losses in the event of nonperformance by the counterparties
that have issued the financial instruments. The Company does not expect that the
counterparties  will  fail to meet  their  obligations,  based on the  Company's
review of the  financial  condition  of the  counterparties  and/or their credit
ratings.

The notional  quantities and maximum terms of derivative  financial  instruments
held for non-trading activities at December 31, 1998 are presented below:

                               Volume     Max.
                             Purchased    Term       Fair Value
                             (MMBtu's)   (Years)   (in thousands)
                             ---------   -------   --------------

Natural gas futures          
  contracts purchased        1,470,000      2           $(409)
Natural gas swap
  contracts purchased        7,989,096      3         $(2,601)
Natural gas swap
  contracts sold             1,473,000      1            $432

Because  these  contracts  are entered  into for hedging  purposes,  the Company
expects that the gains/(losses)  will be largely offset by gains (losses) on the
underlying  physical  transactions.  The  notional  amounts  detailed  above are
intended  to  be  indicative  of  the  Company's   level  of  activity  in  such
derivatives.

At December 31, 1997,  the Company had fixed rate for floating  rate price swaps
to hedge  crude oil price  risk for  15,000  barrels  of oil per month at prices
ranging from $19.00 per barrel to $20.93 per barrel which  expired  December 31,
1998.  In addition,  the Company had fixed rate for floating rate price swaps on
3.9 bcf of natural  gas to hedge  fixed  price  sales  commitments  in a similar
quantity.

Other 

The Company is subject to various  legal  proceedings  and claims which arise in
the ordinary course of operations.  In the opinion of management,  the amount of
liability, if any, with respect to these actions would not materially affect the
consolidated financial position or results of operations of the Company.

(8)   EMPLOYEE BENEFIT PLANS

The Company has a defined benefit pension plan (the Plan) covering substantially
all  employees.  The  benefits  are based on years of service  and  compensation
levels  during  the  highest  five  consecutive  years of the last ten  years of
service.  The  Company's  funding  policy  is in  accordance  with  the  federal
government's funding requirements. The Plan's assets consist primarily of equity
securities and cash equivalents.

In December  1998,  the  Company  adopted  FASB  Statement  No. 132  "Employers'
Disclosures about Pensions and Other  Postretirement  Benefits - an amendment of
FASB Statements No. 87, 88, and 106" which requires  revised  disclosures  about
pension and other postretirement benefit plans.

Net pension (income) expense for the Plan was as follows:

                             1998       1997        1996
                             ----       ----        ----
                                    (in thousands)

Service cost                $  895    $   931      $   874
Interest cost                2,406      2,383        2,239
Return on assets:
  Actual                    (2,007)   (10,278)      (4,477)
  Deferred                  (2,412)     7,022        1,502
                            ------      -----        -----
Net pension (income)       
  expense                  $(1,118)   $    58      $   138
                           =======    =======      =======

Actuarial assumptions:
  Discount rate               7.5%       7.5%         7.5%
  Expected long-term rate
   of return on assets       10.5%      10.5%        10.5%
  Rate of increase in      
   compensationn levels         5%         5%           5%


<PAGE>

Funding  information  for the Plan as of October 1 each year was as follows (the
discount  rate  assumption  for  obligations  at 1998 was  6.75% and at 1997 was
7.5%):

                                   1998         1997
                                   ----         ----
                                    (in thousands)

Fair value of plan assets        $40,638       $40,435
Projected benefit obligation     (39,490)      (33,025)
                                 -------       ------- 
                                   1,148         7,410
Unrecognized:
  Net gain                          (200)       (7,579)
  Prior service cost                 528           618
  Transition asset                  (180)         (271)
                                 -------       ------- 
Prepaid pension cost             $ 1,296       $   178
                                 =======       =======

Accumulated benefit obligation   $31,323       $27,133
                                 =======       =======

Vested benefit obligation        $29,829       $25,995
                                 =======       =======

A reconciliation  of the beginning and ending balances of the projected  benefit
obligation is as follows:

                                     1998    1997    1996
                                     ----    ----    ----
                                 (in thousands)
Beginning projected
  benefit obligation               $33,025  $32,722 $30,714
Service cost                           895      931     874
Interest cost                        2,406    2,383   2,239
Actuarial gains (losses)             4,968   (1,215)    603
Benefits paid                       (1,804)  (1,796) (1,708)
                                    ------   ------  ------ 
Net increase                         6,465      303   2,008
                                    ------   ------  ------
Ending projected
  benefit obligation               $39,490  $33,025 $32,722
                                   =======  ======= =======

A  reconciliation  of the fair value of plan assets as of October 1 of each year
is as follows:

                                     1998     1997
                                     ----     ----
                                     (in thousands)
Beginning market value
  of plan assets                    $40,435   $31,953
Benefits paid                        (1,804)   (1,796)
Investment income                     2,007    10,278
                                    -------   -------
Ending market value
  of plan assets                    $40,638   $40,435
                                    =======   =======

The Company has various supplemental  retirement plans for outside directors and
key executives of the Company. The plans are nonqualified defined benefit plans.
Expenses recognized under the plans were $395,000, $94,000 and $498,000 in 1998,
1997, and 1996, respectively.

