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

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

     For the fiscal year ended December 31, 1999

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

     For the transition period from ___________________ to __________________

     Commission File Number 1-7978

                             BLACK HILLS CORPORATION

     Incorporated in South Dakota           IRS Identification Number 46-0111677

                                625 Ninth Street
                         Rapid City, South Dakota 57701

               Registrant's telephone number, including area code
                                 (605) 721-1700

     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 January 31, 2000       $511,580,784

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 January 31, 2000

    Common stock, $1.00 par value                    21,371,521 shares

Documents Incorporated by Reference

1.   Definitive  Proxy Statement of the Registrant  filed pursuant to Regulation
     14A for the 2000  Annual  Meeting  of  Stockholders  to be held on June 20,
     2000, 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 THE ELECTRIC UTILITY BUSINESS...............7
                   INDEPENDENT ENERGY OPERATIONS.............................11
                   COMMUNICATIONS OPERATIONS.................................12
                   ENVIRONMENTAL REGULATION..................................13
                   EMPLOYEES.................................................16

ITEM 2.       PROPERTIES.....................................................16
                   ELECTRIC PROPERTIES.......................................16
                   INDEPENDENT ENERGY PROPERTIES.............................17
                   COMMUNICATIONS PROPERTIES.................................18

ITEM 3.       LEGAL PROCEEDINGS..............................................18

ITEM 4.       SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............18

ITEM 5.       MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
              STOCKHOLDER MATTERS............................................19

ITEM 6.       SELECTED FINANCIAL DATA........................................19

ITEM 7.       MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
              CONDITION AND RESULTS OF OPERATIONS............................20
                   LIQUIDITY AND CAPITAL RESOURCES...........................20
                   MARKET RISK DISCLOSURES...................................22
                   RATE REGULATION...........................................25
                   RESULTS OF OPERATIONS.....................................26
                   BUSINESS OUTLOOK STATEMENTS...............................31

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................33

ITEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
              ON ACCOUNTING AND FINANCIAL DISCLOSURE.........................55

ITEM 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.............55

ITEM 11.      EXECUTIVE COMPENSATION.........................................56

ITEM 12.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.56

ITEM 13.      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................56

ITEM 14.     EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.56

              SIGNATURES.....................................................59




<PAGE>



                                   DEFINITIONS

When the  following  terms  are used in the text  they  will  have the  meanings
indicated.
<TABLE>
<CAPTION>
Term                                        Meaning
----                                        -------
<S>                                         <C>

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

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

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

Black Hills Exploration and Production......Black Hills Exploration and Production, Inc., a wholly owned subsidiary of Wyodak
                                            Resources

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

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

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

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

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

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

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

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

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

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

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

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

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

</TABLE>


<PAGE>


PART I

ITEM 1.   BUSINESS

                                     GENERAL


Incorporated  under the laws of South  Dakota in 1941,  the Company is an energy
and  communications  company  primarily  consisting of three principal  business
units: regulated electric, independent energy and communications.  The Company's
mission statement is to provide quality energy and  communications  products and
services  at  competitive   prices  in  targeted  markets  to  build  value  for
shareholders and customers and create  opportunities for employees.  The Company
operates its public utility electric  operations under the assumed name of Black
Hills  Power and Light  Company;  operates  its  independent  energy  businesses
through its direct and indirect subsidiaries:  Wyodak Resources related to coal,
Black Hills  Exploration  and Production  related to oil and natural gas, energy
marketing  through  Enserco  Energy,  Inc.  related to natural gas,  Black Hills
Energy Resources,  Inc. related to crude oil and Black Hills Coal Network,  Inc.
related to coal, and independent  power activities though Black Hills Generation
and Black Hills Energy Capital, all consolidated for reporting purposes as Black
Hills Energy Ventures and, operates communication operations through Black Hills
Fiber Systems, Inc., Black Hills FiberCom, LLC and DAKSOFT, Inc.

Black  Hills  Power  is  engaged  in  the  generation,  purchase,  transmission,
distribution  and sale of  electric  power and  energy to  approximately  57,700
customers  in 11  counties in western  South  Dakota,  northeastern  Wyoming and
southeastern  Montana,  an area with a  population  estimated  at  165,000.  The
largest community served is Rapid City, South Dakota, a major retail,  wholesale
and health care center,  with a  population,  including  environs,  estimated at
75,000.  Agriculture,  tourism, small stakes gambling,  mining, lumbering, small
item  manufacturing,  service  and support  businesses  and  government  support
through  Ellsworth  Air Force Base are the primary  influences  on the  economic
well-being of the region.

