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

   X     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 
         EXCHANGE ACT OF 1934 [FEE REQUIRED]
       
         For the fiscal year ended December 31, 1995

         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
         EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

         For the transition period from  ___________ to ___________

         Commission file Number 1-7978

                             BLACK HILLS CORPORATION
         Incorporated in South Dakota     IRS Identification Number 46-0111677
                                625 Ninth Street
                          Rapid City, South Dakota 57709

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

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

                                                    NAME OF EACH EXCHANGE
            TITLE OF EACH CLASS                     ON WHICH REGISTERED
       Common stock of $1.00 par value             New York Stock Exchange

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

                                    Yes   X      No

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

       State the aggregate market value of the voting stock held by           
       non-affiliates of the Registrant.
                       At February 29, 1996       $370,052,400

       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 29, 1996
       Common stock, $1.00 par value                   14,433,686 shares

       DOCUMENTS INCORPORATED BY REFERENCE

       1.  Definitive Proxy Statement of the Registrant filed pursuant to
           Regulation 14A for the 1996 Annual Meeting of Stockholders to be
           held on May 21, 1996, is incorporated by reference in Part III.
<PAGE>


                               TABLE OF CONTENTS
                                                                          PAGE

ITEM  1.  BUSINESS                                                           4
          GENERAL                                                            4 
          ELECTRIC POWER SUPPLY                                              4
          ELECTRIC SERVICE TERRITORY AND SALES                               6
          COMPETITION IN ELECTRIC UTILITY BUSINESS                           7
          COAL SALES                                                         7
          OIL AND GAS OPERATIONS                                             8
          ENVIRONMENTAL REGULATION                                           9
          EMPLOYEES                                                         11

ITEM  2.  PROPERTIES                                                        11
          UTILITY PROPERTIES                                                11
          MINING PROPERTIES                                                 12
          OIL AND GAS PROPERTIES                                            13

ITEM  3.  LEGAL PROCEEDINGS                                                 13

ITEM  4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS               13

ITEM  5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
          STOCKHOLDER MATTERS                                               14

ITEM  6.  SELECTED FINANCIAL DATA                                           14

ITEM  7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
           CONDITION AND RESULTS OF OPERATIONS                              15
          LIQUIDITY AND CAPITAL RESOURCES                                   15
          RATE REGULATION                                                   16
          COMPETITION IN ELECTRIC UTILITY BUSINESS                          18
          RESULTS OF OPERATIONS                                             20

ITEM  8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                       25

ITEM  9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
          ACCOUNTING AND FINANCIAL DISCLOSURE                               40

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT                40

ITEM 11.  EXECUTIVE COMPENSATION                                            40

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT    40

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                    40

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON 
          FORM 8-K                                                          41

SIGNATURES                                                                  44

<PAGE>
                                DEFINITIONS

       WHEN THE FOLLOWING TERMS ARE USED IN THE TEXT THEY WILL HAVE THE
       MEANINGS INDICATED.

           TERM                             MEANING

       Black Hills        Black Hills Power and Light Company, the assumed
       Power              business name of the Company under which its electric
                          operations are conducted

       Basin Electric     Basin Electric Power Cooperative, Inc., a rural
                          electric cooperative engaged in generating and 
                          transmitting electric power to its member RECs

       Company            Black Hills Corporation

       DEQ                Department of Environmental Quality of the State of
                          Wyoming

       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

       NS #2              Neil Simpson Unit #2, an 80 megawatt coal-fired power
                          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 of the Department of
                          Energy of the United States of America

       WPSC               The Wyoming Public Service Commission

       Western            Western Production Company, a wholly owned
       Production         subsidiary of Wyodak Resources

       Wyodak Resources   Wyodak Resources Development Corp., a wholly owned
                          subsidiary of the Company

       Wyodak Plant       A 330 megawatt coal-fired electric generating plant
                          which is owned 20 percent by the Company and 80 
                          percent by Pacific Power and located near Gillette,
                          Wyoming

<PAGE>
                                       PART I
       ITEM 1. BUSINESS
                                       GENERAL

            Incorporated under the laws of South Dakota in 1941, the Company is
       an energy services company primarily consisting of three principal
       businesses:  electric, coal mining and oil and gas production.  The
       Company operates its public utility electric operations under the
       assumed name of Black Hills Power and Light Company, its coal mining
       operations through its subsidiary Wyodak Resources and its oil and gas
       exploration and production through Western Production.

            Black Hills Power is engaged in the generation, purchase,
       transmission, distribution and sale of electric power and energy to
       approximately 55,000 customers in 11 counties in western South Dakota,
       northeastern Wyoming and southeastern Montana, 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.
       The coal seam varies in thickness from 70 to 110 feet, averages 90 feet
       and is located approximately five miles east of Gillette, Wyoming, in
       the Powder River Basin.

            Acquired by Wyodak Resources in 1986, Western Production is an oil
       and gas exploration and production company with interests located in the
       rocky mountain region, Texas, California and various other locations.

            Information as to the continuing lines of business of the Company
       for the calendar years 1993-1995 is as follows:
<TABLE>
<CAPTION>
                                         1995        1994       1993
                                               (in thousands)
       <S>                              <C>        <C>         <C>
       Revenue from sales to
       unaffiliated customers:
         Electric                       $108,563   $104,431    $97,885
         Coal mining                      19,372     19,149     19,775
         Oil and gas                      11,164     12,052     11,396

       Revenue from intercompany
       sales:
         Electric                        $   220     $  325    $   270
         Coal mining                      10,498      9,445     10,047
</TABLE>

            For additional information relating to the Company's operations see
       Note 11 of "Notes to Consolidated Financial Statements" on page 37.

                               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 298 megawatts
       was reached in August 1995.  Approximately 45 megawatts of additional
       load will occur in 1997 when Black Hills Power begins serving MDU's
       Sheridan, Wyoming, electric service territory.  (See Wholesale to MDU on
       page 6.)  In addition, Black Hills Power estimates its required reserves
       at 82 megawatts.  Black Hills Power is not a member of a power pool.

            Black Hills Power owns coal-fired generating units having a summer
       capability rating of 214 megawatts and 77 megawatts of oil-fired diesel
       and combustion turbines for peaking and standby use.  Black Hills
       purchases additional resources from three contracts with Pacific Power:
       the Pacific Power Colstrip contract, from which it purchases 75
       megawatts of baseload power; the Reserve Capacity Integration Agreement,
       from which 33 megawatts of additional reserve capacity is available;
       and the Pacific Power Capacity Contract, under which Black Hills Power
       has options to be exercised seasonally to purchase from 0 to 60 
       megawatts of capacity.
<PAGE>

       PACIFIC POWER COLSTRIP CONTRACT

            This contract 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.  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 based on
       Pacific Power's costs in Units 3 and 4 of the Colstrip coal-fired
       generating plant near Colstrip, Montana, together with a fixed payment
       for transmission.  The Company has incurred capacity charges of $18,000
       per megawatt month and an average energy charge of $14.55 per megawatt
       hour over the last three years of this agreement with a 59 percent load
       factor.  The Company anticipates better utilization of this resource in
       the future and lowering the average cost per megawatt hour through an
       active marketing program to sell the energy.

       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 CAPACITY CONTRACT AND SETTLEMENT OF CLAIM

            On September 1, 1995, Black Hills Power and Pacific Power entered
       into the Pacific Power Capacity Contract.  This contract was the result
       of an agreement to settle a complaint filed by Black Hills Power against
       Pacific Power before the FERC claiming that since 1987 Pacific Power
       used an incorrect formula resulting in an overcharge to Black Hills
       Power of approximately $490,000 a year for capacity from the Pacific
       Power Colstrip Contract.  In addition to agreeing to the Pacific Power
       Capacity Contract, Pacific Power agreed that commencing July 1, 1995 and
       continuing for the remaining 23 years during which capacity payments are
       to be made, the formula will be corrected which will result in the
       $490,000 per year reduction during said period of time.

            Under the contract, Pacific Power granted Black Hills an option to
       be exercised for each six-month season for a period commencing
       October 1, 1996 and ending March 31, 2007 to purchase from 0 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.

            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 equal to the difference in Black Hills' Resources (all
       energy from Black Hills Power's generating resources and energy
       entitlement under the Pacific Power Colstrip Contract) 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 price is 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, to have its Kirk Power Plant in cold storage and, as          
       opportunities arise in the meantime, to increase sales of its energy
       and capacity.

<PAGE>
                        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 Competition in Electric
       Utility Business on page 18.)

            As evidenced by a 2 percent increase in customers in 1995, the
       economy in and around Black Hills Power's service territory is believed
       by management to be strong.  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.  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 the City of Gillette 23 megawatts of capacity and the
       associated energy.  The most recent average annual capacity factor for
       this 23 megawatt demand has been approximately 85 percent.  Sales to
       Gillette represented 10.4 percent of total firm energy sales and 7.3
       percent of revenue from total sales in 1995.

       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
       commencing January 1, 1997.  The MDU Sheridan service territory has
       experienced a 45 megawatt winter peak and operates at a 60 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.

            Black Hills Power entered into the agreement with MDU because it
       was an opportunity to use energy from its new base load NS #2 and other
       resources, along with purchased peaking capacity, resulting in
       incremental savings to Black Hills Power's other customers.  Management
       believes that the MDU agreement will remain profitable for the 10-year
       term, but no assurances can be given.

       ADDITIONAL OFF-SYSTEM SALES

            Black Hills power sold 60,575 megawatt hours of non-firm energy in
       1995 and plans to continue to make non-firm sales under the Pacific
       Power Contract in 1996. (See Pacific Power Capacity Contract and
       Settlement of Claim on page 5.)  The selling price is based on spot
       market prices which have been low allowing only a small profit margin on
       the sales in 1995.  Management does not expect spot market prices to
       improve in 1996.

            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 over a term of six months or longer.  The
       highly competitive electric power market, 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.
<PAGE>

        COMPETITION IN THE ELECTRIC UTILITY BUSINESS

            For information relating to competition in the electric utility
       business see page 18.

                                    COAL SALES

       SALES TO BLACK HILLS POWER'S PLANTS

            Black Hills Power and Wyodak Resources entered into the Restated
       and Amended Coal Supply Agreement for NS #2 on February 12, 1993.  Under
       this agreement, Wyodak Resources agrees to supply all of the fuel
       requirements for NS #2 for its useful life and reserve 20 million tons
       of coal reserves for that purpose.  Black Hills Power made a commitment
       to both the SDPUC and the WPSC that coal would be furnished and priced
       as provided by this agreement for the life of the plant.  The City of
       Gillette has agreed to this same methodology of pricing coal in the
       Gillette power purchase contract.

            Under this agreement, Wyodak Resources agrees that its earnings
       from all coal sales to Black Hills Power (including the 20 percent share
       on the Wyodak Plant and all sales to Black Hills Power's other plants)
       will be limited to a return on Wyodak Resources' original cost,
       depreciated investment base.  The return is 4 percent (400 basis points)
       above A-rated utility bonds to be applied to a new investment base each
       year.

            Since Wyodak Resources is expected to incur only minimal additional
       capital costs to fulfill the coal supply agreement for NS #2, Wyodak
       Resources is not expected to increase its earnings from such sale.
       Earnings from the intercompany sales of coal at this time represent 6.4
       percent of the Company's consolidated earnings.

            Sales and production statistics for the last five calendar years
       comparing sales to Black Hills Power to others are as follows:
<TABLE>
<CAPTION>
         Year     Revenue from      % Revenue     Tons of Coal
                  Sale of Coal    Derived from        Sold
                 (in thousands)    Black Hills   (in thousands)
                                      Power
         <S>        <C>                <C>          <C>
         1995       $29,870            35%          2,934
         1994        28,594            33           2,796
         1993        29,822            34           3,027
         1992        28,296            35           2,958
         1991        26,138            35           2,742
</TABLE>

       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" on page 33.)  The price for unprocessed coal sold
       to the Wyodak Plant is based on a coal supply agreement entered into by
       Black Hills Power, Pacific Power and Wyodak Resources in 1974 and
       terminating in the year 2013.  This agreement was amended and restated
       in 1987.  Revenue from coal sales to the Wyodak Plant totaled
       $20,224,000 in 1995 or 68 percent of revenue for all coal sold by Wyodak
       Resources.  The quantity of coal sold in 1995 for the Wyodak Plant was
       1,880,000 tons, as compared to 1,956,000 tons sold in 1994.  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 18 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 2,934,000 tons of coal sold by Wyodak Resources in 1995,
       1,086,000 tons were sold to Black Hills Power, 1,508,000 tons were sold
       to Pacific Power and 340,000 tons were sold to others.