The Company follows the provisions of SFAS No. 106,  "Employers'  Accounting for
Postretirement  Benefits Other Than  Pensions."  The standard  requires that the
expected cost of these benefits must be charged to expense during the years that
the  employees  render  service.  Prior to adopting  the  standard in 1993,  the
Company expensed these benefits as they were paid. The Company is amortizing the
transition obligation of $2,996,000 over a 20 year period.

Employees  retiring  from  the  Company  on or after  attaining  age 55 who have
rendered  at  least  five  years of  service  to the  Company  are  entitled  to
postretirement  healthcare  benefits  coverage.  These  benefits  are subject to
premiums,  deductibles,  copayment provisions and other limitations. The Company
may amend or change the plan  periodically.  The Company is not  pre-funding its
retiree medical plan.

The net periodic postretirement cost for the Company was as follows:

                       1998    1997    1996
                       ----    ----    ----
                          (in thousands)
Service cost            $135    $168    $166
Interest cost            290     329     304
Amortization of
transition               150     150     150
  obligation
Amortization of gain     (42)     (5)     (1)
                         ---      --      -- 
                        $533    $642    $619
                        ====    ====    ====

Funding information as of October 1 was as follows:

                                         1998    1997
                                        (in thousands)

Accumulated postretirement benefit
  obligation:
   Retirees                            $1,821  $1,588
   Fully eligible active participants   1,033     671
   Other active participants            2,576   1,668
                                        -----   -----
Unfunded accumulated postretirement
  benefit obligation                    5,430   3,927
Unrecognized net gain (loss)             (301)  1,067
Unrecognized transition              
obligation                             (2,097) (2,247)
                                       ------  ------ 
                                       $3,032  $2,747
                                       ======  ======

For  measurement  purposes,  a 9.0 percent annual rate of increase in healthcare
benefits was assumed for 1998;  the rate was assumed to decrease  gradually to 6
percent in 2005 and remain at that level  thereafter.  The healthcare cost trend
rate assumption has a significant effect on the amounts reported.  A one percent
increase in the healthcare cost trend  assumption would increase the service and
interest cost $95,000 or 22.2% and the net periodic postretirement cost $129,000
or 24.1%.  A one percent  decrease would reduce the service and interest cost by
$73,000 or 17.1% and decrease the net periodic  postretirement  cost $112,000 or
21.0%.  The  weighted-average  discount rate used in determining the accumulated
postretirement benefit obligation was 6.75 percent.

<PAGE>


(9)   INCOME TAXES

Income tax expense for the years indicated was:

                                            1998           1997           1996
                                            ----           ----           ----
                                                     (in thousands)
      Current                               $14,243       $11,869       $11,706
      Deferred                               (1,886)        3,107         2,533
      Tax credits, net                         (649)         (650)         (661)
                                            -------       -------       ------- 
                                            $11,708       $14,326       $13,578
                                            =======       =======       =======

The temporary  differences  which gave rise to the net deferred tax liability at
December 31, 1998 and 1997 were as follows:

                                                                    Net Deferred
                                                                       Income
                                                                      Tax Asset
December 31, 1998                          Assets      Liabilities   (Liability)
-----------------                          ------      -----------   -----------
                                                     (in thousands)
Accelerated depreciation and other
  plant-related differences                  $     -      $47,095      $(47,095)
Regulatory asset                               1,963            -         1,963
Regulatory liability                               -        1,392        (1,392)
Unamortized investment tax credits             1,230            -         1,230
Mining development and oil exploration         5,481        5,746          (265)
Employee benefits                              2,623          494         2,129
Other                                          1,050          380           670
                                             -------      -------      --------
                                             $12,347      $55,107      $(42,760)
                                             =======      =======      ======== 


                                                                    Net Deferred
                                                                       Income
                                                                      Tax Asset
December 31, 1997                          Assets      Liabilities   (Liability)
-----------------                          ------      -----------   -----------
                                                       (in thousands)
Accelerated depreciation and other
  plant-related differences                $       -      $45,508      $(45,508)
Regulatory asset                               2,136            -         2,136
Regulatory liability                               -        1,415        (1,415)
Unamortized investment tax credits             1,405            -         1,405
Mining development and oil exploration         1,417        5,342        (3,925)
Employee benefits                              2,426          103         2,323
Other                                            677          642            35
                                            --------      -------      --------
                                            $  8,061      $53,010      $(44,949)
                                            ========      =======      ======== 
<PAGE>


The  effective  tax rate differs from the federal  statutory  rate for the years
ended December 31, as follows:

                                             1998           1997           1996
                                             ----           ----           ----

Federal statutory rate                        35.0%         35.0%         35.0%
Regulatory asset recognition                  (0.7)         (1.3)         (1.7)
Amortization of investment tax credits        (1.3)         (1.1)         (1.5)
Tax-exempt interest income                    (1.1)         (0.9)         (0.6)
Percentage depletion in excess of cost        (1.7)         (0.7)         (0.5)
Other                                          1 .0         (0.3)          0.2
                                               ----         ----           ---
                                              31.2%         30.7%         30.9%
                                              ====          ====          ==== 

(10) OIL AND GAS RESERVES  (Unaudited)

Black Hills  Exploration  and  Production has interests in 572 producing oil and
gas properties in seven states.  Black Hills  Exploration  and  Production  also
holds leases on approximately 38,825 net undeveloped acres.