Black  Hills  Energy  Ventures  is  engaged in the mining and sale of low sulfur
sub-bituminous  coal near Gillette,  Wyoming, in the Powder River Basin; has oil
and gas  exploration  and production  operations  with interests  located in the
Rocky Mountain region,  Texas,  California and various other locations;  markets
natural gas,  crude oil and coal to the East Coast,  Midwest,  Southwest,  Rocky
Mountain,  Northwest  and West Coast regions and owns  interests in  independent
power  production  facilities  in  the  Rocky  Mountain  region.  Communications
operations provide local and long-distance telephone, cable television, internet
and data  services  in the Black  Hills of South  Dakota,  and  development  and
marketing of software products for the utility and communications industries.

Black Hills Capital Group directs the Company's  corporate  development  efforts
primarily in the energy and communications areas.

Information as to the  continuing  lines of business of the Company for the
calendar years 1999-1997 is as follows:


                               1999         1998         1997
                               ----         ----         ----
                                    (in thousands)
Revenue from sales
to unaffiliated customers:
  Electric                     $132,799     $128,834     $126,194
  Independent energy            650,711      539,762      176,076
  Communications                    278            -            -

Revenue from
  inter-company sales:
   Electric                    $    423     $    402    $     303
   Independent
     energy                       7,664       10,256       11,089

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

                              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 361  megawatts was reached in July
1999.  Black Hills Power is a member of a power pool, the Rocky Mountain Reserve
Group. Black Hills Power's 1999 reserve requirement,  and estimated 2000 reserve
requirement,  is 20 megawatts,  consisting of 10 megawatts of spinning  reserves
and 10 megawatts of secondary reserves.


<PAGE>

Black Hills Power owns coal-fired  generating  units having a summer  capability
rating of 214  megawatts  and 77  megawatts  of  oil-fired  diesel  and  natural
gas-fired  combustion  turbines for peaking and standby use. In addition,  Black
Hills Power is currently constructing a 40 megawatt natural gas-fired combustion
turbine for  additional  peaking  resources  and load growth.  Black Hills Power
purchases  additional  resources under three  contracts with Pacific Power:  the
Power Sales  Agreement,  under which it purchases 75 megawatts of baseload power
declining to 50 megawatts  from 2000 to 2004; the Reserve  Capacity  Integration
Agreement,   under  which  33  megawatts  of  additional  reserve  capacity  are
available;  and the Capacity Contract, under which Black Hills Power has options
to be exercised seasonally to purchase up to 60 megawatts of capacity.

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

This  agreement  obligates  Black Hills Power to purchase  from Pacific Power 75
megawatts of electric  power plus energy at a load factor varying from a minimum
of 41 percent to a maximum of 80 percent as scheduled  by Black Hills Power.  In
October 1997, Black Hills Power entered into a second Restated and Amended Power
Sales Agreement with Pacific Power. The Amended  Agreement  reduces the contract
capacity by 25 megawatts (5 megawatts per year beginning in 2000).  The contract
terminates  December  31,  2023.  The power and energy  delivered  is power from
Pacific  Power's  system and does not  depend on any one unit,  but the price is
generally  based on  Pacific  Power's  costs  in  Units 3 and 4 of the  Colstrip
coal-fired generating plant near Colstrip,  Montana. Black Hills Power contracts
for transmission  service from Pacific Power under Pacific Power's FERC approved
transmission rates. The Company has incurred average capacity charges of $14,400
per megawatt  month and energy charges of $11.46 per megawatt hour over the last
three  years of this  agreement  with a 70 percent  load  factor for a total per
megawatt hour cost of $34.47.

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

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

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

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

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


<PAGE>


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

                      ELECTRIC SERVICE TERRITORY AND SALES

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

Black Hills Power's service territory is currently protected by assigned service
area and  franchises  that  generally  grant to Black Hills Power the  exclusive
right to sell all electric power consumed therein, subject to providing adequate
service.