            Wyodak Resources' revenue from sales of coal to Pacific Power and
       Black Hills Power as compared to its revenue from all sales to other
       customers for the last three years was as follows:
<PAGE>
<TABLE>
<CAPTION>
                                                             Revenue from All
                                             Revenue       Sales to Unaffiliated
                    Revenue from Sales   from Sales to      Customers (includes)
          Year       to Pacific Power  Black Hills Power(1)    Pacific Power) 
                                           (in thousands)
          <S>             <C>                 <C>                   <C>
          1995            $16,777             $10,498               $19,372
          1994             16,887               9,445                19,149
          1993             17,448              10,047                19,775
</TABLE>

       (1)  1993, 1994 and the first seven months of 1995 are not adjusted for
            the affiliate coal price adjustment.

            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.

       OTHER SALES

            In addition to the coal sold to the Wyodak Plant and to Black Hills
       Power, Wyodak Resources sold coal to the South Dakota State Cement Plant
       under an all requirements contract expiring on December 1, 1997.  Wyodak
       Resources sold 214,000 tons under this contract in 1995.  Wyodak
       Resources anticipates that the Cement Plant will cancel this contract
       within the next six months.  Because of the Cement Plant's need for a
       higher Btu coal, Wyodak Resources has agreed to the cancellation option.
       Smaller amounts of coal are sold to various businesses and for
       residential use.  All long-term contracts contain adjustment clauses
       based upon certain costs and government indices.

            The coal mining industry is highly competitive and significant new
       sales opportunities are limited.  Wyodak Resources operates in an area
       with many other mining companies which have substantial unused capacity.
       They, like Wyodak Resources, have the permits and capability for large
       increases in production.  Wyodak Resources has no train load-out
       facilities and is not able to compete for large coal sales which require
       unit train (usually 110 cars) loading capabilities, and the current
       market price for such sales does not support the cost of constructing
       the necessary facilities.  Generally, Wyodak Resources' coal sales will
       be confined to sales for consumption at or near the mine.

                               OIL AND GAS OPERATIONS

            Oil and gas operations have not been a significant part of the
       Company's total operations.  Net income and assets related to oil and
       gas operations have been 6 percent or less of the Company's consolidated
       amounts over the last five years.  The oil and gas industry is highly
       competitive.  Western Production encounters strong competition from many
       oil and gas producers 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.  Western Production has
       been able to market all of its oil and gas production.  Operating
       revenue by source for the last five years was as follows:

<TABLE>
<CAPTION>
                    Oil and Gas      Gas Plant       Field
                      Sales           Revenue       Services
                                  (in thousands)
            <S>       <C>              <C>           <C>
            1995      $7,449            $762         $2,953
            1994       8,325             729          2,998
            1993       7,489             759          3,148
            1992       5,640             701          3,258
            1991       4,780             693          3,595
</TABLE>
            Western Production produced approximately 597,000 equivalent
       barrels of oil in 1995 comprised of 45 percent oil and 55 percent gas.
<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 permit set emission rate limitations on particulate, sulfur
       dioxide, nitrogen oxides and opacity.  NS #2 is meeting all of these
       emission rate limitations at this time, and based on operating
       experience with continuing monitoring, management believes that Black
       Hills Power will be able to continue to operate the plant in full
       compliance.

            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.

            NS #2 and all existing generating units of the Company are required
       to obtain operating source permits under the Clean Air Act amendments.
       The operating permit application for NS #2 is due August 31, 1996.
       Completed applications for operating permits were submitted to the DEQ
       for the Osage and NS #1 generating units prior to the November 1995
       deadline.  Air quality permits for the Ben French and Kirk Stations have
       been recently renewed by the Department of Environmental and Natural
       Resources of South Dakota for a period of five years.

            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.
<PAGE>
       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 disposal
       cells located in Wyodak Resources' mined areas.  These disposal cells
       are located below some shallow water aquifers in the mine.  Management
       believes that the disposal cells are sufficiently constructed and lined
       with clay so as to prevent any pollution of the underground water from
       these cells.  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.  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.

            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 material unexpected increases in
       costs of the reclamation permit relates to three depressions, the
       existing south depression, an additional north pit depression and a
       north extension 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 minimum 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 to 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.
<PAGE>

            Cleanup costs recognized to date total approximately $436,000, of
       which amount $282,500 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.

       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 transformers in compliance with law as they are discovered.
       Black Hills Power is uncertain of the number of PCB-contaminated
       transformers remaining in operation in its system.

            A release of PCB-contaminated fluids, especially any involving a
       fire or a release into a waterway, could result in substantial cleanup
       costs.

       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, 1995, the number of employees of the Company
       (including Black Hills Power), Wyodak Resources and Western Production
       were 342, 52 and 38, respectively, for a total of 432 employees.

       ITEM 2. PROPERTIES

                                 UTILITY PROPERTIES

            NS #2 was placed into commercial operation in August 1995.  The
       plant has exceeded its name plate rating and has had stable operations
       in the last several months.  However, management cautions that the plant
       has been in operation only a few months, and a higher degree of
       confidence in the plant's capability will come about over a longer
       period of time.

            The following table provides information on the generating plants
       of Black Hills Power.  During 1995, 99 percent of the fuel used in
       electric generation, measured in Btus (British thermal units), was coal.
<PAGE>
                                  GENERATING UNITS
<TABLE>
<CAPTION>
                                                     Name Plate   
                                        Year of        Rating     Principal
                                      INSTALLATION   (KILOWATTS)    FUEL
       <S>                              <C>            <C>       <C>        
       Osage Plant - Osage, Wyoming      1948-1952      34,500      Coal
       Kirk Plant - Lead, South Dakota     1956(a)      18,750      Coal
       Ben French Station - Rapid City,    1960         25,000      Coal
        South Dakota                       1965         10,000       Oil
                                        1977-1979(b)   100,800    Oil or gas
       Neil Simpson Station - Gillette,    1969         21,760      Coal
        Wyoming                            1995         80,000      Coal
       Wyodak Plant - Gillette, Wyoming    1978(c)      72,400      Coal
                                                       -------                
            Total                                      363,210
</TABLE>
[FN]
       (a) Placed in cold reserve on September 1, 1995 due to economic
           conditions.  The plant can be brought back into operation within 30
           days if economic conditions should change.

       (b) These combustion turbines are those referenced by the Reserve
           Capacity Integration Agreement with Pacific Power on page 5.

       (c) Black Hills Power's 20 percent interest.  See Note 6 of "Notes to
           Consolidated Financial Statements" on page 33.

            Black Hills Power owns transmission lines and distribution systems
       in and adjoining the communities served consisting of 447 miles of
       230 kV, 544 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.

                                 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 sale contracts.  The coal averages 8,000 Btus per pound.
       Mining rights to the coal are based upon five federal leases.  The
       estimated recoverable coal from the five leases as of December 31, 1995
       is 173,453,000 tons, of which 28,412,000 tons are committed to be sold
       to the Wyodak Plant and approximately 28,000,000 tons to Black Hills
       Power's other plants.  Purchase options are granted on 51,000,000 tons
       of which options for 50,000,000 tons can be exercised only if Wyodak
       Resources has not committed the coal reserves to other buyers prior to
       such exercise.  Because the coal purchase price that would be paid if
       the options are exercised would be substantially higher than prices
       being paid under new coal contracts, it is unlikely that the options
       will be exercised.

            Each federal lease grants Wyodak Resources the right to mine all of
       the coal in the land described therein, but the government has the right
       at the end of 20 years from the date of the lease to readjust royalty
       payments and other terms and conditions.  All of the federal leases
       provide for a royalty of 12.5 percent of the selling price of the coal.
       Each federal lease requires diligent development to produce at least one
       percent of all recoverable reserves within either 10 years from the
       respective dates of the 1983 leases or 10 years from the date of
       adjustment of the other leases.  Each lease further requires a
       continuing obligation to mine, thereafter, at an average annual rate of
       at least one percent of the recoverable reserves.  All of the federal
<PAGE> 
       leases 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
       1992, the date of the logical mining unit.  Even if federal coal leases
       are not mined out in 40 years, the federal coal is likely to be
       available for further lease after the 40 years.  Wyodak Resources'
       current coal agreements require production which should be sufficient to
       satisfy the diligent development and continual operation requirements of
       present law.  Wyodak Resources will require additional coal sales in
       order to mine all of its federal coal within the 40 year requirement.

           The law, which requires that an owner of land that is primarily
       devoted to agriculture must approve a reclamation plan before the state
       will approve a permit for open pit mining, affects approximately
       3,100,000 tons of the recoverable coal.  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.

                               OIL AND GAS PROPERTIES

            Western Production operates 336 wells as of December 31, 1995.  The
       vast majority of these wells are in the Finn Shurley Field, located in
       Weston and Niobrara Counties, Wyoming.  Western Production does not
       operate, but owns a working interest in 112 producing properties located
       in the western United States.  Western Production owns a 44.7 percent
       interest in a natural gas processing plant also located at the Finn
       Shurley Field.

            Western Production participated in the drilling of 22 wells in
       1995.  Western Production's average working interest in such wells was
       21.2 percent, or 4.67 net wells.  Approximately 36 percent of the wells
       were classified as development wells and 64 percent were classified as
       exploratory wells.  A development well is a well drilled within the
       presently proved productive area of an oil and gas reservoir, as
       indicated by reasonable interpretation of available data, with the
       objective of completing in that reservoir.  An exploratory well is a
       well drilled in search of a new, as yet undiscovered oil or gas
       reservoir or to greatly extend the known limits of a previously
       discovered reservoir.  Fourteen out of the 22 wells drilled in 1995 were
       completed as producing wells for an overall drilling success rate of 64
       percent.

            See the table in Note 10 of "Notes to the Consolidated Financial
       Statements" on page 37 for Western Production's estimated quantities of
       proved developed and undeveloped oil and natural gas reserves at
       December 31, 1995 and 1994, and a reconciliation of the changes between
       these dates using constant product prices for the respective years.

       ITEM 3. LEGAL PROCEEDINGS

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


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

           No matter was submitted to a vote of security holders during the
       fourth quarter of 1995.

<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 7,386 common shareholders of
       record.  All 50 states and the District of Columbia plus 12 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 1996 meeting,
       the Board of Directors raised the quarterly dividend to 34.5 cents per
       share, equivalent to an annual increase of 4 cents per share.  This
       regular quarterly dividend is payable March 1, 1996.  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 were as follows:

<TABLE>
<CAPTION>
                                                                    
                                     1ST      2ND       3RD        4TH
    YEAR ENDED DECEMBER 31, 1995
    <S>                           <C>       <C>       <C>        <C>
    Dividends paid per share      $0.335    $0.335    $0.335     $0.335
    Common stock prices -
      High                        $24-1/8   $23-5/8   $25-7/8    $26-1/8
      Low                         $20-5/8   $20-1/4   $19-3/4    $24-1/8
</TABLE>

<TABLE>
<CAPTION>
    YEAR ENDED DECEMBER 31, 1994
    <S>                           <C>       <C>       <C>        <C>
    Dividends paid per share      $0.33     $0.33     $0.33      $0.33
    Common stock prices -
      High                        $22-3/4   $22-1/8   $20-3/4    $22-1/4
      Low                         $20-3/4   $18-1/4   $17-7/8    $17-3/4
</TABLE>

       ITEM 6.  SELECTED FINANCIAL DATA

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

<TABLE>
<CAPTION>
    YEARS ENDED DECEMBER 31       1995      1994      1993     1992      1991
                                 (in thousands, except per share amounts)
    <S>                         <C>       <C>       <C>      <C>       <C>
    Operating revenues          $149,817  $145,402  $139,373 $135,343  $133,373
    Net income                    25,590    23,805    22,946   23,638    22,681
    Per share of common stock:
      Earnings                      1.78      1.66      1.66     1.73      1.66
      Dividends paid                1.34      1.32      1.28     1.24      1.17
    Total assets                 448,830   436,877   352,853  330,202   319,895
    Total net long-term debt     166,069   128,925    85,274   88,816    92,982
    
</TABLE>

            Quarterly financial data for the years indicated are summarized as
        follows:

<TABLE>
<CAPTION>
    YEAR ENDED DECEMBER 31, 1995       1ST        2ND        3RD         4TH
                                      (in thousands, except per share amounts)
    <S>                              <C>        <C>        <C>         <C>
    Operating revenues               $35,939    $34,603    $39,061     $40,214
    Operating income                   9,573      8,948     11,626      12,015
    Net income                         5,999      5,642      6,932       7,017
    Earnings per share                  0.42       0.39       0.48        0.49
</TABLE>
<PAGE>

<TABLE>
<CAPTION>
    YEAR ENDED DECEMBER 31, 1994       1ST         2ND       3RD         4TH
                                     (in thousands, except per share amounts)
    <S>                              <C>        <C>        <C>         <C>
    Operating revenues               $35,660    $34,491    $38,589     $36,662
    Operating income                   9,680      7,512     11,348      10,292
    Net income                         5,800      4,383      6,979       6,643
    Earnings per share                  0.41       0.31       0.49        0.45
</TABLE>

       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 a portion 
       of capital requirements.  Except for the construction of NS #2, a new
       power plant which began commercial operation in August 1995, property
       additions from 1993 through 1995 were primarily for the replacement of
       equipment, modernization of facilities and for oil and gas investments.
       The primary capital requirements of the Company for the past three years
       were as follows:

                            1995           1994           1993
                                      (in thousands)
<TABLE>
<CAPTION>
       <S>                       <C>       <C>       <C>
       Construction of NS #2     $33,219   $73,984   $12,792
       Other property             18,676    29,075    27,498
        additions
       Common stock dividends     19,312    18,920    17,720
       Maturities/redemptions     10,499     3,542     4,166
        of long-term debt
                                 $81,706  $125,521   $62,176
</TABLE>

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

                            1996           1997           1998
                                      (in thousands)
<TABLE>
<CAPTION>
       <S>                       <C>       <C>       <C>
       Electric:
         Production              $ 2,040   $ 1,632   $ 1,394
         Transmission              5,149     2,107     3,081
         Distribution              6,924     6,849     7,977
         General                   1,307     1,988     1,883
                                 -------   -------   -------    
                                  15,420    12,576    14,335
       Coal mining                 3,122     1,601     1,573
       Oil and gas                 8,157     6,000     7,000
                                 -------   -------   -------
                                 $26,699   $20,177   $22,908
</TABLE>

            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.
       WYGEN, Inc. and DAKSOFT, Inc., newly formed subsidiaries in 1994, do not
       have any forecasted capital expenditures that are significant.  WYGEN
       was formed as an exempt wholesale generator and will not incur
       substantial costs until and unless long-term power sale contracts are
       obtained.  DAKSOFT was formed to develop and market internally generated
       computer software associated with the Company's business segments.

            The electric operations is the only segment of the Company's
       business with long-term debt.  Long-term debt and sinking fund
       requirements are:  $1,405,000 in 1996, $1,534,000 in 1997 and $1,331,000
       in 1998.

            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 $600,000 is
       charged to operations as reclamation expense annually.  As of December
       31, 1995, accrued reclamation costs were approximately $8,000,000.
<PAGE>     
            The Company sold 525,000 shares of Common Stock, $1 par value, at a
       price of $25-3/8 per share in 1993 through a public stock offering.
       Proceeds from the sale were used to finance NS #2.  Net proceeds from
       the sale were approximately $12,700,000.

            In 1993 the Company revised its Dividend Reinvestment and Stock
       Purchase Plan, under which shareholders may purchase additional shares
       of Common Stock through dividend reinvestment or optional cash payments
       at 100 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 chose the open market purchase option for all of
       1995.  The Company issued 112,578 new shares under the Plan in 1994 and
       26,891 shares in 1993.  Proceeds from the sale of new shares were used
       to finance capital expenditures.

            The Company filed a Form S-3, shelf registration in 1994 for
       $100,000,000 first mortgage bonds.  Under the filing the Company issued
       bonds in the amount of $45,000,000 on September 1, 1994, $30,000,000 on
       February 3, 1995 and $15,000,000 on July 14, 1995.  The $45,000,000 bond
       issue has a 30-year life with an 8.3 percent rate of interest; the
       $30,000,000 bond issue has a 15-year life with an 8.06 percent rate of
       interest; and the $15,000,000 bond issue has a 7-year life with a 6.5
       percent rate of interest.  The $30,000,000 bond issue is redeemable at
       the option of the holders in integral multiples of $1,000 on February 1,
       2002.  The Company also issued $3,000,000 of Environmental Improvement
       Revenue Bonds in 1994 with a variable rate of interest which is
       currently reset weekly.  The average interest rate applied to the bonds
       was 4.2 percent and 3.5 percent in 1995 and 1994, respectively.  The
       Company has the option to remarket the environmental bonds on a short-
       term or long-term basis depending on the remarketability of the bonds.
       Proceeds from all of the above bond issues were used to finance NS #2.
       These additional financings increased the debt component of the
       Company's capital structure from 34 percent at December 31, 1993 to 48
       percent at December 31, 1995.  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 the WYGEN project is constructed.  (See
       WYGEN on page 24.)

            The Company also completed the refinancing of the $12,200,000, City
       of Gillette Pollution Control Revenue Bonds during 1994.  The new bonds
       were issued in July 1994 at 7.5 percent, as agreed to in a 1992 forward
       refunding agreement, and the Series 1984 bonds were called and redeemed
       on August 1, 1994 at 102 percent of par.

            The Company had $36,000,000 of unsecured short-term lines of credit
       at December 31, 1995 and $70,000,000 at December 31, 1994, which provide
       for interim borrowings and the opportunity for timing of permanent
       financing.  Borrowings outstanding under these lines of credit were
       $575,000 and $36,975,000 as of December 31, 1995 and 1994, respectively.
       The weighted average interest rate on these borrowings at December 31,
       1995 and 1994 was 7.4 percent and 6.9 percent, respectively.  There are
       no compensating balance requirements associated with these lines 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.

            Credit ratings for the Company's First Mortgage Bonds remained at
       an A1 level at Moody's Investors Service, Inc. and at an A at Standard &
       Poor's.  Standard & Poor's issued a negative outlook on the Company in
       1993.  The negative outlook was removed in 1995 after NS #2 became
       commercially operational and the Company received rate recovery on the
       NS #2 investment.  These ratings reflect the respective agencies'
       opinions of the credit quality of the Company's bonds.

                                  RATE REGULATION

       COMMERCIAL OPERATION OF NS #2 AND THE RELATED RATE RECOVERY

            NS #2, an 80 megawatt coal-fired electric generating plant located
       adjacent to the Company's coal mine, began commercial operation in
       August 1995.  The cost of the plant was approximately $122,000,000 which
       was $2,900,000 under the initial project budget.  A portion of the
       generation from the plant replaces power Black Hills Power was
       purchasing from other sources.
<PAGE>
            Black Hills Power was authorized a 6.76 percent increase in
       electric rates charged its South Dakota customers (representing
       approximately 81 percent of sales) effective August 1, 1995, an 8.97
       percent increase for its Wyoming retail customers (representing
       approximately 8 percent of sales) effective August 16, 1995, and a 12.3
       percent increase for its only wholesale customer, the City of Gillette
       (representing approximately 10 percent of sales), effective September 6,
       1995.  The increase for the City of Gillette will be reduced to an 8.8
       percent increase commencing January 1, 1997, when Black Hills Power
       expects to receive additional revenue from sales to MDU for its
       Sheridan, Wyoming, service territory.  (See Wholesale to MDU on page 6.)

            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.

            Black Hills Power is undertaking during the freeze period 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 settlement will allow Black Hills Power to 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.  Management's expectation is that the
       settlement will be 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 will
       not materially increase.

            The rate settlements resulted in the inclusion of NS #2 into Black
       Hills Power's rate base without any disallowance.

       LONG-TERM CONTRACTS

            As a result of rate negotiations, Black Hills Power was successful
       in entering into long-term contracts with 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.  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 will be able to
       invoke a planning surcharge on that customer.  If deregulation in retail
       electric sales occurs, the contracts give Black Hills Power sufficient
       notice to allow the appropriate planning to make the transition to full
       competition, guard against stranded investment and protect other
       customers from unexpected load loss.  These industrial and large
       commercial customers, together with the power sales agreement to the
       City of Gillette, result in Black Hills Power having approximately 36
       percent of its firm load (based upon 1995 sales) under term contracts of
       at least five years, and in 1997 when service commences under the MDU
       contract, approximately 41 percent of Black Hills Power's firm load is
       estimated to be 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.

<PAGE>
                       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 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.

            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.  The FERC has proposed 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.  The Company can give no assurances that this proposal will be
       in the final regulations.  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 Polices 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--WYGEN
       Project on page 24.)
<PAGE>
            Black Hills Power's success in constructing NS #2 and getting it
       into rate base was unusual for this period of time.  The isolated area
       in which Black Hills Power serves, the need for generation internal to
       its system to support the limited transmission system and the Company's
       control of its fuel supply at the mine site allowed Black Hills Power to
       satisfy regulators that constructing NS #2 was the least cost of any
       alternative, including purchased power.  In the future, however, because
       of the competitive forces described herein, it will become increasingly
       difficult for any public utility to build base load generation and
       expect to pass those costs on to its customers under the traditional
       rate base methodology.  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, but no assurances can be given that material competition from
       these sources will not occur.

       TRANSMISSION ACCESS

            The Energy Policy Act of 1992 provided for amendments to the
       Federal Power Act that grant the FERC broad authority to mandate
       transmission access to independent power producers as well as others
       engaged in wholesale power transactions but specifically prevented the
       FERC from ordering wheeling to end users (retail wheeling).  Under the
       new law, any electric utility or any other entity generating wholesale
       electric energy may apply to the FERC for an order requiring any
       electric utility to transmit such energy, including the enlargement of
       relevant facilities.  If the utility refuses to wheel or furnish
       transmission service, the FERC may but is not required to order wheeling
       in response to an application.  The FERC is not to order wheeling if to
       do so would impair the transmitting utility's reliability of service.
       The new law does provide for the transmitting utility to obtain its full
       cost of transmission service, as determined by the FERC.

            In March of 1996, the FERC is expected to adopt regulations that
       will require 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 will provide for various transmission services
       and will apply to the transmission of electric power for wholesale
       purposes only.  The regulations will 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.  The public utilities will further be required to
       functionally separate those persons who operate and market the
       transmission system from those persons who buy and sell power for the
       same utility.  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.  Black Hills Power plans to
       file an application with the FERC to approve open access transmission
       tariffs in compliance with what is expected to be the final rule.

            The new FERC regulations requiring the filing of open access
       tariffs will 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 is proposing 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 and for the City of Gillette, Wyoming through contracts.
       As long as the states in which Black Hills Power operates continue to
       grant exclusive service territories, the federal government does not
       preempt this state jurisdiction and municipalities in Black Hills
       Power's service territory do not establish municipal electric systems,
       the increase in transmission access through the Energy Policy Act of
       1992 and the FERC regulations through Black Hills Power's transmission
       system are 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-user customers who were formerly captive 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
<PAGE> 
       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 and the end of exclusive
       franchised service territories will come.  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.  At this time, the Company is not aware of
       any movement in its major state jurisdictions for retail wheeling, but
       no assurances can be given that either Congress or the states may in the
       future require electric retail competition.

            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 is in a position 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 investment due to competition should
       be allowed payment for such 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.  Black Hills Power
       should always be able to expect rates based upon full costs for the use
       of its transmission and distribution systems, and its competition will
       be paying the same costs.  Lower rates today are partially caused by
       excess generation capacity which allows providers to sell energy above
       their marginal costs but below full costs.  Based upon industry
       predictions, management believes that this excess capacity will be more
       fully utilized in the next five to seven years.  Management believes
       that coal-fired plants will become more competitive with natural gas-
       fired plants in the future as natural gas prices increase.

            However, future market and regulatory conditions anticipated in the
       previous paragraph may not occur.  Market and economic conditions and
       government actions or inaction are highly unpredictable and 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.