The  following  table  summarizes  Black  Hills   Exploration  and  Production's
quantities  of proved  developed and  undeveloped  oil and natural gas reserves,
estimated using constant  year-end product prices, as of December 31, 1998, 1997
and 1996,  and a  reconciliation  of the  changes  between  these  dates.  These
estimates are based on reserve  reports by Ralph E. Davis  Associates,  Inc. (an
independent engineering company selected by the Company). Such reserve estimates
are based upon a number of  variable  factors  and  assumptions  which may cause
these estimates to differ from actual results.

<TABLE>
<CAPTION>
                                       1998                1997                1996
                                   Oil       Gas       Oil       Gas       Oil      Gas
                                   ---       ---       ---       ---       ---      ---
                                     (in thousands of barrels of oil and MCF of gas)
<S>                                <C>      <C>        <C>     <C>        <C>       <C>
Proved developed and
undeveloped
  Reserves:
  Balance at beginning of year     2,495    9,052      2,386   10,972     1,612      7,658
   Production                       (353)  (2,068)      (299)  (1,747)     (286)    (1,718)
   Additions                       1,149   10,721      1,146    3,498       404      5,098
   Property sales                      -        -        (10)    (393)       (9)      (312)
   Revisions to previous estimates  (923)   (1,753)     (728)  (3,278)      665        246
                                    ----    ------      ----   ------       ---        ---

  Balance at end of year           2,368   15,952      2,495    9,052     2,386     10,972
                                   =====   ======      =====    =====     =====     ======

Proved developed reserves at
  end of Year included above        1,463   10,041      2,035    6,821     2,376     9,633
                                    =====   ======      =====    =====     =====     =====

Year-end prices                     $9.16    $1.93     $16.34    $2.32    $24.04     $3.20
                                    =====    =====     ======    =====    ======     =====

</TABLE>

In  December  1998,  Black  Hills   Exploration  and  Production   recognized  a
$13,546,000  pretax loss related to a write down of oil and gas properties.  The
write down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties.

<PAGE>

(11)   SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY'S BUSINESS

Effective  December  31,  1998 the  Company  adopted  FASB  Statement  No.  131,
"Disclosure  About  Segments of an Enterprise  and Related  Information."  Black
Hills Corporation's business segments include:  Electric which supplies electric
utility service to western South Dakota,  northeastern  Wyoming and southeastern
Montana;  Mining which engages in the mining and sale of coal from its mine near
Gillette, Wyoming; Oil and Gas which produces, explores and operates oil and gas
interests  located in the Rocky  Mountain  region,  Texas,  California and other
states;  Energy  Marketing  which  markets  natural gas,  oil,  coal and related
services to customers in the East Coast,  Midwest,  Southwest,  Rocky  Mountain,
West Coast and  Northwest  Regions  markets  and  Technology  and  Others  which
primarily markets communications and software development services.

Financial data for the business segments are as follows (in thousands):

<TABLE>
<CAPTION>
                                         Oil      Energy    Technology
                    Electric  Mining   and Gas   Marketing   & Others  Eliminations  Total
                    --------  ------   -------   ---------   --------  ------------  -----
       1998
-------------------
<S>                  <C>      <C>       <C>       <C>          <C>       <C>       <C>
Operating revenues  $129,236 $31,413   $12,562   $506,043     $2,437    $(2,437)   $679,254
Depreciation,
 depletion & amort.   14,881   3,252    18,760*       690          -          -      37,583*
Operating income
 (loss)               49,896  12,723   (12,340)        41     (1,087)         -      49,233
Interest expense      13,572       9       355        731         40          -      14,707
Income taxes          12,612   4,092    (4,689)      (116)      (191)         -      11,708
Net income (loss)     24,825   9,585    (7,976)      (346)      (280)         -      25,808
Current assets        43,760  25,538     1,335     77,401      6,406    (13,960)    140,480
Total assets         451,404  93,140    26,666     86,300     18,838   (116,931)    559,417
Property additions    11,451   1,447    10,169        424      1,774          -      25,265
Increase in goodwill       -       -         -      1,960          -          -       1,960

</TABLE>

* Includes the impact of a $13,546  pretax write down of certain oil and natural
gas properties.