As  evidenced by a 1 percent  increase in  customers in both 1999 and 1998,  the
economy in and around  Black  Hills  Power's  service  territory  is believed by
management to be stable.  Small  businesses  and regional  plant  expansions are
continually  being  attracted  to  the  region  along  with  retirees  who  have
discovered the Black Hills region with its scenery,  recreational activities and
medical services to be an attractive place to live. Management  anticipates that
the  economy  will  continue  to  experience  modest  growth,  but  can  give no
assurances,  as many  economic  factors  will  greatly  influence  any  economy.
Ellsworth Air Force Base, a B-1 bomber  military base near Rapid City,  survived
the fourth  round of base  closures  in 1995 but may be  subject to future  base
closures that are beyond the Company's  control.  The Company does not serve the
air base,  but the base  impacts  the  surrounding  economy.  In  January  1998,
Homestake  Mining Company  (Homestake),  the Company's third largest customer at
4.3  percent  of  1999  electric   revenues,   announced  a  reorganization  and
restructuring  plan at its gold mine in Lead,  South Dakota.  Load reductions at
Homestake were mitigated by additional  off-system  wholesale sales. Other major
industries  in and  around  Black  Hills  Power's  service  territory  have been
economically stable.

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

Black Hills  Power sells  electric  power and energy to the  municipal  electric
system at Gillette,  Wyoming.  Service is rendered  under a long-term  contract,
amended in 1998,  and expiring July 1, 2012,  wherein Black Hills Power sells to
the City of Gillette  its first 23 megawatts  of capacity  requirements  and the
associated  energy. In 1998, as part of a contract  amendment,  the transmission
service   component  was  unbundled  from  the  power  supply   agreement,   and
transmission  service will be provided at FERC  approved  rates.  In the amended
contract,  the City of  Gillette  has  agreed  not to apply to FERC for any rate
change to be  effective  prior to January 1, 2003,  unless and in the event that
Black Hills Power files for a rate change with FERC, which rate filing cannot be
effective prior to January 1, 2002, except under extraordinary events as defined
in the  contract.  In  addition,  Black  Hills  Power  agreed  to phase in price
reductions  for the power  purchased  by the City of  Gillette.  The most recent
average  annual   capacity   factor  for  this  23  megawatt   demand  has  been
approximately  92  percent.  Sales to Gillette  represented  9.6 percent and 9.5
percent of total firm  energy  sales and 5.9  percent and 6.1 percent of revenue
from total firm electric sales in 1999 and 1998, respectively.

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

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

The agreement provides for fixed rates for capacity and energy to be paid by MDU
during the 10-year  contract term.  Black Hills Power and MDU have agreed not to
apply to FERC for any rate changes in the  contract for the entire  10-year term
other than increases caused by governmental  direct taxes on electric generation
fired by hydrocarbons.  The agreement further provides for Black Hills Power and
MDU to  equally  share  the  costs  of  constructing  a  combustion  turbine  of
approximately 70 megawatts at such time during the 10-year term that Black Hills
Power  determines in its sole  discretion  that such turbine is required.  While
Black Hills Power has begun construction of a 40 megawatt  gas-fired  combustion
turbine,   and  approached  MDU  with  the  right  of   participation   in  such
construction,  MDU  has  declined  participation  in  this  project.

<PAGE>

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

Black Hills Power sold  445,700,  371,100  and  279,600  megawatt  hours of
non-firm energy in 1999, 1998 and 1997 respectively.  The selling price is based
on spot market prices.

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

Black Hills Power furnishes long-term transmission services under two contracts:
(i) the transmission  contract  terminating  December 31, 2020 (1986 Agreement),
among  Black  Hills  Power  and  Basin  Electric  and  the  other   distribution
cooperatives as it concerns the  transmission  contract (the  Cooperatives)  and
(ii) the agreement with the City of Gillette terminating July 1, 2012 (described
under  Wholesale to City of Gillette  above),  under which Black Hills Power has
agreed to deliver all of the City of Gillette's electric requirements. The rates
charged under the transmission  contract with the Cooperatives are fixed formula
rates, and the transmission rates under the Gillette contract are established by
FERC under Black Hills Power's open access transmission tariff.