       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 1995 reflecting the
       successful completion of the construction of NS #2, the related rate
       recovery and strong growth in sales for the residential and commercial
       customers.  Consolidated net income for 1995 was $25,590,000 compared to
       $23,805,000 in 1994 and $22,946,000 in 1993 or $1.78 per average common
       share in 1995 and $1.66 per average common share in 1994 and 1993.  This
       equates to a 14.0 percent return on year-end common equity in 1995, 13.6
       percent in 1994 and 13.7 percent in 1993.  Consolidated net income
       includes noncash earnings of $3,645,000 and $2,371,000 for allowance for
       equity funds used during construction in 1995 and 1994, respectively.
<PAGE>
            Consolidated revenue and income provided by the three businesses as
       a percentage of the total were as follows:

<TABLE>
<CAPTION>
                                   1995         1994        1993
       <S>                         <C>          <C>         <C>       
       Revenue:
         Electric                   73%          72%         71%
         Coal mining                20           20          21
         Oil and gas                 7            8           8
                                   ---          ---         ---
                                   100%         100%        100%
</TABLE>


<TABLE>
<CAPTION>
        <S>                         <C>         <C>         <C>
        Net Income:
          Electric                  57%          54%         49%
          Coal mining               38           41          46
          Oil and gas                5            5           5
                                   ---          ---         ---
                                   100%         100%        100%
</TABLE>

            Dividends paid on common stock totaled $1.34 per share in 1995.
       This reflected increases approved by the Board of Directors from $1.32
       per share in 1994 and $1.28 per share in 1993.  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 70's.  Management believes
       this objective is attainable through earnings growth.  The Company's
       three year dividend growth rate was 2.6 percent and the payout ratio for
       1995 was 75 percent.

            In January 1996 the Board of Directors increased the quarterly
       dividend 3.0 percent to 34.5 cents per share.  If this dividend is
       maintained during 1996, the increase will be equivalent to an annual
       increase of 4 cents per share.

       ELECTRIC OPERATIONS
<TABLE>
<CAPTION>
                               1995          1994           1993
                                         (in thousands)
       <S>                   <C>           <C>            <C>
       Revenue               $108,783      $104,756       $98,155
       Operating expenses      80,540        79,680        74,173
                             --------      --------       -------
       Operating income      $ 28,243      $ 25,076       $23,982
                             ========      ========       =======
       Net income            $ 14,569      $ 12,852       $11,171
                             ========      ========       =======
</TABLE>

            Electric revenue increased 3.8 percent in 1995 compared to a 6.7
       percent increase in 1994 and a 0.7 percent increase in 1993.  Firm
       kilowatthour sales increased 0.5 percent in 1995 compared to a 2.7
       percent increase in 1994 and a 3.5 percent increase in 1993 and have
       averaged an annual 2.2 percent growth rate over the last three years.

            The increase in revenue in 1995 was primarily due to the increase
       in electric rates (see Commercial Operation of NS #2 and the Related
       Rate Recovery on page 16) and strong growth in the residential and
       commercial sectors of the Company's electric business. The residential
       sector showed a 1.8 percent growth in the number of customers and a 4.1
       percent growth in kilowatthour sales.  The commercial sector showed a
       2.6 percent growth in the number of customers and a 3.6 percent growth
       in kilowatthour sales.  While the residential and commercial sectors
       which provide Black Hills Power with the highest margin sales showed
       strong growth, the impact of this growth was partially offset by a 5.2
       percent decrease in kilowatthour sales to the industrial customers.
       Homestake Mining Company, representing 10.5 percent of firm kilowatthour
       sales, purchased 7.7 percent less energy in 1995 by continuing to
       concentrate on more efficient production areas.  The South Dakota Cement
       Plant, representing 6.3 percent of firm kilowatthour sales, purchased
       12.5 percent less energy than the previous year because of a decrease in
       cement production and sales and the installation of more efficient
       equipment.

            The increase in revenue in 1994 was due to the 2.7 percent increase
       in firm kilowatthour sales and an increase in the fuel and purchased
       power adjustment passed on to electric customers.  The increase in
       purchased power costs was primarily due to replacement power purchased
       while the Wyodak Plant was out of service for maintenance.
<PAGE>

            The revenue increase in 1993 from additional electric sales was
       offset by a decrease in the fuel and purchased power adjustment passed
       on to electric customers.  The decrease in the purchased power
       adjustment passed on to electric customers was due to a $2,000,000
       refund received from PacifiCorp on the 40-year power purchase agreement.
       Homestake Mining Company reduced its energy usage by 22,000 megawatt
       hours in 1993 by concentrating on more efficient production areas.

            Revenue per kilowatthour sold was 6.1 cents in 1995 and 1994 up
       from 5.9 cents in 1993.  The number of customers in the service area
       increased to 55,018 in 1995 from 53,959 in 1994 and 53,330 in 1993.  The
       revenue per kilowatthour sold in 1995 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 60,575 megawatt hours of non-
       firm sales.  Excluding non-firm sales the rate per kilowatthour sold was
       6.3 cents in 1995.  The increase in revenue per kilowatthour sold in
       1994 was due to the increase in purchased power cost related to
       replacement power purchased during the Wyodak Plant maintenance period.

            Operating expenses increased slightly in 1995 reflecting the
       commercial operation of NS #2, increased substantially in 1994 due to
       the increase in purchased power costs and remained relatively flat in
       1993 compared to 1992 as a result of the $2,000,000 purchased power
       refund.  Coinciding with the commercial operation of NS #2, the electric
       operations realized a decrease in the cost of coal per ton charged by
       Wyodak Resources.  Over the past several years Black Hills Power was not
       allowed to include in rates charged to its South Dakota customers any
       cost of coal which allowed Wyodak Resources to earn a return on equity
       on sales of coal to Black Hills Power in excess of a percentage equal to
       the rate on long-term "A" rated utility bonds plus 400 basis points (4
       percent).  Any excess amount that was charged was refunded to Black
       Hills Power's South Dakota customers through the fuel and purchased
       power adjustment clause.  Beginning with the commercial operation of NS
       #2, Wyodak Resources changed its coal pricing methodology to Black Hills
       Power making the price of coal equal to the above limitation thereby
       eliminating the need for any further adjustment to the electric
       operations revenue.  The impact of this change reduced fuel expense for
       the electric operations, reduced revenue for the coal mining operations
       and had no impact on the consolidated financial statements.

            Firm energy sales are forecasted to increase over the next 10 years
       at an annual compound growth rate of approximately 2 percent with the
       system demand forecasted to increase 2.1 percent in the summer and 2.4
       percent in the winter.  The Company currently has a winter peak of 291
       MWs established in January 1996 and a summer peak of 298 MWs established
       in August 1995.  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 as was experienced with the industrial
       sales growth in 1995.  However, in the past the forecasts tracked actual
       sales within a band of reasonableness over a period of several years.

       COAL MINING OPERATIONS

<TABLE>
<CAPTION>
                                1995        1994         1993
                                       (in thousands)
       <S>                    <C>          <C>          <C>
       Revenue                $29,870      $28,594      $29,822
       Operating expenses      17,644       16,694       17,461
                              -------      -------      -------
       Operating income       $12,226      $11,900      $12,361
                              =======      =======      =======
       Net income             $ 9,737      $ 9,918      $10,641
                              =======      =======      =======  
</TABLE>

            Revenue increased 4.5 percent in 1995, decreased 4.1 percent in
       1994 and increased 5.4 percent in 1993 due to a 5.0 percent increase, a
       7.6 percent decrease and a 2.3 percent increase, respectively, in tons
       of coal sold.  The increase in revenue in 1995 was partially offset by a
       decrease in the price of coal charged to the utility's operations.  (See
       explanation of the change in coal pricing methodology under Electric
       Operations.)  The decrease in tons of coal sold in 1994 was caused by
       the Wyodak Plant being out of service for five weeks of scheduled
       maintenance.  Operating expenses increased 5.7 percent in 1995
       reflecting the increase in tons of coal sold.  Operating expenses
       decreased 4.0 percent in 1994 reflecting the decrease in tons of coal
       mined offset by an increase in depreciation expense.  Operating expense
       increased 4.4 percent in 1993 reflecting an increase in depreciation
       expense as a result of an increase in capital investments and higher
       taxes associated with increased revenues.

<PAGE>            
       Non-operating income was $2,279,000 in 1995 compared to $1,750,000
       in 1994 and $2,226,000 in 1993.  Non-operating income includes gains or
       losses on sale or disposal of property and equipment, a coal contract
       settlement from Grand Island, Nebraska and interest income from
       investments.  Non-operating income increased in 1995 due to a $700,000
       gain realized on the disposal of equipment offset by a decrease in
       interest rates.  Non-operating income decreased in 1994 and 1993 due to
       a decrease in interest income attributable to lower interest rates.

       OIL AND GAS PRODUCTION

<TABLE>
<CAPTION>
                               1995          1994         1993
                                        (in thousands)
       <S>                    <C>          <C>          <C>
       Revenue                $11,164      $12,052      $11,396
       Production expenses      9,471       10,196        9,952
                              -------      -------      -------
       Operating income       $ 1,693      $ 1,856      $ 1,444
                              =======      =======      =======
       Net income             $ 1,320      $ 1,080      $ 1,127
                              =======      =======      =======
</TABLE>

            The oil and gas operations have not been a significant part of the
       Company's total operations.  Net income and assets related to oil and
       gas operations have been 6 percent or less of the Company's consolidated
       amounts over the last three years.

            Revenue is primarily comprised of oil and gas sales and is
       supplemented by field services in eastern Wyoming.  Equivalent barrels
       of oil sold was 599,000 barrels in 1995, 624,000 barrels in 1994 and
       465,000 barrels in 1993. The average sales price of oil per barrel was
       $17.09 in 1995 compared to $15.56 in 1994 and $16.69 in 1993.  The
       average sales price per mcf of gas was $1.47 in 1995 compared to $1.81
       in 1994 and $2.31 in 1993.  Western Production's production expenses
       decreased 7.1 percent in 1995 compared to a 2.5 percent increase in 1994
       and a 21 percent increase in 1993.

            During 1995 Western Production sold its interest in several wells
       with estimated net remaining reserves of 208,000 barrels of oil
       equivalents for approximately $2,175,000.  The impact of this sale
       reduced 1995 production by approximately 100,000 equivalent barrels.

            Production expenses decreased in 1995 reflecting lower depletion
       expense associated with higher oil prices and a successful drilling
       program.  Production expenses increased in 1994 and 1993 primarily due
       to increased depletion expense as a result of increased oil and gas
       production and lower oil and gas prices.  Western Production recognized
       $3,730,000, $4,450,000 and $3,725,000 of depletion expense in 1995, 1994
       and 1993, respectively.  Low oil and gas prices reduce the cash flow and
       value of the Company's oil and gas assets and will cause the Company to
       increase its depletion expense.

            Western Production's proved reserves and the revenues generated
       from production decline as production occurs, except to the extent
       successful exploration and development activities are conducted or
       additional proved reserves are acquired.  Western Production has been in
       an active exploration and development drilling program during the past
       three years.  Western Production participated in the drilling of 22
       wells in 1995 with an average working interest of 21 percent or 4.7 net
       wells.  Fourteen of the 22 wells were completed as producing wells for
       an overall success rate of 64 percent.  Much of the production growth in
       1994 and 1993 was the result of its horizontal drilling program in the
       Austin Chalk formation in Texas.  Western 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.

            Western 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.  Western
       Production's unaudited reserves, principally proved developed and proved
       undeveloped properties, were estimated to be 1.6, 1.4 and 1.1 million
       barrels of oil and 7.7, 9.1 and 2.8 billion cubic feet of natural gas as
       of December 31, 1995, 1994 and 1993, respectively.  The decrease in
       reserves at December 31, 1995 was due to the sale of properties 
       described above and low gas prices.  The increase in reserves as of
       December 31, 1994, was primarily due to the active drilling program 
       and a production acquisition in South Texas.  The decrease in the 
       reserves in 1993 was caused by price decreases and engineering revisions.
<PAGE>

       WYGEN

            In 1994, Wyodak Resources formed a wholly owned subsidiary named
       WYGEN, Inc.  WYGEN applied for and received from the FERC a
       determination that WYGEN has exempt wholesale generator status under
       Section 32 of the Public Utility Holding Company Act.  WYGEN was formed
       for the sole purpose of engaging in the generating and selling of
       electric power and energy at wholesale.  At this time WYGEN is proposing
       to build an 80 megawatt coal-fired electric generating plant to be known
       as the Wygen Plant adjacent to NS #2.  WYGEN has filed with the DEQ an
       application for a prevention of significant deterioration air quality
       construction permit.  Management expects, but can give no assurances,
       that the required permit will be obtained in mid-1996.  Construction
       must commence within two years of the granting of the permit or WYGEN
       would be required to reapply.  As an independent power project, the air
       quality permit is the only major permit required.  Based upon nonbinding
       suggestions of major contractors, management believes that WYGEN would
       be able to construct the Wygen Plant for approximately the same cost of
       construction as NS #2.