 <TABLE>
<CAPTION>
                                         Oil      Energy    Technology
                    Electric  Mining   and Gas   Marketing   & Others  Eliminations  Total
                    --------  ------   -------   ---------   --------  ------------  -----
       1997
-------------------
<S>                  <C>      <C>       <C>       <C>          <C>       <C>        <C>
Operating revenues   $126,497 $31,080  $13,295    $142,790     $685      $(685)     $313,662
Depreciation,
  depletion & amort.   14,608   3,188    4,275         240        -          -        22,311
Operating income
  (loss)               44,611  12,217    2,907        (825)    (471)         -        58,439
Interest expense       13,676       5      203         203       36          -        14,123
Income taxes            9,929   4,205      629        (347)     (90)         -        14,326
Net income (loss)      22,106   9,073    2,147        (749)    (218)         -        32,359
Current assets         35,987  17,227    2,009      34,403    6,116    (11,733)       84,009
Total assets          445,840  89,665   31,449      41,211   15,888   (115,312)      508,741
Property additions     12,484   1,336    7,076           -      191          -        21,087
Increase in goodwill        -       -        -       7,232        -          -         7,232
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                                          Oil      Energy     Technology
                      Electric  Mining   and Gas   Marketing   & Others  Eliminations  Total
                      --------  ------   -------   ---------   --------  ------------  -----
       1996
-------------------
<S>                   <C>       <C>       <C>       <C>          <C>       <C>         <C>
Operating revenues    $118,718  $31,315   $12,555        -      $685       $(685)      $162,588
Depreciation,
  depletion & amort.    16,104    2,981     3,709        -        24         (24)        22,794
Operating income
 (loss)                 39,090   12,234     2,981        -      (237)        237         54,305
Interest expense        13,814        1        98        -        29           -         13,942
Income taxes             7,887    5,024       715        -       (48)          -         13,578
Net income (loss)       18,333    9,934     2,198     (126)      (87)          -         30,252
Current assets          30,345   20,325     3,796        -       385      (3,854)        50,997
Total assets           432,667   77,671    29,131     (123)      604     (72,596)       467,354
Property additions      12,634    2,118     9,585        -        51           -         24,388

</TABLE>

Detailed  revenues  by product  sold and  business  segment  are as follows  (in
thousands):

<TABLE>
<CAPTION>
                                        Oil      Energy   Technology
                   Electric  Mining   and Gas  Marketing   & Others  Eliminations  Total
                   --------  ------   -------  ---------   --------  ------------  -----
       1998
-------------------
<S>                <C>       <C>      <C>      <C>         <C>         <C>        <C>
Electric revenues  $129,236  $    -   $    -   $       -   $      -    $     -    $129,236
Coal revenues             -  31,413        -      12,924          -          -      44,337
Gas revenues              -       -    4,073     375,136          -          -     379,209
Oil revenues              -       -    5,131     117,185          -          -     122,316
Other revenues            -       -    3,358         798      2,437     (2,437)      4,156
                   -------- -------  -------    --------     ------    -------    -------- 
Total              $129,236 $31,413  $12,562    $506,043     $2,437    $(2,437)   $679,254
                   ======== =======  =======    ========     ======    =======    ========

</TABLE>


<TABLE>
<CAPTION>
                                        Oil      Energy    Technology
                   Electric  Mining   and Gas   Marketing   & Others  Eliminations  Total
       1997
-------------------
<S>                <C>       <C>      <C>       <C>         <C>         <C>        <C>
Electric revenues  $126,497 $     -   $     -   $      -     $    -    $     -    $126,497
Coal revenues            -   31,080         -          -          -          -      31,080
Gas revenues             -        -     4,223     94,295          -          -      98,518
Oil revenues             -        -     5,540     48,495          -          -      54,035
Other revenues           -        -     3,532          -        685       (685)      3,532
                   -------- -------   -------   --------       ----      -----    --------
Total              $126,497 $31,080   $13,295   $142,790       $685      $(685)   $313,662
                   ======== =======   =======   ========       ====      =====    ========

</TABLE>

<TABLE>
<CAPTION>
                                       Oil      Energy   Technology
                   Electric Mining   and Gas  Marketing   & Others  Eliminations  Total
       1996
-------------------
<S>                <C>       <C>      <C>       <C>         <C>         <C>        <C>
Electric revenues  $118,718 $     -  $      -    $     -    $     -     $    -    $118,718
                                  -         -
Coal revenues            -   31,315         -          -          -          -      31,315
Gas revenues             -        -     3,523          -          -          -       3,523
Oil revenues             -        -     5,527          -          -          -       5,527
Other revenues           -        -     3,505          -          -          -       3,505
                   -------- -------  --------    -------    -------     ------    --------
Total              $118,718 $31,315  $ 12,555    $     -    $     -     $    -    $162,588
                   ======== =======  ========    =======    =======     ======    ========

</TABLE>

<PAGE>

(12)   SUPPLEMENTARY INCOME STATEMENT INFORMATION

Taxes Other than Income Taxes

                                            1998           1997           1996
                                            ----           ----           ----
                                                     (in thousands)

      Property                             $ 4,993      $  4,326      $  4,368
      Production and severance               3,437         3,654         4,105
      Payroll                                1,348         1,332         1,307
      Black lung                             1,324         1,310         1,320
      Federal reclamation                    1,148         1,138         1,135
      Other                                    222           225           225
                                           -------       -------       -------
                                           $12,472       $11,985       $12,460
                                           =======       =======       =======

<PAGE>



FINANCIAL STATISTICS
<TABLE>
<CAPTION>
Years ended December 31,                          1998        1997      1996      1995       1994
------------------------                          ----        ----      ----      ----       ----
<S>                                              <C>         <C>       <C>       <C>       <C>    
TOTAL ASSETS (in thousands)                      $559,417    $508,741 $467,354   $448,830  $436,877