In 1998,  the FERC  approved a settlement  in Black Hills' Order 888 open access
transmission  tariff  filing.  This  settlement  allows  Black  Hills to use the
revenues received under the long-term transmission agreement between the Company
and the Cooperatives which terminates on December 31, 2020 as being equal to the
cost of providing  service to the Cooperatives.  The Cooperatives'  transmission
loads are not considered when calculating Black Hills' open access  transmission
tariff rates;  and as such,  the  Cooperatives  are paying less than their fully
allocated cost for use of the transmission  system.  But as a result of allowing
the revenue credit  methodology,  the open access transmission rates still allow
Black Hills to earn a just and reasonable rate on its  transmission  facilities.
The  settlement  with the FERC is consistent  with past actions of the SDPUC and
WPSC,  which  similarly  have  allowed  Black  Hills to use the  revenue  credit
methodology in determining bundled rates for retail customers.

Finally,  to the extent  that a  transmission  customer  (other than Black Hills
Power  or  the   Cooperatives)   arranges  for   transmission   service  on  the
Cooperatives'  transmission  facilities as defined in the 1986 Agreement for the
purposes of serving the  transmission  customer's  retail  customers  within the
joint transmission area as defined within the 1986 Agreement,  Black Hills Power
shall provide a credit,  not to exceed its tariff rate,  against their rates for
transmission service it charges to such transmission customer for its use of the
Cooperatives'  transmission  facilities  to serve  the  transmission  customer's
retail customers within the joint transmission area.

Black Hills  Power does not  anticipate  any  material  use of its  transmission
system by third-parties  until such time that retail wheeling may be instituted.
It is uncertain at this date as to what extent the FERC or the state  regulatory
jurisdictions will have jurisdiction over determining retail wheeling rates.

                  COMPETITION IN THE ELECTRIC UTILITY BUSINESS

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

In 1998,  Black Hills Power initiated an effort to enter into new contracts with
its largest industrial customers. During 1999, this effort was expanded to cover
most of Black Hills Power's  larger  commercial  and  industrial  accounts.  The
contracting effort had two parts, the first being customer specific negotiations
with  industrial  customers  with  loads  greater  than  5 MW.  These  customers
typically were being served under  contracts that had matured to the point where
the customer  could  exercise  its right to extend the  contract  annually to in
effect have a three-year remaining term (right-to-extend term).

Part two of the  effort  was the  design  and  approval  by the SDPUC of the new
General Service  Large-Optional  Combined  Account  Billing tariff.  This tariff
allows customers with multiple  accounts  eligible for the General Service Large
tariff to aggregate  these loads prior to billing  under a declining  block rate
schedule modeled after the existing General Service Large rate.

A key  provision  of the  new  tariff  and  large  industrial  contracts  is the
agreement  of the  customer to grant  Black  Hills  Power a  five-year  right to
continue  to  serve  the  customer  if  deregulation  occurs  (meet  or  release
contracts).  This right is essentially  an option to serve the  customer's  firm
power requirements at market prices.

<PAGE>


As of February 2000, Black Hills Power has replaced all but two of the 1995 rate
case  "right-to-extend  term" contracts with the "meet or release" approach.  Of
the two  remaining  contracts,  the  largest  customer  (approximately  5 MW) is
expected to sign a five-year fixed term contract,  while the other customer is a
curtailable  load that was not targeted for the new contract.  The new contracts
cover 6 large industrial customers representing 62 MW of load.

In addition,  Black Hills Power was successful in  implementing  the new General
Service  Large-Optional  Combined Account Billing tariff.  In all, 22 customers,
representing  104 accounts and 33 MW of the 40 MW of  estimated  eligible  load,
have elected service and signed contracts under the new tariff.

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.

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

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

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

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

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

<PAGE>

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

The business of electric  generation is no longer  reserved  exclusively for the
traditional  public utility such as Black Hills Power.  The Energy Policy Act of
1992 exempted  independent  power producers  engaged  exclusively in the sale of
power at wholesale from the onerous  restrictions  of the Public Utility Holding
Company  Act.  The  Public  Utility  Regulatory  Policies  Act of  1978  (PURPA)
authorizes entities generating electricity from waste fuel and renewable fuel or
utilizing steam for both generation and other purposes to force a public utility
to purchase the energy at an avoided  cost.  These laws,  together with the FERC
mandating all public utilities under its jurisdiction to file tariffs  providing
transmission  access  for sales of energy at  wholesale,  have  caused  electric
generation and the marketing of electric energy at wholesale to become extremely
competitive. While independent power producers, other than qualifying facilities
under PURPA,  are regulated by the FERC, the FERC is allowing rates for the sale
of  generation  to be  determined  by the  market  rather  than by  costs if the
producer or marketer can demonstrate no market power.