            WYGEN would not commence construction of the Wygen Plant until such
       time that WYGEN receives sufficient power purchase contracts from
       responsible entities which would be required to obtain the necessary
       financing.  It is anticipated that the WYGEN Plant will be financed
       primarily with non-recourse debt secured only by the WYGEN Plant assets.
       The wholesale market is currently highly competitive (see Competition in
       the Electric Utility Business on page 18), and the Company can give no
       assurances that the project is feasible at this time.  If not at this
       time, the Company believes that it is only a matter of time before
       additional power plants at the site of Wyodak Resources' mine are
       economically feasible.

            Viable markets for the electric power and energy from the Wygen
       Plant 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 WYGEN's participation in
       transmission improvements which, together with transmission rates for
       access across transmission systems, could make the WYGEN Plant 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 interests of any one provider, with mechanisms to pool costs and 
       cause transmission system improvements to be constructed, on a timely
       basis, with broad participation.

       OTHER SEGMENTS OF BUSINESS

            DAKSOFT, Inc., a subsidiary of Wyodak Resources, was formed in 1994
       to develop and market internally generated computer software associated
       with the Company's business segments.  DAKSOFT entered into a multi-year
       enhancement and sales contract in 1995 totalling $700,000.  The revenue
       from this contract is earned as the product enhancement occurs.
       Approximately $290,000 of revenue was recognized in 1995.  DAKSOFT's
       expenses in 1994 were primarily organizational expenses.   Landrica was
       incorporated by the Company in March 1984, and holds minor interests in
       real estate.  The financial position and results of operations of WYGEN,
       DAKSOFT and Landrica were not significant to the Company.

       ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND LONG-LIVED ASSETS
       TO BE DISPOSED OF

            In December 1995, the Company adopted Statement of Financial        
       Accounting Standards 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.  The adoption of the
       standard did not have an impact on the financial position or results
       of operations based on the current regulatory structure in which Black
       Hills Power operates.  This may change in the future as competitive
       factors influence wholesale and retail pricing in the utility industry.
<PAGE>
       ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

         Report of Independent Public Accountants                        25

         Consolidated Statements of Income and Retained Earnings
           for the three years ended December 31, 1995                   26

         Consolidated Statements of Cash Flows for
           the three years ended December 31, 1995                       27

         Consolidated Balance Sheets as of December 31, 1995 and 1994    28

         Consolidated Statements of Capitalization as of
           December 31, 1995 and 1994                                    29

         Notes to Consolidated Financial Statements                      30


                     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, 1995 and 1994, and the related consolidated
       statements of income, retained earnings and cash flows for each of the
       three years in the period ended December 31, 1995.  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, 1995 and 1994, and the
       results of their operations and their cash flows for each of the three
       years in the period ended December 31, 1995, in conformity with
       generally accepted accounting principles.



                                                   ARTHUR ANDERSEN LLP


       Minneapolis, Minnesota,
       January 30, 1996
<PAGE>
                             BLACK HILLS CORPORATION
                        CONSOLIDATED STATEMENTS OF INCOME


<TABLE>
<CAPTION>
       Years ended December 31        1995           1994           1993
                                                (in thousands)
       <S>                          <C>            <C>            <C>
       Operating revenues:
         Electric                   $108,783       $104,756       $ 98,155
         Coal mining                  29,870         28,594         29,822
         Oil and gas                  11,164         12,052         11,396
                                    --------       --------       --------
                                     149,817        145,402        139,373
                                    --------       --------       --------
       Operating expenses:
         Fuel and purchased           39,265         41,970         36,946
          power
         Operations and               28,523         28,713         30,237
          maintenance
         Administrative and            9,226          7,920          8,144
          general
         Depreciation, depletion      19,660         17,601         16,051
          and amortization
         Taxes, other than            10,981         10,366         10,208
          income taxes                                                 
                                    --------       --------       --------
                                     107,655        106,570        101,586
                                    --------       --------       --------
       Operating income:
         Electric                     28,243         25,076         23,982
         Coal mining                  12,226         11,900         12,361
         Oil and gas                   1,693          1,856          1,444
                                    --------       --------       --------
                                      42,162         38,832         37,787
                                    --------       --------       --------
       Other income (expense):
         Interest expense            (14,195)       (10,339)        (8,817)
         Investment income             1,368          1,631          1,739
         Allowance for funds           5,867          3,983            729  
          used during construction    
         Other, net                       93            473          1,125
                                    --------       --------       --------  
                                      (5,835)        (4,632)        (5,876)
                                    --------       --------       --------
       Income before income           36,327         34,200         31,911
        taxes
       Income taxes                  (10,737)       (10,395)        (8,965)
                                    --------       --------       --------
          Net income                $ 25,590       $ 23,805       $ 22,946
                                    ========       ========       ========
       Weighted average common        14,409         14,339         13,811
        shares outstanding

       Earnings per share of        $   1.78      $    1.66      $    1.66
        common stock
</TABLE>

                        CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
       Years ended December 31           1995          1994            1993
                                                (in thousands)
       <S>                          <C>            <C>            <C>
       Balance, beginning of year   $115,284       $110,399       $105,173
       Net income                     25,590         23,805         22,946
       Cash dividends on common
        stock ($1.34, $1.32          (19,312)       (18,920)       (17,720)
        and $1.28 per share,
        respectively)
                                    --------       --------       -------- 
       Balance, end of year         $121,562       $115,284       $110,399
                                    ========       ========       ========

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

                         CONSOLIDATED STATEMENTS OF CASH FLOWS

</TABLE>
<TABLE>
<CAPTION>
       Years ended December 31         1995          1994            1993
                                                 (in thousands)
       <S>                          <C>             <C>            <C>
       Operating activities:
         Net income                 $ 25,590        $23,805        $22,946
         Principal non-cash
          items-
           Depreciation, depletion    19,660         17,601         16,051
            and amortization
           Deferred income taxes
            and investment tax         2,097          2,470          1,042
            credits
           Allowance for other
            funds used during         (3,645)        (2,371)          (333)
            construction
         Increase in receivables,
          inventories and other         (669)        (3,438)        (1,556)
          current assets
         Increase (decrease) in       (1,420)         5,054         (2,562)
          current liabilities
         Other, net                    3,677          5,815          4,259
                                     -------        -------        -------
                                      45,290         48,936         39,847
                                     -------        -------        -------
       Investing activities:
         Neil Simpson Unit #2
          construction costs,
          excluding allowance for    (29,820)       (71,956)       (12,675)
          other funds used during
          construction
         Other property
          additions, excluding       (18,430)       (28,732)       (27,282)
          allowance for other
          funds used during
          construction
         Available for sale          (19,323)       (41,923)       (33,622)
          securities purchased
         Available for sale           36,941         46,964         40,228
          securities sold
                                     -------        -------        -------
                                     (30,632)       (95,647)       (33,351)
                                     -------        -------        -------
       Financing activities:
         Dividends paid              (19,312)       (18,920)       (17,720)
         Common stock issued             654          2,436         13,705
         Net short-term              (36,400)        25,250          3,784
          borrowings (repayments)
         Long-term debt issued        46,904         45,795              -
         Long-term debt retired      (10,499)        (3,542)        (4,166)
                                     -------        -------        -------
                                     (18,653)        51,019         (4,397)
                                     -------        -------        -------
           Increase (decrease) in
            cash and cash             (3,995)          4,308          2,099
            equivalents
       Cash and cash equivalents:
         Beginning of year            12,174           7,866          5,767
                                     -------         -------        -------
         End of year                 $ 8,179         $12,174        $ 7,866
                                     =======         =======        =======
       Supplemental disclosure of
        cash flow information:
         Cash paid during the
          period for-
           Interest                  $12,901       $  9,244        $ 9,283
           Income taxes              $ 7,775       $  7,290        $ 8,000

       The accompanying notes to consolidated financial statements are an
       integral part of these consolidated financial statements.
</TABLE>
<PAGE>

                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
       December 31                                  1995           1994
          ASSETS                                      (in thousands)
       <S>                                       <C>            <C>
       Current assets:
         Cash and cash equivalents               $  8,179       $ 12,174
         Securities available for sale              6,804         24,422
         Receivables, net
           Customers                               13,339         12,409
           Other                                    3,825          4,045
         Materials, supplies and fuel               7,415          7,139
         Prepaid expenses                           1,247          1,564
                                                 --------       --------
                                                   40,809         61,753
                                                 --------       -------- 
       Property and investments:
         Electric                                 469,135        425,690
         Coal mining                               44,473         51,755
         Oil and gas                               40,704         38,842
         Other                                      3,330          3,009
                                                 --------       --------
                                                  557,642        519,296
         Less accumulated depreciation and       (164,383)      (156,046)
          depletion
                                                 --------       -------- 
                                                  393,259        363,250
                                                 --------       --------
       Deferred charges:
         Federal income taxes                       7,543          7,505
         Regulatory asset                           2,576            699
         Other                                      4,643          3,670
                                                 --------       --------
                                                   14,762         11,874
                                                 --------       --------
                                                 $448,830       $436,877
                                                 ========       ========
          LIABILITIES AND CAPITALIZATION
       Current liabilities:
         Current maturities of long-term         $  1,405       $  2,144
          debt
         Notes payable                                618         37,018
         Accounts payable                           9,737         12,018
         Accrued liabilities-
           Taxes                                    7,047          6,331
           Interest                                 4,089          2,795
           Other                                    6,977          8,126
                                                 --------       -------- 
                                                   29,873         68,432
                                                 --------       --------
       Deferred credits:
         Federal income taxes                      45,290         39,953
         Investment tax credits                     5,018          5,521
         Reclamation costs                          7,974          7,618
         Regulatory liability                       7,111          6,925
         Other                                      5,153          4,093
                                                 --------       --------
                                                   70,546         64,110
                                                 --------       --------
       Commitments and contingent
        liabilities
         (Notes 6, 7 and 8)

       Capitalization, per accompanying
        statements:
         Common stock equity                      182,342        175,410
         Long-term debt                           166,069        128,925
                                                 --------       -------- 
                                                  348,411        304,335
                                                 --------       --------
                                                 $448,830       $436,877
                                                 ========       ========

       The accompanying notes to consolidated financial statements are an
       integral part of these consolidated balance sheets.
</TABLE>
<PAGE>









                     CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
       December 31                                   1995            1994
                                                       (in thousands)
       <S>                                       <C>            <C> 
       Common stock equity:
         Common stock, $1 par value;
          50,000,000 shares authorized;          $ 14,425       $ 14,386
          14,424,952 and 14,386,353
          shares outstanding respectively
         Additional paid-in capital                46,355         45,740
         Retained earnings                        121,562        115,284
                                                 --------       --------
          Total common stock equity               182,342        175,410
                                                 --------       -------- 
       Cumulative preferred stock:
         No par value; 400,000 share                    -              -
          authorized; no shares outstanding
         $100 par value; 270,000 shares                 -              -
          authorized; no shares outstanding

       Long-term debt:
         First mortgage bonds-
           8.375% retired 1995                          -          2,675
           8.05% retired 1995                           -          4,850
           6.625% pollution control bonds,              -          1,680
            retired 1995
           6.50% due 2002                          15,000              -
           9.00% due 2003                           9,275         10,561
           8.06% due 2010                          30,000              -
           9.49% due 2018                           6,000          6,000
           9.35% due 2021                          35,000         35,000
           8.30% due 2024                          45,000         45,000
                                                 --------       --------
                                                  140,275        105,766
                                                 --------       --------
         Other-
           6.7% pollution control revenue          12,300         12,300
            bonds, due 2010
           7.5% pollution control revenue          12,200         12,200
            bonds, due 2024
           Other long-term obligations              2,699            803
                                                 --------       --------
                                                   27,199         25,303
                                                 --------       --------
          Total long-term debt                    167,474        131,069
       Current maturities                          (1,405)        (2,144)
                                                 --------       --------  
          Net long-term debt                      166,069        128,925
                                                 --------       --------
          Total capitalization                   $348,411       $304,335
                                                 ========       ========

       The accompanying notes to consolidated financial statements are an
       integral part of these consolidated financial statements.
</TABLE>


<PAGE>
       NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
       DECEMBER 31, 1995, 1994, AND 1993

       (1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

       BUSINESS DESCRIPTION

       Black Hills Corporation and its subsidiaries operate in three primary    
       business segments:  electric, coal mining and oil and gas production.
       The Company's electric utility operation is engaged in the generation,
       purchase, transmission, distribution and sale of electric power and
       energy in western South Dakota, northeastern Wyoming and southeastern
       Montana.  Sales of electric power to the three largest electric
       customers represented 18 percent of the Company's electric revenue in
       1995 and 20 percent in 1994 and 1993.  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, 64 percent of the coal mining operation's sales are to the
       Wyodak Plant.  Sales of coal to the Company and to PacifiCorp represent
       88 percent of total coal sales.  The Company's oil and gas exploration
       and production business operates and has working interests in properties
       located in the western United States.