PROPERTY AND INVESTMENTS
     (in thousands)
   Total property and investments                $619,549    $598,306 $581,537   $557,642  $519,296
   Accumulated depreciation and depletion         229,942     197,179  181,103    164,383   156,046
   Capital expenditures (includes AFDC)            27,225      28,319   24,388     51,895   103,059

CAPITALIZATION (in thousands)
   Long-term debt                                $162,030    $163,360 $164,691   $166,069  $128,925
   Common stock equity                            206,666     205,403  193,175    182,342   175,410
                                                  -------     -------  -------    -------   -------

      Total capitalization                       $368,696    $368,763 $357,866   $348,411  $304,335
                                                 ========    ======== ========   ========  ========

CAPITALIZATION RATIOS
   Long-term debt                                   43.9%       44.3%    46.0%      47.7%     42.4%
   Common stock equity                              56.1        55.7     54.0       52.3      57.6
                                                    ----        ----     ----       ----      ----
      Total                                        100.0%      100.0%   100.0%     100.0%    100.0%
                                                   =====       =====    =====      =====     ===== 

AVERAGE INTEREST RATE ON LONG-
TERM DEBT                                            8.1%        8.1%     8.1%       8.1%      8.5%

NET INCOME AVAILABLE FOR
   COMMON STOCK (in thousands)                   $25,808*    $32,359  $30,252    $25,590   $23,805

DIVIDENDS PAID IN COMMON STOCK
   (in thousands)                                $21,737     $20,540  $19,930    $19,312   $18,920

COMMON STOCK DATA (in thousands)**

   Shares outstanding, average                    21,623      21,692   21,660     21,614    21,509
   Shares outstanding, end of year                21,578      21,705   21,675     21,638    21,579

   Earnings per average share, in dollars          $1.19*      $1.49    $1.40      $1.19     $1.11
   Dividends paid per share, in dollars            $1.00       $0.95    $0.92      $0.89     $0.88
   Book value per share, end of year, in dollars   $9.58       $9.46    $8.91      $8.43     $8.13

RETURN ON COMMON STOCK 
EQUITY (year-end)                                  12.5%*      15.8%    15.7%      14.0%     13.6%

ALLOWANCE FOR FUNDS USED
   DURING CONSTRUCTION AS
   PERCENT OF NET INCOME                            0.9%        0.6%     1.2%      22.9%     16.7%
</TABLE>

 *    Includes impact of $8.8 million, or 41 cents per average share, write down
      of certain oil and gas properties.

**Common Stock Data reflects the 3-for-2 stock split on March 10, 1998.

<PAGE>



ELECTRIC OPERATION STATISTICS
<TABLE>
<CAPTION>
Years ended December 31,                 1998      1997       1996      1995       1994
------------------------                 ----      ----       ----      ----       ----
<S>                                    <C>        <C>        <C>         <C>       <C>
ELECTRIC ENERGY GENERATED AND
   PURCHASED (megawatt hours)
   Generated, net station output      1,870,247  1,803,350  1,659,671   1,320,630  1,108,530
   Purchased and net interchange        500,319    503,242    380,106     473,175    595,872
                                      ---------  ---------  ---------   ---------  ---------
     Total generated and purchased    2,370,566  2,306,592  2,039,777   1,793,805  1,704,402
   Company use and losses               (76,131)   (94,633)   (80,106)    (87,512)   (65,651)
   ----------------------             ---------  ---------  ---------   ---------  ---------
     Total electric energy sales      2,294,435  2,211,959  1,959,671   1,706,293  1,638,751
                                      =========  =========  =========   =========  =========

ELECTRIC ENERGY SALES
   (megawatt hours)
   Residential                           392,637   392,059    406,658     383,929    368,953
   General and commercial                561,292   547,624    541,463     513,854    495,909
   Industrial                            527,157   556,554    555,601     552,829    583,258
   Public authorities                     24,356    22,583     25,083      23,164     23,051
   Sales for resale                      417,889   413,527    181,766     171,942    166,580
                                       --------- ---------  ---------   ---------  ---------
      Total firm electric energy sales 1,923,331 1,932,347  1,710,571   1,645,718  1,637,751
   Non-firm sales                        371,104   279,612    249,100      60,575      1,000
                                       --------- ---------  ---------   ---------  ---------
     Total electric energy sales       2,294,435 2,211,959  1,959,671   1,706,293  1,638,751
                                       ========= =========  =========   =========  =========

ELECTRIC REVENUE (in thousands)
   Residential                            32,336    32,178     33,230      30,433     28,574
   General and commercial                 42,221    41,452     41,307      37,663     35,390
   Industrial                             25,713    26,802     26,915      26,495     27,318
   Public authorities                      1,944     1,843      1,970       1,775      1,718
   Sales for resale                       15,782    16,181      8,189       7,625      7,460
                                         -------   -------    -------     -------    -------
      Total firm electric revenue        117,996   118,456    111,611     103,991    100,460
   Non-firm electric revenue               6,002     3,760      2,985         741          -
   Other electric revenue                  5,238     4,281      4,122       4,051      4,296
                                        --------  --------   --------    --------   --------
     Total electric revenue             $129,236  $126,497   $118,718    $108,783   $104,756
                                        ========  ========   ========    ========   ========