As a result of these changes in the law and regulations,  the traditional public
utility,  such as Black Hills Power,  is more likely to purchase energy required
for its franchised service  territories  through  competitive bidding and either
not  expand  its rate base  generating  capabilities  or engage in the  electric
generation  business  through  independent  power  producers by selling to other
utilities.  (See ITEM 7.  MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF  FINANCIAL
CONDITION AND RESULTS OF OPERATIONS  -RESULTS OF OPERATIONS - Independent  Power
Production.)

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

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

This  waiver  will  remain in effect  until such time that Black  Hills Power is
determined  (by FERC) to not be  providing  information  about its  transmission
network to other potential system users.

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

In 1996,  the FERC adopted Order 888 that requires each public utility under its
jurisdiction to file open access  transmission  tariffs that provide rates which
are comparable to the same transmission  costs of the public utility to transmit
power over its system. The rates provide for various transmission services to be
provided for any competitor but apply to the  transmission of electric power for
wholesale  purposes only. FERC has  established  Black Hills Power's open access
transmission tariffs. The regulations further require the public utility to keep
posted  for  public  access,  on  an  electronic  bulletin  board,  all  current
information  concerning  the  availability  and  rates  for  these  transmission
services.  In 1996,  Black Hills Power was granted an extension by FERC to delay
establishing an electronic bulletin board until WAPA, which operates the control
area in which Black Hills Power is located,  establishes or  participates  in an
electronic  bulletin  board.  In June,  1999,  Black Hills Power obtained a full
waiver  (from FERC) from  meeting  these  electronic  bulletin  board  reporting
requirements.  The  public  utilities  are  further  required  by FERC to  adopt
standards of conduct  which require the  functional  separation of those persons
who operate and market the  transmission  system from those  persons who buy and
sell power for the same  utility;  however,  the FERC  granted a waiver to Black
Hills Power from the  requirement  to adopt the  standards of conduct in view of
Black Hills Power's small  transmission  system and lack of  significant  market
control.  The  regulations  are  designed  to  attempt to  eliminate  any market
advantage of the utility owning  transmission over others engaged in the sale of
electric power at wholesale.

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

<PAGE>

Black Hills Power currently  furnishes  transmission  service for competing RECs
through  contract.  As long as the states in which Black  Hills  Power  operates
continue to grant exclusive service territories, the federal government does not
preempt  this state  jurisdiction  and  municipalities  in Black  Hills  Power's
service territory do not establish  municipal electric systems,  the increase in
transmission   access  for  wholesale   purposes  through  Black  Hills  Power's
transmission system is not likely to have any material adverse effect upon Black
Hills  Power.  Such  open  access  may  have  a  beneficial  effect  by  opening
opportunities  for the Company to further the  marketing  of  coal-fired  energy
outside of its service  territory.  On December 20, 1999,  the FERC issued Order
No.  2000,  Final Rule on  Regional  Transmission  Organizations  ("RTOs").  The
objective of FERC is for all transmission-owning  entities, including non-public
utility entities,  to place their  transmission  facilities under the control of
appropriate RTOs in a timely manner.  Black Hills Power is a FERC jurisdictional
utility  and per  Order  2000  will be  required  to make a filing  with FERC by
October  15,  2000 which will  either  contain a proposal  for  establishing  an
operational  RTO by  December  15,  2001,  or a  description  of our  efforts to
participate  in an RTO, any existing  obstacles in achieving RTO  participation,
and any plans to work  towards  RTO  participation.  Black  Hills Power has been
actively  participating  in various  discussion  groups in reviewing some of the
various aspects  associated with  participating  and  establishing  this type of
organization  for this region.  Black Hills Power will be making a filing to the
FERC.