       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 No. 71, "Accounting for the Effects of
       Certain Types of Regulation."  Total intercompany coal sales not
       eliminated were $10,498,000, $9,445,000 and $10,047,000 in 1995, 1994
       and 1993, respectively.

       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.

       PROPERTY

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

       DEPRECIATION AND DEPLETION

       Depreciation is computed using the straight-line method over the 
       estimated useful lives of the related assets.  Depreciation provisions
       for the electric property were equivalent to annual composite rates of
       3.0 percent in 1995, 3.1 percent in 1994 and 3.2 percent in 1993.  
       Composite depreciation rates for other property were 8.9 percent, 10.3
       percent and 9.6 percent in 1995, 1994 and 1993, respectively.  
       Depletion of coal and oil and gas properties is computed using the cost
       method for financial reporting and the gross income method or cost 
       method, whichever is applicable, for federal income tax reporting.

       AVAILABLE FOR SALE SECURITIES

       The Company has investments in marketable securities which are
       classified as available-for-sale securities.  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.
<PAGE>

       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 EXPLORATION

       The Company accounts for its oil and gas exploration activities under
       the full cost method. Capitalized costs associated with unsuccessful 
       wells are amortized over future periods as the reserves from successful
       wells are produced.

       ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

       Allowance for funds used during construction (AFDC) represents the       
       approximate composite cost of borrowed funds and a return on capital
       used to finance construction expenditures and is capitalized as a 
       component of the electric property.  The AFDC was computed at an annual
       composite rate of 10.2 percent in 1995, 8.7 percent in 1994 and 7.7 
       percent in 1993.

       INCOME TAXES

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

       RECLASSIFICATIONS

       Certain amounts previously reported in the 1994 financial statements
       have been reclassified to conform to the 1995 financial statement
       presentation.  Those reclassifications had no effect on previously
       reported net income or common stock equity.

       NEW ACCOUNTING PRONOUNCEMENTS

       In December 1995, the Company adopted Statement of Financial Accounting
       Standards 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. The adoption of the standard did
       not have an impact on the financial position or results of operations
       based on the current regulatory structure in which the Company operates.
       This may change in the future as competitive factors influence wholesale
       and retail pricing in the utility industry.

       (2)  CAPITAL STOCK

       COMMON STOCK

       Common shares issued at $1.00 par value during the years indicated were:

<TABLE>
<CAPTION>
                                   1995         1994        1993
       <S>                        <C>         <C>          <C>
       Public Offering                 -            -      525,000
       Employee Stock             38,599        4,195       16,402
       Purchase Plan
       Dividend Reinvestment
       and Stock Purchase Plan         -      112,578       26,891
                                  ------      -------      -------        
                                  38,599      116,773      568,293
                                  ======      =======      =======
</TABLE>
       At December 31, 1995, 231,415 shares of unissued common stock were
       available for future offerings under the Employee Stock Purchase Plan.

       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.  At
       December 31, 1995, 860,531 shares of unissued common stock were
       available for future offerings under the Plan.
<PAGE>

       ADDITIONAL PAID-IN CAPITAL

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

<TABLE>
<CAPTION>
                                       1995           1994       1993
                                                (in thousands)
       <S>                           <C>            <C>         <C>
       Balance, beginning of         $45,740        $43,420     $30,284
        year         
       Premium, net of expenses,
       received from sales of stock      615          2,320      13,136
                                     -------        -------     -------
       Balance, end of year          $46,355        $45,740     $43,420
                                     =======        =======     =======
</TABLE>

       (3)  LONG-TERM DEBT

       Substantially all of the Company's utility property is subject to the
       lien of the Indenture securing its first mortgage bonds.  First mortgage
       bonds of the Company may be issued in amounts limited by property,
       earnings and other provisions of the mortgage indentures.  Scheduled
       maturities of long-term debt for the next five years are:  $1,405,000 in
       1996, $1,534,000 in 1997, $1,331,000 in 1998, and $1,330,000 in 1999 and
       2000.

       In 1994 the Company filed a Form S-3, shelf registration for
       $100,000,000 first mortgage bonds.  Under the filing, the Company issued
       bonds in the amount of $45,000,000 on September 1, 1994, $30,000,000 on
       February 3, 1995 and $15,000,000 on July 14, 1995.  The $30,000,000 bond
       issue is redeemable at the option of the holders in integral multiples
       of $1,000 on February 1, 2002.  These bond issues were used to finance
       NS #2.

       The Company also completed the refinancing of the $12,200,000, City of
       Gillette Pollution Control Revenue Bonds during 1994.  In 1992 the
       Company entered into a forward refunding on the $12,200,000, 10.5
       percent, City of Gillette Pollution Control Revenue Bonds.  The new
       bonds were issued in July 1994 at 7.5 percent, due 2024.

       (4)  NOTES PAYABLE TO BANKS

       The Company had $36,000,000 of unsecured short-term lines of credit at
       December 31, 1995 and $70,000,000 at December 31, 1994.  Borrowings
       outstanding under these lines of credit were $575,000 and $36,975,000 as
       of December 31, 1995 and 1994, respectively.  The weighted average
       interest rate on these borrowings at December 31, 1995 and 1994 was 7.4
       percent and 6.9 percent, respectively.  Average borrowings during 1995
       and 1994 were $6,619,000 and $21,070,000, respectively.  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.

       (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,
       1995.

       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.
<PAGE>





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

<TABLE>
<CAPTION>
                                                                              
                                         1995                    1994
                                 Carrying      Fair     Carrying      Fair
                                  Value        Value      Value       Value
                                               (in thousands)
<S>                            <C>          <C>         <C>         <C>
Cash and cash equivalents       $  8,179    $  8,179    $ 12,174    $ 12,174
Securities available for sale:
 Corporate debt securities         1,000       1,000      12,200      12,200
 State and local agency            5,804       5,804      12,222      12,222
  obligations
Long-term debt                   167,474     194,625     131,069     133,313
</TABLE>

       (6)  WYODAK PLANT

       The Company owns a 20 percent interest and PacifiCorp an 80 percent
       interest in the Wyodak Plant (the Plant), a 330 megawatt coal-fired
       electric generating station located in Campbell County, Wyoming.
       PacifiCorp is the operator of the Plant.  The Company receives 20
       percent of the Plant's capacity and is committed to pay 20 percent of
       its additions, replacements and operating and maintenance expenses.  As
       of December 31, 1995, the Company's investment in the Plant included
       $73,203,000 in electric plant and $23,053,000 in accumulated
       depreciation.  The Company's share of direct expenses of the Plant were
       $6,503,000, $6,945,000 and $6,882,000 for the years ended December 31,
       1995, 1994 and 1993, respectively, and are 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 PacifiCorp 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, 1995, approximately 28,412,000 tons were covered under this
       agreement.  Wyodak Resources' sales to the Plant were $20,224,000,
       $20,671,000 and $21,438,000 for the years ended December 31, 1995, 1994
       and 1993, respectively.

       (7)  COMMITMENTS AND CONTINGENT LIABILITIES

       MDU POWER SALE

       During 1994, the Company entered into a Power Integration Agreement with
       MDU.  The agreement provides that for a period of 10 years commencing
       January 1, 1997, the Company will supply up to 55 megawatts of electric
       power and associated energy required by MDU for its Sheridan, Wyoming,
       service territory.  MDU's Sheridan service area has experienced a 45
       megawatt peak and a load factor of approximately 60 percent.



       COAL OBLIGATIONS

       In addition to the 28,412,000 tons of coal reserved under the agreement
       to supply coal to the Wyodak Plant, Wyodak Resources has reserved
       28,110,000 tons of coal under existing contracts and 51,000,000 tons of
       coal under future purchase options.  None of the purchase options are
       expected to be exercised because the option price is substantially
       higher than the market price.  An option for 50,000,000 tons can be
       exercised only if Wyodak Resources has not committed the coal reserves
       to other buyers prior to the exercise of the option.

       PACIFICORP PURCHASE POWER AGREEMENT

       In 1983 the Company entered into a 40 year power agreement with
       PacifiCorp providing for the purchase of 75 megawatts of electric 
       capacity and energy from its system.  The price paid for the capacity
       and energy is based on the operating costs of one of PacifiCorp's 
       coal-fired electric generating plants.  Costs incurred under this 
       agreement were $20,689,000, $23,132,000 and $21,106,000 in 1995, 1994
       and 1993, respectively.

       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 $600,000 is
       charged to operations as reclamation expense annually.  As of December
       31, 1995, accrued reclamation costs were approximately $8,000,000.

       OTHER

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






       Net pension expense for the Plan was as follows:

<TABLE>
<CAPTION>
                                1995          1994        1993
                                        (in thousands)
       <S>                    <C>           <C>         <C>
       Service cost           $  802        $  865      $  651
       Interest cost           2,169         2,074       1,899
       Return on
       assets:
         Actual               (5,204)       (1,819)     (2,852)
         Deferred              2,603         (793)         333
                              ------        ------      ------
       Net pension            $  370        $  327      $   31
       expense                ======        ======      ======
</TABLE>

       Funding information for the Plan as of October 1 of each year was as
       follows:

                                            1995                1994
                                                 (in thousands)
<TABLE>
<CAPTION>
       <S>                                <C>                  <C>
       Fair value of plan assets          $29,184              $25,584
       Projected benefit obligation       (30,714)             (27,931)
                                          -------              -------
                                           (1,530)              (2,347)
       Unrecognized:
         Net loss                           1,559                2,747
         Prior service cost                   796                  885
         Transition asset                    (451)                (541)
                                          -------              ------- 
       Prepaid pension cost               $   374              $   744
                                          =======              ======= 
       Accumulated benefit obligation     $24,969              $22,649
                                          =======              ======= 
       Vested benefit obligation          $23,919              $21,749
                                          =======              =======
       Actuarial assumptions:
         Discount rate                        7.5%                 8.0%
         Expected long-term rate of
          return on assets                   10.5%                10.5%
         Rate of increase
          in compensaton levels                 5%                   5%
</TABLE>

       The change in the assumed discount rate from 8.0 percent in 1994 to 7.5
       percent in 1995 resulted in an increase in the accumulated benefit
       obligation and projected benefit obligation of $1,381,000 and
       $1,923,000, respectively.

       The Company has various supplemental retirement plans for outside
       directors and key executives of the Company.  The plans are nonqualified
       defined benefit plans.  Expenses recognized under the plans were
       $350,000, $401,000 and $633,000 in 1995, 1994 and 1993, respectively.

       The Company follows Statement of Financial Accounting Standards 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.
<PAGE>
       The net periodic postretirement cost for the Company was as follows:

                                           1995           1994
                                              (in thousands)
<TABLE>
<CAPTION>
       <S>                                 <C>            <C>
       Service cost                        $211           $188
       Interest cost                        429            303
       Amortization of                      150            150
       transition obligation
       Amortization of loss                  79             28
                                           ----           ----
                                           $869           $669
                                           ====           ====
</TABLE>

       Funding information as of October 1 was as follows:

                                          1995            1994
                                             (in thousands)
<TABLE>
<CAPTION>
       <S>                               <C>            <C>
       Accumulated postretirement 
        benefit obligation:
         Retirees                        $1,485         $1,805
         Fully eligible active              723          1,246
          participants
         Other active                     1,906          2,400
          participants
                                         ------         ------
       Unfunded accumulated               4,114          5,451
        postretirement benefit 
        obligation
       Unrecognized net gain                140         (1,838)
        (loss)
       Unrecognized transition           (2,546)        (2,696)
        obligation
                                         ------         ------ 
                                         $1,708         $  917
                                         ======         ======
</TABLE>

       For measurement purposes, a 10.5 percent annual rate of increase in
       healthcare benefits was assumed for 1996; 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 net periodic
       postretirement cost by approximately $116,000 annually or 18.8 percent.
       The weighted-average discount rate used in determining the accumulated
       postretirement benefit obligation was 7.5 percent.