ELECTRIC CUSTOMERS (end of year)
   Residential                            46,967    46,656     46,146      45,886     45,060
   General and commercial                  9,703     9,431      9,280       8,958      8,732
   Industrial                                 44        39         37          35         36
   Public authorities                        140       141        137         138        130
   Other electric utilities                    2         2          1           1          1
                                          ------    ------     ------      ------     ------
     Total electric customers             56,856    56,269     55,601      55,018     53,959
                                          ======    ======     ======      ======     ======

</TABLE>
<PAGE>

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE

No change of accountants or disagreements on any matter of accounting principles
or practices or financial statement disclosure have occurred.

PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information  regarding  the directors of the Company is  incorporated  herein by
reference to the Proxy Statement for the Annual Shareholders' Meeting to be held
May 11, 1999.

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, 52, Chairman, President and Chief Executive Officer of Black
Hills  Corporation Mr.  Landguth was elected to his present  position in January
1991.

Roxann R.  Basham,  37, Vice  President - Finance  and  Secretary/Treasurer  

Ms. Basham was elected to her present  position in December 1997. She had served
as Secretary/Treasurer since 1993.

David R. Emery, 36, Vice President - Fuel Resources

Mr. Emery was elected to his present  position in January 1997. He had served as
General  Manager of Black Hills  Exploration  and Production  (formerly  Western
Production Company) since June 1993.

Gary R. Fish, 40, Vice President - Corporate Development

Mr. Fish was elected to his present  position in October  1996. He had served as
Controller since 1988.

Everett E. Hoyt, 59, President and Chief Operating Officer of Black Hills Power

Mr. Hoyt was elected to his present position in October 1989.

James M. Mattern, 44, Vice President - Corporate Administration and Assistant to
the CEO

Mr. Mattern was elected to his present position in September 1997. He had served
as Vice President - Corporate  Administration  since January 1994 and had served
as Director of Human Resources since 1991.

Thomas M. Ohlmacher, 47, Vice President - Power Supply

Mr.  Ohlmacher was elected to his present position in August 1994. He had served
as Director of Power Generation since 1993.

Mark T. Thies, 35, Controller

Mr. Thies was elected to his present position in May 1997. Previously, Mr. Thies
had served in a number of  accounting  positions,  most  recently  as  Assistant
Controller,   at  InterCoast  Energy  Company,  a  wholly  owned  subsidiary  of
MidAmerican Energy Holdings Company since 1990.

Kyle D. White, 39, Vice President - Marketing and Regulatory Affairs

Mr.  White was  elected to his present  position in July 1998.  He had served as
Vice  President - Energy  Services since January 1998 and had served as Director
of Strategic Marketing and Sales since 1993.

<PAGE>

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 11, 1999.

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 11, 1999.

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 11, 1999.

PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)   1.  Consolidated Financial Statements

     Financial  statements  required by Item 14 are listed in the index included
in Item 8 of Part II.

      2.  Schedules

     All schedules  have been omitted  because of the absence of the  conditions
under which they are  required or because the required  information  is included
elsewhere  in the  financial  statements  incorporated  by reference in the Form
10-K.

      3.  Exhibits

          *3(a)     Restated  Articles  of  Incorporation  dated  May  24,  1984
                    (Exhibit 3(I) to Form 8-K dated June 7, 1994, File No.
                    1-7978).

          *3(b)     Bylaws dated  January 30, 1997.  (Exhibit  3(b) to Form 10-K
                    for 1997.)

          *4(a)     Reference  is made to  Article  Fourth  (7) of the  Restated
                    Articles  of  Incorporation  of the  Company  (Exhibit  3(a)
                    hereto).

          *4(b)     Indemnification  Agreement  and Company and  Directors'  and
                    Officers'  indemnification  insurance  (Exhibit 4(b) to Form
                    10-K for 1987).

          *4(c)     Indenture of Mortgage and Deed of Trust,  dated September 1,
                    1941, and as amended by supplemental  indentures  (Exhibit B
                    to Form A-2,  File No.  2-4832);  (Exhibit  7-B to Form S-1,
                    File  No.  2-6576);  (Exhibit  7-C to  Form  S-1,  File  No.
                    2-7695);  (Exhibit  7-D  to  Form  S-1,  File  No.  2-8157);
                    (Exhibit 4.05(e) to Form S-3, File No.  33-54329);  (Exhibit
                    4-I to Form S-1, File No. 2-9433); (Exhibit 4-H to Form S-1,
                    File  No.  2-13140);  (Exhibit  4-I to Form  S-1,  File  No.
                    2-14829);  (Exhibits  4-J  and  4-K to Form  S-1,  File  No.
                    2-16756);  (Exhibits 4-L, 4-M, and 4-N to Form S-1, File No.
                    2-21024);  (Exhibits 2(q),  2(r), 2(s), 2(t), 2(u), and 2(v)
                    to Form S-7, File No. 2-57661);  (Exhibit  4.05(t),  4.05(u)
                    and 4.05(v) to Form S-3, File No.  33-54329);  (Exhibit 4(b)
                    to Form S-3, File No. 2-81643);  (Exhibit 4.05(x),  4.05(y),
                    and 4.05(z) to Form S-3, File No.  33-54329);  (Exhibit 4(d)
                    and 4(e) to Post-Effective Amendment No. 1 to Form S-8, File
                    No. 33-15868); and (Exhibit 4.05(ac), 4.05(ad), and 4.05(ae)
                    to Form S-3, File No. 33-54329).