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

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

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

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

<PAGE>


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

                               INDEPENDENT ENERGY

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

Wyodak  Resources  sells coal to Black Hills  Power for all of its  requirements
under an agreement that limits earnings from all coal sales to Black Hills Power
(including the 20 percent share on the Wyodak Plant and all sales to Black Hills
Power's  other  plants)  to  a  return  on  Wyodak  Resources'   original  cost,
depreciated  investment  base.  The return is 4 percent (400 basis points) above
A-rated utility bonds to be applied to Wyodak  Resources' coal mining investment
base as determined each year.  Black Hills Power made a commitment to the SDPUC,
the WPSC and the City of  Gillette  that coal would be  furnished  and priced as
provided by this agreement for the life of NS #2. Earnings from the intercompany
sales  of coal  at  this  time  represent  4.5  percent  of the  Company's  1999
consolidated earnings.

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

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

1999                 $31,095              25            3,180
1998                  31,413              33            3,280
1997                  31,080              36            3,251


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

Wyodak Resources  furnishes all of the fuel supply for the Wyodak Plant in which
Black Hills  Power owns a 20 percent  interest  and Pacific  Power an 80 percent
interest.  (See Note 6 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.) The price
for  unprocessed  coal sold to Pacific Power for its 80 percent  interest in the
Wyodak  Plant is  determined  by a coal supply  agreement  entered into by Black
Hills Power,  Pacific Power and Wyodak  Resources in 1978 and terminating in the
year 2013.  This  agreement was amended and restated in 1987.  Revenue from coal
sales to the Wyodak Plant totaled  $24,883,000  in 1999 or 80 percent of revenue
for all coal sold by Wyodak Resources. The quantity of coal sold in 1999 for the
Wyodak Plant was  2,078,000  tons,  as compared to 2,120,000  tons sold in 1998.
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 14 years of the coal
agreement.   However,   from  time  to  time,  the  plant's  physical  operating
capabilities will affect the quantity of coal burned.

Of the 3,180,000 tons of coal sold by Wyodak  Resources in 1999,  1,398,000 tons
were sold to Black Hills Power,  1,663,000  tons were sold to Pacific  Power and
119,000 tons were sold to others.

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

                             1999        1998        1997
                             ----        ----        ----
                                    (in thousands)
Sales to:
Pacific Power               $22,610     $20,263     $19,240
Black Hills Power             7,664      10,256      11,089
All unaffiliated
customers                    23,431      21,157      19,991

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

The Company's oil and gas production is sold at or near the wellhead,  generally
at prevailing  posted prices.  Black Hills  Exploration  and Production has been
able to market all of its oil and gas  production.  Oil and natural gas revenues
are subject to market price volatility.

<PAGE>


Operating revenue by source for the last three years was as follows:

                Oil and Gas      Gas Plant          Field
     Year           Sales         Revenue         Services
     ----       -----------      ---------        --------
                                (in thousands)

1999                $10,075         $738             $2,239
1998                  9,204          613              2,745
1997                  9,763          755              2,777

Black Hills  Exploration and Production sold  approximately  783,000  equivalent
barrels of oil in 1999 comprised of 59 percent gas and 41 percent oil.

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

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

In  September  1999,  the  Company  consolidated  its  wholesale  gas  marketing
operations into the Denver,  Colorado office. In the fourth quarter of 1999, the
Company sold its retail gas marketing  operations in Colorado and  Pennsylvania.
In July 1999,  Black  Hills  Energy  Resources  acquired  a  minority  ownership
interest in a 200 mile pipeline  with a capacity of 67,000  barrels per day. The
majority owner and operator of the pipeline is Equilon Pipeline Company.

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

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

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

                           1999           1998           1997
                           ----           ----           ----
                                     (in thousands)
Revenues:
  Natural gas           $382,809        $375,934       $95,980*
  Crude oil              192,207         117,185        46,810*
  Coal                    39,212          12,924*            -

Daily Volumes:
  Natural gas
   (mmbtus)              486,800         487,000       231,000*
  Crude oil
   (barrels)              19,270          19,000        12,600*
  Coal (tons)              4,500           4,400*            -
*Since date of acquisition

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

Independent Power Production
----------------------------

In December  1999,  Black Hills  Generation  and Indeck  Capital,  Inc.  jointly
acquired  111  megawatts  of  natural   gas-fired   combustion   turbines  under
construction  in Colorado.  The project has a seven year tolling  agreement with
Public  Service  Company of Colorado and is expected to cost  approximately  $80
million. In-service date for the project is expected to be June of 2000.