       (9)  INCOME TAXES

       The Company follows Statement of Financial Accounting Standards No. 109,
       "Accounting for Income Taxes," which requires the use of the liability
       method in accounting for income taxes.  Under the liability method,
       deferred income taxes are recognized, at currently enacted income tax
       rates, to reflect the tax effect of temporary differences between the
       financial 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.

       Income tax expense for the years indicated was:

<TABLE>
<CAPTION>
                                                                   
                                  1995         1994         1993
                                           (in thousands)
       <S>                      <C>          <C>           <C>
       Current                  $ 8,640      $ 7,925       $7,923
       Deferred                   2,600        2,975        1,547
       Investment tax              (503)        (505)        (505)
        credits, net
                                -------      -------       ------ 
                                $10,737      $10,395       $8,965
                                =======      =======       ======  
</TABLE>
<PAGE>
       The temporary differences which gave rise to the net deferred tax
       liability at December 31, 1995 and 1994 were as follows:

<TABLE>
<CAPTION>
                                                            NET DEFERRED
                                                               INCOME
                                                              TAX ASSET
       December 31, 1995             ASSETS     LIABILITIES  (LIABILITY)
                                               (in thousands)

       <S>                          <C>            <C>         <C>               
       Accelerated depreciation 
        and other plant-
        related differences         $      -       $42,182     $(42,182)
       Regulatory asset                2,482             -        2,482
       Regulatory liability                -         1,415       (1,415)
       Unamortized investment          1,756             -        1,756
        tax credits
       Mining development                988           898           90
       and oil exploration
       Employee benefits               1,828           137        1,691
       Other                             489           658         (169)
                                      ------       -------     --------
                                      $7,543       $45,290     $(37,747)
                                      ======       =======     ========
</TABLE>

<TABLE>
<CAPTION>
                                                             NET DEFERRED
                                                                INCOME
                                                               TAX ASSET
          December 31, 1994             ASSETS   LIABILITIES  (LIABILITY)
                                                (in thousands)
       <S>                             <C>          <C>         <C>
       Accelerated
        depreciation and               $     -     $34,940     $(34,940)
        other plant-
        related differences
       Regulatory asset                  2,350           -        2,350
       Regulatory liability                  -           -            -
       Unamortized                       2,109           -        2,109
        investment tax
        credits
       Mining development                  678       2,896       (2,218)
        and oil exploration
       Employee benefits                 1,521         278        1,243
       Other                               847       1,839         (992)
                                        ------     -------     --------  
                                        $7,505     $39,953     $(32,448)
                                        ======     =======     ========
</TABLE>

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

<TABLE>
<CAPTION>
                                1995        1994       1993
       <S>                      <C>         <C>        <C>
       Federal statutory        35.0%       35.0%      35.0%
        rate
       Regulatory asset         (1.9)           -          -
        recognition
       Amortization of          (1.4)       (1.5)      (1.6)
        investment tax
        credits
       Tax-exempt interest      (0.8)       (1.1)      (1.7)
        income
       Percentage depletion     (0.4)       (1.7)      (2.8)
        in excess of cost
       Other                    (0.9)       (0.3)      (0.8)
                                ----        ----       ----  
                                29.6%       30.4%      28.1%
                                ====        ====       ====
</TABLE>

       (10)  OIL AND GAS RESERVES  (Unaudited)

       Western Production has interests in 448 producing oil and gas properties
       in eight states.  Western Production's non-operated properties are
       located in the western United States.  Western Production also holds
       leases on approximately 62,000 net undeveloped acres.

       The following table summarizes Western Production's quantities of proved
       developed and undeveloped oil and natural gas reserves, estimated using
       constant year-end product prices, as of December 31, 1995 and 1994, 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.
<PAGE>
<TABLE>
<CAPTION>
                                       1995                1994
                                  OIL       GAS       OIL        GAS
                           (in thousands of barrels of oil and MCF of gas)
       <S>                       <C>       <C>       <C>       <C>
       Proved developed and
       undeveloped
       reserves:
         Balance at              1,438     9,080     1,116      2,759
          beginning of year
           Production             (266)   (1,986)     (321)    (1,731)
           Additions               168     4,106       107      7,582
           Property sales         (103)     (843)        -          -
           Revisions to
            previous estimates
            due primarily to       375    (2,699)      536        470
            changed economic
            conditions
                                 -----     -----     -----      -----
         Balance at end of       1,612     7,658     1,438      9,080
          year                   =====     =====     =====      =====  
                                  
       Proved developed
        reserves at end of       1,606     6,370     1,436      6,246
        year included above      =====     =====     =====      =====

       Year-end prices          $18.50   $  1.90    $15.75    $  1.72

</TABLE>

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

       The three primary segments of the Company's business are its electric,
       coal mining and oil and gas production operations.  The following table
       summarizes certain information specifically identifiable with each
       segment as of or for the years ended December 31.
<TABLE>
<CAPTION>
                                1995       1994      1993
                                     (in thousands)
       <S>                    <C>       <C>        <C>
       Assets at year-end:

          Electric            $380,256  $340,042   $259,680
          Coal mining           45,224    72,851     72,328
          Oil and gas           23,350    23,984     20,845
                              --------  --------   --------
                              $448,830  $436,877   $352,853
                              ========  ========   ========
       Depreciation,
        depletion and
        amortization:
          Electric            $ 11,943  $ 10,314   $  9,952
          Coal mining            3,575     2,427      1,953
          Oil and gas            4,142     4,860      4,146
                              --------  --------   -------- 
                              $ 19,660  $ 17,601   $ 16,051
                              ========  ========   ========
       Capital
       expenditures:
          NS #2 (includes     $ 33,219  $ 73,984   $ 12,792
           AFDC)
          Other electric        11,242    14,187     13,140
          Coal mining            1,546     5,911      7,425
          Oil and gas            5,888     8,977      6,933
                              --------  --------   --------
                              $ 51,895  $103,059   $ 40,290
                              ========  ========   ========  
</TABLE>

       (12)  SUPPLEMENTARY INCOME STATEMENT INFORMATION

       TAXES OTHER THAN INCOME TAXES

<TABLE>
<CAPTION>
                                 1995      1994       1993                       
                                     (in thousands)
       <S>                     <C>       <C>        <C>
       Property                $ 3,696   $ 3,637    $ 3,549
       Production and            3,385     2,995      2,982
       severance
       Payroll                   1,402     1,334      1,195
       Black lung                1,263     1,205      1,256
       Federal reclamation       1,027       979      1,060
       Other                       208       216        166
                               -------   -------    -------
                               $10,981   $10,366    $10,208
                               =======   =======    =======
</TABLE>
<PAGE>





  FINANCIAL STATISTICS

<TABLE>
<CAPTION>
  Years ended December 31       1995      1994      1993      1992      1991
  <S>                         <C>       <C>       <C>       <C>       <C>
  TOTAL ASSETS (in thousands) $448,830  $436,877  $352,853  $330,202  $319,895

  PROPERTY AND INVESTMENTS
   (in thousands)
    Total property and        $557,642  $519,296  $433,143  $413,192  $390,766
     investments
    Accumulated depreciation   164,383   156,046   144,492   132,890   122,574
     and depletion
    Capital expenditures        51,895   103,059    40,290    27,915    36,981
     (includes AFDC)

  CAPITALIZATION (in
   thousands)
    Long-term debt            $166,069  $128,925  $ 85,274  $ 88,816  $ 92,982
    Common stock equity        175,410   149,158   141,963   182,342   168,089
                              --------  --------  --------  --------  --------
       Total                  $348,411  $304,335  $253,363  $237,974  $234,945
                              ========  ========  ========  ========  ========

  CAPITALIZATION RATIOS
    Long-term debt               47.7%     42.4%     33.7%     37.3%     39.6%
    Common stock equity          52.3      57.6      66.3      62.7      60.4
                                -----     -----     -----     -----     -----
       Total                    100.0%    100.0%    100.0%    100.0%    100.0%
                                =====     =====     =====     =====     =====

  AVERAGE INTEREST RATE ON        8.1%      8.5%      9.0%      8.9%      8.9%
   LONG-TERM DEBT

  NET INCOME AVAILABLE FOR
   COMMON STOCK (in thousands) $25,590   $23,805   $22,946   $23,638   $22,681

  DIVIDENDS PAID ON COMMON     $19,312   $18,920   $17,720   $16,977   $16,045
   STOCK (in thousands)

  COMMON STOCK DATA (in
   thousands)*
   Shares outstanding,          14,409    14,339    13,811    13,689    13,675
    average
   Shares outstanding, end of   14,425    14,386    14,270    13,701    13,675
    year
   Earnings per average          $1.78     $1.66     $1.66     $1.73     $1.66
    share, in dollars
   Dividends paid per share,     $1.34     $1.32     $1.28     $1.24     $1.17
    in dollars
   Book value per share, end    $12.64    $12.19    $11.78    $10.89    $10.38
    of year, in dollars

  RETURN ON COMMON STOCK         14.0%     13.6%     13.7%     15.8%     16.0%
   EQUITY

  ALLOWANCE FOR FUNDS USED
   DURING CONSTRUCTION AS        22.9%     16.7%      3.2%      1.6%      0.8%
   PERCENT OF NET INCOME
</TABLE>

         * Common stock data have been adjusted retroactively to reflect
           the three-for-two stock split in March 1992.

<PAGE>

ELECTRIC OPERATION STATISTICS

<TABLE>
<CAPTION>
Years ended December 31     1995       1994       1993       1992       1991
<S>                      <C>        <C>        <C>        <C>        <C>
ELECTRIC ENERGY GENERATED
 AND PURCHASED (megawatt
 hours)
Generated, net station   1,320,630  1,108,530  1,227,084  1,226,153  1,148,259
 output
Purchased and net          473,175    595,872    435,990    397,478    444,848
 interchange                                             
Total generated and      1,793,805  1,704,402  1,663,074  1,623,631  1,593,107
 purchased
Non-firm sales             (60,575)    (1,000)    (7,780)   (10,405)    (1,040)
Company use and losses     (87,512)   (65,651)   (61,336)   (73,627)   (59,896)
                         ---------  ---------  ---------  ---------  ---------
   Total electric        1,645,718  1,637,751  1,593,958  1,539,599  1,532,171
    energy sales         =========  =========  =========  =========  =========  

ELECTRIC ENERGY SALES
 (megawatt hours)
 Residential               383,929    368,953    370,736    339,341    355,691
 General and commercial    513,854    495,909    469,496    446,036    440,043
 Industrial                552,829    583,258    568,316    572,244    550,999
 Public authorities         23,164     23,051     22,621     21,798     21,347 
 Sales for resale          171,942    166,580    162,789    160,180    164,091
                         ---------  ---------  ---------  ---------  ---------
   Total electric        1,645,718  1,637,751  1,593,958  1,539,599  1,532,171
    energy sales         =========  =========  =========  =========  =========  

ELECTRIC REVENUE (in
 thousands)
 Residential              $ 30,433   $ 28,574   $ 27,064   $ 25,366   $ 27,053
 General and commercial     37,663     35,390     32,295     30,742     31,227
 Industrial                 26,495     27,318     25,901     27,106     26,812
 Public authorities          1,775      1,718      1,537      1,586      1,593
 Sales for resale            8,366      7,460      7,122      7,002      7,223
                          --------   --------   --------   --------   -------- 
   Total electric          104,732    100,460     93,919     91,802     93,908
    revenue
 Other revenue               4,051      4,296      4,236      5,646      4,250
                          --------   --------   --------   --------   --------
   Total revenue          $108,783   $104,756   $ 98,155   $ 97,448   $ 98,158
                          ========   ========   ========   ========   ======== 
ELECTRIC CUSTOMERS 
 (end of year)
 Residential                45,886     45,060     44,657     44,100     43,539
 General and commercial      8,958      8,732      8,507      8,279      8,083
 Industrial                     35         36         41         38         40
 Public authorities            138        130        124        117        112
 Other electric                  1          1          1          1          1
  utilities             
                            ------     ------     ------     ------     ------
   Total                    55,018     53,959     53,330     52,535     51,775
                            ======     ======     ======     ======     ======
RESIDENTIAL STATISTICS
 Average annual KWH
  usage:
  With electric heating     16,901     16,369     17,601     15,380     16,773
  Without electric           6,688      6,488      6,428      6,172      6,502
   heating
  All residential            8,452      8,198      8,351      7,743      8,218
  Average price per KWH,       7.9        7.7        7.3        7.5        7.6
   in cents

AVERAGE PRICE PER KWH,
 ALL SALES                     6.1        6.1        5.9        5.9        6.1
 (in cents)

AVERAGE PRICE PER KWH,         6.3        6.1        5.9        5.9        6.1
 FIRM SALES (in cents)
</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 21, 1996.