<PAGE>

           *4(d)    Indentures  of  Trust  dated  as of  June 1,  1992,  City of
                    Gillette,  Campbell County, Wyoming;  Lawrence County, South
                    Dakota;  Pennington  County,  South  Dakota;  Weston  County
                    Wyoming;  and  Campbell  County,  Wyoming;  to Norwest  Bank
                    Minnesota, National Association, as Trustee (Exhibits 10(n),
                    10(q), 10(s), 10(u), and 10(w), to Form 10-K for 1992).

           *10(a)   Agreement  for  Transmission  Service  and The Common Use of
                    Transmission  Systems  dated  January  1,  1986,  among  the
                    Company, Basin Electric Power Cooperative, Rushmore Electric
                    Power Cooperative,  Inc.,  Tri-County Electric  Association,
                    Inc.,  Black  Hills  Electric  Cooperative,  Inc.  and Butte
                    Electric  Cooperative,  Inc. (Exhibit 10(d) to Form 10-K for
                    1987).

           *10(b)   Restated and Amended Coal Supply  Agreement  for NS #2 dated
                    February 12, 1993 (Exhibit 10(c) to Form 10-K for 1992).

           *10(c)   Coal Leases between Wyodak Resources Development Corp. and
                    the Federal Government -Dated May 1, 1959,  (Exhibit 5(i) to
                    Form S-7,  File No.  2-60755)  -Modified  January  22,  1990
                    (Exhibit  10(h) to Form 10-K for 1989)  -Dated April 1, 1961
                    (Exhibit  5(j) to Form  S-7,  File  No.  2-60755)  -Modified
                    January  22,  1990  (Exhibit  10(i) to Form  10-K for  1989)
                    -Dated  October 1, 1965  (Exhibit 5(k) to Form S-7, File No.
                    2-60755)  -Modified  January 22, 1990 (Exhibit 10(j) to Form
                    10-K for 1989)

           *10(d)   Further  Restated and Amended Coal Supply  Agreement dated
                    May 5, 1987 between Wyodak Resources  Development  Corp. and
                    Pacific  Power & Light Company  (Exhibit  10(k) to Form 10-K
                    for 1987).

           *10(e)   Second  Restated  and Amended  Power Sales  Agreement  dated
                    September  29,  1997,  between  PacifiCorp  and the  Company
                    (Exhibit 10(e) to Form 10-K for 1997).

           *10(f)   Coal Supply  Agreement for Wyodak Unit #2 dated  February 3,
                    1983,  and  Ancillary  Agreement  dated  February  3,  1982,
                    between Wyodak Resources Development Corp. and Pacific Power
                    & Light Company and the Company  (Exhibit 10(o) to Form 10-K
                    for 1983). Amendment to Agreement for Coal Supply for Wyodak
                    #2 dated May 5, 1987 (Exhibit 10(o) to Form 10-K for 1987).

           *10(g)   Third   Restated   Electric  Power  and  Energy  Supply  and
                    Transmission Agreement dated January 1, 1998, by and between
                    the Company and the City of Gillette, Wyoming (Exhibit 10(g)
                    to Form 10-K for 1997).

           *10(h)   Reserve  Capacity  Integration  Agreement dated May 5, 1987,
                    between  Pacific  Power &  Light  Company  and  the  Company
                    (Exhibit 10(u) to Form 10-K for 1987).

           *10(i)   Compensation Plan for Outside  Directors  (Exhibit 10(bb) to
                    Form 10-K for 1992).

           *10(j)   The Amended and Restated Pension  Equalization Plan of Black
                    Hills Corporation dated January 27, 1995 (Exhibit 10 (ad) to
                    Form 10-K for 1994).

<PAGE>

           *10(k)   The  Amended  and  Restated  Pension  Plan of Black  Hills
                    Corporation (Exhibit 10 (ad) to Form 10-K for 1994).


           *10(l)   Agreement for Supplemental  Pension Benefit for Everett E.
                    Hoyt dated January 20, 1992 (Exhibit 10(gg) to Form 10-K for
                    1992).

           *10(m)   Power  Integration  Agreement,  dated  September  9, 1994,
                    between  the  Company and  Montana-Dakota  Utilities  Co., a
                    Division of MDU Resources  Group,  Inc.  (Exhibit  10(gg) to
                    Form 8-K dated September 12, 1994, File No. 1-7978).