In August  1999,  Black Hills  Generation  began  initial  engineering  and site
preparation for an 80 megawatt  coal-fired  electric  generation facility at the
Wyodak coal mine.

In January  2000,  the Company  announced  a  definitive  agreement,  subject to
certain conditions of closing including regulatory  approval,  to acquire Indeck
Capital, Inc., a privately held independent power producer.

                            COMMUNICATIONS OPERATIONS

In September  1998,  Black Hills Capital Group formed Black Hills Fiber Systems,
Inc. (formerly Black Hills FiberCom, Inc.). Black Hills Fiber Systems, Inc. owns
a 51  percent  equity  interest  in Black  Hills  FiberCom,  LLC which  provides
facilities-based  communication  services for Rapid City and the Northern  Black
Hills  of  South   Dakota.   The  Company   partnered   with  an   international
telecommunications  firm, GLA International,  of St. Louis,  Missouri,  to build
Black Hills FiberCom's 200 mile fiber optic backbone and a 500-mile hybrid fiber
coaxial (HFC) network in Rapid City and the Northern Black Hills.

<PAGE>

In the fourth  quarter of 1999,  the company  began  providing  state-of-the-art
technology  offering local and long distance telephone  service,  expanded cable
television  service,  Internet access, and high-speed data and video services to
residential and business customers.

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

At December 31, 1999 the Company had built 200 miles of fiber optic backbone and
100 miles of HFC plant and was serving business and residential customers.

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

                            ENVIRONMENTAL REGULATION

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

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

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

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

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

Because  the  1990  amendments  to the  Clean  Air  Act  have  been  or  will be
implemented and interpreted in the future, 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.

<PAGE>

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

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

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

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

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

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

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

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

<PAGE>

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

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

Cleanup costs recognized to date total approximately  $465,000,  of which amount
$379,000  has  been   reimbursed  from  the  South  Dakota   Petroleum   Release
Compensation  Fund. To date, no penalties,  claims or actions have been taken or
threatened against the Company because of this oil spill.

PCBs
----

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

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

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

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

A number of studies have examined the possibility of adverse health effects such
as  cancer  from  electromagnetic  fields  (EMF)  which are  caused by  electric
transmission and distribution facilities,  however, recent studies have shown no
adverse effects.  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.

<PAGE>

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, 1999,  the number of employees of the Company  (including  Black
Hills Power),  independent energy companies and communications  companies,  were
300, 105 and 70, respectively, for a total of 475 employees.

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


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

ITEM 2.   PROPERTIES

                               ELECTRIC PROPERTIES

The following table provides information on the generating plants of Black Hills
Power. During 1999, 99 percent of the fuel used in electric generation, measured
in Btus (British thermal units), was coal.

Generating Units
----------------

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

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

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

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

Black  Hills  Power  owns  transmission  lines and  distribution  systems in and
adjoining the communities served consisting of 447 miles of 230 kV, 530 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.

<PAGE>

                          INDEPENDENT ENERGY PROPERTIES

Independent energy properties consist of coal mining properties, oil and natural
gas properties, energy marketing properties and independent power properties.

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

Wyodak  Resources is engaged in mining and processing  sub-bituminous  coal near
Gillette  in  Campbell  County,  Wyoming,  and  owns or has user  rights  in the
necessary  mining,  processing  and  delivery  equipment  to  fulfill  its sales
contracts. The coal averages 8,000 Btus per pound. Mining rights to the coal are
based upon four federal  leases and one state lease.  The estimated  recoverable
coal from the leases as of  December  31,  1999 is  277,717,000  tons,  of which
19,934,000  tons are committed to be sold to the Wyodak Plant and  approximately
24,150,000 tons to Black Hills Power's other plants.

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

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 Natural Gas Properties
------------------------------

Black Hills  Exploration  and  Production  operates 298 wells as of December 31,
1999.  The  majority of these wells are in the Finn  Shurley  Field,  located in
Weston and Niobrara  Counties,  Wyoming.  Black Hills Exploration and Production
does not  operate,  but owns a  working  interest  in 284  producing  properties
located in the western and southern United States.  Black Hills  Exploration and
Production  also owns a 44.7  percent  non-operating  interest  in a natural gas
processing plant also located at the Finn Shurley Field.