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

       Dale E. Clement, 62, Senior Vice President - Finance
          Mr. Clement was elected to his present position in September 1989.

       Roxann R. Basham, 34, Secretary and Treasurer
          Ms. Basham was elected to her present position January 1, 1993.  She
          had served as Assistant Secretary/Treasurer since May 1991 and as     
          Financial Analyst since February 1985.

       Gary R. Fish, 37, Controller
          Mr. Fish was elected to his present position in August 1988.

       Everett E. Hoyt, 56, President and Chief Operating Officer of Black
       Hills Power
          Mr. Hoyt was elected to his present position in October 1989.

       Thomas M. Ohlmacher, 44, Vice President - Power Supply
          Mr. Ohlmacher was elected to his present position on August 1, 1994.
          He had served as Director of Power Generation since 1993 and Director
          of Electric Operations since 1991.

       James M. Mattern, 41, Vice President - Administration
          Mr. Mattern was elected to his present position on August 1, 1994.  He
          had served as Rapid City Area Manager since January 1994 and Director
          of Human Resources since 1991.

       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 21, 1996.

       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 21, 1996.

       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 21, 1996.
<PAGE>
                                     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 24,1994 (Exhibit
                3(i) to Form 8-K dated June 7, 1994, File No. 1-7978).

           3(b) Bylaws dated January 30, 1996.

          *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).

          *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) Coal Supply Agreement and First Amendment dated September 1,
                 1977, between the Company and Wyodak Resources Development 
                 Corp. (Exhibit 5(g) to Form S-7, File No. 2-60755).  Second
                 Amendment to Coal Supply Agreement dated November 2, 1987
                 (Exhibit 10(f) to Form 10-K for 1987).  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 Lease dated May 1, 1959, between Wyodak Resources
                 Development Corp. and the Federal Government (Exhibit 5(i) to
                 Form S-7, File No. 2-60755).  Modified coal lease dated
                 January 22, 1990, between Wyodak Resources Development Corp. 
                 and the Federal Government (Exhibit 10(h) to Form 10-K for
                 1989).

          *10(d) Coal Lease dated April 1, 1961, between Wyodak Resources
                 Development Corp. and the Federal Government (Exhibit 5(j) to
                 Form S-7, File No. 2-60755).  Modified coal lease dated January
                 22, 1990, between Wyodak Resources Development Corp. and the
                 Federal Government (Exhibit 10(i) to Form 10-K for 1989).

          *10(e) Coal Lease dated October 1, 1965, between Wyodak Resources
                 Development Corp. and the Federal Government, as amended 
                 (Exhibit 5(k) to Form S-7, File No. 2-60755).  Modified coal
                 lease dated January 22, 1990, between Wyodak Resources 
                 Development Corp. and the Federal Government (Exhibit 10(j)
                 to Form 10-K for 1989).

          *10(f) Participation Agreement dated May 16, 1978, and various
                 related agreements dated June 8, 1978, including, without
                 limitation, Lease Agreement, Amended and Restated Coal Supply
                 Agreement, Coal  Supply System Agreement and Security Agree-
                 ment, and Real Estate Mortgage (all relating to the lease 
                 financing of the Wyodak Plant and the dedication by Wyodak
                 Resources Development Corp. of coal deposits with respect
                 thereto) filed pursuant to item 6(b) of Amendment No. 1 to
                 Registrant's Current Report on Form 8-K for June 1978 and 
                 located in Commission File No. 2-4832.  Further Restated and
                 Amended Coal Supply Agreement dated May 5, 1987 (Exhibit 
                 10(k) to Form 10-K for 1987).



          *10(g) Power Sales Agreement dated December 31, 1983, between Pacific
                 Power & Light Company and the Company (Exhibit 7(b) to Form 8-K
                 for January 1984, File No. 0-0164).

          *10(h) 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(i) Coal lease dated February 16, 1983, between Wyodak Resources
                 Development Corp. and the Federal Government (Exhibit 10(p) to
                 Form 10-K for 1983).

          *10(j) Coal lease dated September 28, 1983, between Wyodak Resources
                 Development Corp. and the Federal Government (Exhibit 10(q) to
                 Form 10-K for 1983).

          *10(k) Indenture of Trust dated as of June 1, 1992, City of Gillette,
                 Campbell County, Wyoming, to Norwest Bank Minnesota, National
                 Association, as Trustee (Black Hills Power and Light Company
                 Project) (Exhibit 10(n) to Form 10-K for 1992).

          *10(l) Loan Agreement dated as of June 1, 1992, by and between City
                 of Gillette, Campbell County, Wyoming, and the Company (Exhibit
                 10(o) to Form 10-K for 1992).

          *10(m) Loan Agreement dated as of June 1, 1992, by and between
                 Lawrence County, South Dakota and the Company (Exhibit 10(p) to
                 Form 10-K for 1992).

          *10(n) Indenture of Trust dated as of June 1, 1992, Lawrence County,
                 South Dakota, to Norwest Bank Minnesota, National Association,
                 as Trustee (Black Hills Power and Light Company Project)
                 (Exhibit 10(q) to Form 10-K for 1992).

          *10(o) Loan Agreement dated as of June 1, 1992, by and between
                 Pennington County, South Dakota and the Company (Exhibit 10(r)
                 to form 10-K for 1992).

          *10(p) Indenture of Trust dated as of June 1, 1992, Pennington
                 County, South Dakota, to Norwest Bank Minnesota, National
                 Association, as Trustee (Black Hills Power and Light Company
                 Project) (Exhibit 10(s) to Form 10-K for 1992).

          *10(q) Loan Agreement dated as of June 1, 1992, by and between Weston
                 County, Wyoming and the Company (Exhibit 10(t) to Form 10-K for
                 1992).

          *10(r) Indenture of Trust dated as of June 1, 1992, Weston County,
                 Wyoming, to Norwest Bank Minnesota, National Association, as
                 Trustee (Black Hills Power and Light Company Project) (Exhibit
                 10(u) to Form 10-K for 1992).

          *10(s) Loan Agreement dated as of June 1, 1992, by and between
                 Campbell County, Wyoming and the Company (Exhibit 10(v) to 
                 Form 10-K for 1992).
<PAGE>
          *10(t) Indenture of Trust dated as of June 1, 1992, Campbell County,
                 Wyoming, to Norwest Bank Minnesota, National Association, as
                 Trustee (Black Hills Power and Light Company Project) (Exhibit
                 10(w) to Form 10-K for 1992).

           10(u) Second Restated Electric Power and Energy Supply and
                 Transmission Agreement dated February 28, 1995, by and between
                 the Company and the City of Gillette, Wyoming.

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

          *10(x) Retirement Plan for Outside Directors dated January 1, 1993
                 (Exhibit 10(cc) to Form 10-K for 1992).

          *10(y)  The Amended and Restated Pension Equalization Plan of Black
                  Hills Corporation dated January 27, 1995.

           10(z) Black Hills Corporation 1996 Executive Gainsharing Program.

          10(aa) Black Hills Corporation 1996 Results Compensation Program.

         *10(ab) The Amended and Restated Pension Plan of Black Hills
                 Corporation.

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

         *10(ad) Agreement for Supplemental Pension Benefit for Dale E.
                 Clement dated December 19, 1991 (Exhibit 10(hh) to
                 Form 10-K for 1992).

         *10(ae) 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(af) Change in Control Agreements dated January 30, 1996
                 for Daniel P. Landguth, Dale E. Clement, Everett E. Hoyt,
                 Thomas M. Ohlmacher, James M. Mattern, Roxann R. Basham and
                 Gary R. Fish.

          10(ag) Marketing, Capacity and Storage Services Agreement between
                 Black hills Corporation and PacifiCorp dated September 1, 1995.

          21     Subsidiaries of the Registrant.

          23     Consent of Independent Public Accountants.

          27     Financial Data Schedule.




         * Exhibits incorporated by reference.


       (b) No reports on Form 8-K have been filed in the quarter ended December
           31, 1995.
       (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 /c/   DANIEL P. LANDGUTH          
                                     Daniel P. Landguth, Chairman,
                                     President and Chief Executive

       Dated:  March 15, 1996

          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.


       /c/DANIEL P. LANDGUTH            Director and Principal    March 15, 1996
       Daniel P. Landguth (Chairman,    Executive Officer
        President, and Chief Executive)

       /c/DALE E. CLEMENT               Director and Principal    March 15, 1996
       Dale E. Clement (Senior Vice     Financial Officer
       President - Finance)

       /c/GARY R. FISH                  Principal Accounting      March 15, 1996
       Gary R. Fish (Controller)        Officer

       /c/GLENN C. BARBER               Director                  March 15, 1996
       Glenn C. Barber

       /c/BRUCE B. BRUNDAGE             Director                  March 15, 1996
       Bruce B. Brundage

       /c/KIRK E DEAN                   Director                  March 15, 1996
       Kirk E. Dean

       /c/MICHAEL B. ENZI               Director                  March 15, 1996
       Michael B. Enzi

       /c/JOHN R. HOWARD                Director                  March 15, 1996
       John R. Howard

       /c/EVERETT E. HOYT               Director and Officer      March 15, 1996
       Everett E. Hoyt (President
        and Chief Operating Officer
        of Black Hills Power)

       /c/KAY S. JORGENSEN              Director                  March 15, 1996
       Kay S. Jorgensen

<PAGE>
       DIRECTORY

        COMMON STOCK

          Transfer Agent, Registrar and Dividend Disbursing Agent

          Norwest Shareowner Services
          P.O. Box 64854
          St. Paul, MN  55164-0854
          1-800-468-9716

        FIRST MORTGAGE BONDS

          Trustee and Paying Agent

          Chemical Bank
          450 West 33rd Street
          New York, New York  10001

        POLLUTION CONTROL AND INDUSTRIAL DEVELOPMENT REVENUE BONDS

          Trustee and Paying Agent

          Norwest Bank Minnesota, N.A.
          Eighth Street and Marquette Avenue
          Minneapolis, Minnesota  55479

        ENVIRONMENTAL IMPROVEMENT REVENUE BONDS

          Trustee and Paying Agent

          First National Bank of Chicago
          One First National Plaza
          Chicago, Illinois  60670

        GENERAL COUNSEL

         Morrill Brown Thomas & Nooney LLP
         P.O. Box 8108
         Rapid City, South Dakota  57709

        CORPORATE OFFICES

         Black Hills Corporation
         P.O. Box 1400
         Rapid City, South Dakota  57709
         (605) 348-1700

       1996 ANNUAL MEETING

       The Annual Meeting of Shareholders will be held at the Holiday Inn -
       Rushmore Plaza Hotel, 505 North Fifth Street, Rapid City, South Dakota,
       at 9:30 A.M., on May 21, 1996.  Prior to the meeting, formal notice,
       proxy statement, and proxy will be mailed to shareholders.

       DIRECT DEPOSIT OF DIVIDENDS

       The Company encourages you to consider the direct deposit of your
       dividends.  With direct deposit, your quarterly dividend payment can be
       automatically transferred on the dividend payment date to the bank,
       savings and loan, or credit union of your choice.  Direct deposit
       assures payments are credited to shareholders' accounts without delay.
       A form is attached to your dividend check where you can request
       information about this method of payment.  Questions regarding direct
       deposit should be directed to Norwest Shareowner Services.

       DIVIDEND REINVESTMENT PLAN

       A Dividend Reinvestment and Stock Purchase Plan (the Plan) is available
       to  common shareholders.  The Plan provides a method of investing common
       stock dividends and optional cash payments in additional shares of
       common stock of the Company at 100 percent of the recent average market
       price.  The participant may  elect to continue to receive cash dividends
       on shares registered in their names  and invest by making optional cash
       payments only.  Questions regarding the Plan should be directed to the
       Secretary of the Company or Norwest Shareowner Services.

<PAGE>