           *10(n)   Change in Control  Agreements  dated  January 30, 1996 for
                    Daniel P. Landguth,  Everett E. Hoyt,  Thomas M.  Ohlmacher,
                    James M. Mattern, Roxann R. Basham and Gary R. Fish (Exhibit
                    10(af) to Form 10-K for 1995).  Change in Control  Agreement
                    dated  February 1, 1997 for David R. Emery (Exhibit 10(p) to
                    Form 10-K for 1997).  Change in Control  Agreement dated May
                    1, 1997 for Mark T.  Thies  (Exhibit  10(q) to Form 10-K for
                    1997).  Change in Control  Agreement dated December 31, 1997
                    for Kyle D. White (Exhibit 10(r) to Form 10-K for 1997).

           *10(o)   Marketing,  Capacity and Storage Service  Agreement  between
                    Black Hills  Corporation  and PacifiCorp  dated September 1,
                    1995 (Exhibit 10(ag) to Form 10-K for 1995).

           *10(p)   Black Hills  Corporation  1996 Stock Option Plan  (Exhibit
                    10(s) to Form 10-K for 1997).

           *10(q)   The  Outside  Directors  Stock  Based  Compensation  Plan
                    (Exhibit 10(t) to Form 10-K for 1997).

           *10(r)   Assignment  of  Mining   Leases  and  Related   Agreement
                    effective May 27, 1997, between Wyodak Resources Development
                    Corp.  and  Kerr-McGee  Coal  Corporation.  Included in this
                    Agreement   are  coal  leases   between   Wyodak   Resources
                    Development  Corp. and the Federal  Government and the State
                    of Wyoming,  as modified by the decision  dated May 27, 1997
                    from the U.S.  Department  of the  Interior - Bureau of Land
                    Management (Exhibit 10(u) to Form 10-K for 1997).

            10(s)   Officers 1998 Short-Term Incentive Plan.

      21  Subsidiaries of the Registrant.

      23a Consent  of  Independent  Public  Accountants  with  respect to Annual
          Report on Form 10-K.

      23b Consent  of  Independent  Public  Accountants  with  respect to Annual
          Report on Form 11-K.

      27  Financial Data Schedule.

      99  Annual  Report on Form 11-K of the Black  Hills  Corporation  Employee
          Stock Purchase Plan for the year ended December 31, 1998.


      *   Exhibits incorporated by reference.

(c)   See (a) 3. above.
(d)   See (a) 2. above.

<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 Officer

Dated:    March 9, 1999


     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
Registrant and in the capacities and on the dates indicated.

/s/ DANIEL P. LANDGUTH                Director and Principal       March 9, 1999
Daniel P. Landguth, Chairman,         Executive Officer
President, and Chief Executive Officer

/s/ ROXANN R. BASHAM                  Principal Financial Officer  March 9, 1999
Roxann R. Basham, Vice President-Finance,
and Corporate Secretary/Treasurer

/s/ MARK T. THIES                     Principal Accounting Officer March 9, 1999
Mark T. Thies, Controller

/s/ ADIL M. AMEER                     Director                     March 9, 1999
Adil M. Ameer

/s/ GLENN C. BARBER                   Director                     March 9, 1999
Glenn C. Barber

/s/ BRUCE B. BRUNDAGE                 Director                     March 9, 1999
Bruce B. Brundage

/s/ DAVID C. EBERTZ                   Director                     March 9, 1999
David C. Ebertz

/s/ JOHN R. HOWARD                    Director                     March 9, 1999
John R. Howard

/s/ EVERETT E. HOYT                   Director and Officer         March 9, 1999
Everett E. Hoyt (President and Chief
Operating Officer of Black Hills Power)

/s/ KAY S. JORGENSEN                  Director                     March 9, 1999
Kay S. Jorgensen

/s/ THOMAS J. ZELLER                  Director                     March 9, 1999
Thomas J. Zeller

<PAGE>

BOARD OF DIRECTORS AND OFFICERS


BOARD OF DIRECTORS                        OFFICERS

Daniel P. Landguth                      Daniel P. Landguth
  Chairman of the Board, President and    Chairman of the Board,President and
  Chief Executive Officer of the Compan    Chief Executive Officer

Adil M. Ameer                           Roxann R. Basham
  President and Chief Executive Officer   Vice President - Finance and
  Rapid City Regional Hospital            Corporate Secretary/Treasurer

Glenn C. Barber                         David R. Emery
  President and Chief Executive Officer   Vice President - Fuel Resources
  Glenn C. Barber & Associates, Inc.

Bruce B. Brundage                       Gary R. Fish
  President and Director                  Vice President-      
  Brundage & Company                      Corporate Development

David C. Ebertz                         Everett E. Hoyt
  President                               President and Chief Operating Officer
  Barlow Agency, Inc.                     Black Hills Power and Light Company

John R. Howard                          James M. Mattern
  President                              Vice President-Corporate Administration
  Industrial Products, Inc.              and Assistant to the CEO

Everett E. Hoyt                         Thomas M. Ohlmacher
  President and Chief Operating Officer   Vice President-Power Supply
  Black Hills Power and Light Company

Kay S. Jorgensen                        Mark T. Thies
  Owner - Jorgensen-Thompson              Controller
  Creative Broadcast Services

Thomas J. Zeller                        Kyle D. White
  President                               Vice President-Marketing and
  RE/SPEC Inc.                            Regulatory Affairs