Black  Hills  Exploration  and  Production  participated  in the  drilling of 52
exploratory  and  development   wells  in  1999.  Black  Hills  Exploration  and
Production's  average  working  interest in such wells was 17 percent,  or 9 net
wells.  A  development  well  is a well  drilled  within  the  presently  proved
productive  area  of an oil  and  gas  reservoir,  as  indicated  by  reasonable
interpretation  of available  data,  with the  objective of  completing  in that
reservoir.  An  exploratory  well is a well  drilled in search of a new,  as yet
undiscovered  oil or gas  reservoir  or to greatly  extend the known limits of a
previously discovered reservoir. Thirty-nine out of the 52 wells drilled in 1999
were  completed as producing  wells for an overall  drilling  success rate of 75
percent.

See the table in Note 10 of "NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS" for
Black  Hills  Exploration  and  Production's   estimated  quantities  of  proved
developed  and  undeveloped  oil and natural gas  reserves at December 31, 1999,
1998 and 1997,  and a  reconciliation  of the changes  between these dates using
constant product prices for the respective years.

<PAGE>

Energy Marketing Properties
---------------------------

In 1999,  Black Hills Energy  Resources  formed Black Hills  Millenium  Pipeline
Company to own a minority interest in a 200 mile pipeline in Texas. The pipeline
has a capacity of 67,000 barrels per day. The majority owner and operator of the
pipeline is Equilon  Pipeline  Company  LLC.  The pipeline is scheduled to begin
operations in the second quarter of 2000.

Independent Power Properties
----------------------------

In December  1999,  Black Hills  Generation  jointly  acquired 111  megawatts of
natural  gas-fired  combustion  turbines under  construction in Colorado.  Black
Hills Generation has a fifty percent interest (with Indeck Capital,  Inc. owning
the other fifty  percent).  The turbines are expected to be placed in service in
June 2000.

                            COMMUNICATIONS PROPERTIES

Black Hills  FiberCom,  LLC is a competitive  local exchange  carrier  providing
local and long-distance  telephone service, cable television and high speed data
services. At December 31, 1999 the company has 200 miles of fiber optic backbone
cable and 100 miles of hybrid fiber coaxial cable to service its customers. When
deployment is complete the company  expects to have  approximately  500 miles of
hybrid fiber coaxial cable. In addition, the company owns a building housing its
employees,  a central office switch and a cable  head-end.  The company also has
co-location rights within a US West Communications building.

ITEM 3.   LEGAL PROCEEDINGS

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

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

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

No matter was submitted to a vote of security  holders during the fourth quarter
of 1999.


<PAGE>


PART II

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

The  Company's  Common  Stock ($1 par  value)  is  traded on The New York  Stock
Exchange.  Quotations for the Common Stock are reported under the symbol BKH. At
year-end, the Company had 6,086 common shareholders of record. All 50 states and
the District of Columbia plus 10 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  2000  meeting,  the Board of
Directors raised the quarterly  dividend to 27.0 cents per share,  equivalent to
an annual increase of 4.0 cents per share.  This regular  quarterly  dividend is
payable  March 1, 2000.  Dividend  payment  dates are normally  March 1, June 1,
September 1, and December 1.

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

                            Year ended December 31, 1999
                       1st        2nd        3rd         4th
                       ---        ---        ---         ---
Dividends paid
  per share           $0.26    $0.26         $0.26      $0.26
Common stock
  Prices
     High             $26.50    $23.88       $25.63     $23.31
     Low              $21.00    $21.00       $22.19     $20.31

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



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

The following data was derived from the Company's audited financial statements.
<TABLE>
<CAPTION>
Years ended December 31                              1999             1998             1997             1996             1995
                                                     ----             ----             ----             ----             ----
                                                                     (in thousands, except per share amounts)
<S>                                                 <C>              <C>               <C>              <C>              <C>
Operating revenues                                  $791,875         $679,254          $313,662         $162,588         $149,817
Net income                                            37,067           25,808*           32,359           30,252           25,590
Per share of common stock:
    Earnings - basic and diluted                        1.73             1.19*            1.49              1.40            1.19
    Dividends paid                                      1.04             1.00             0.95              0.92            0.89
Total assets                                         674,806          559,417           508,741          467,354          448,830
Long-term debt                                       160,700          162,030           163,360          164,691          166,069
</TABLE>

Quarterly  financial data for the years  indicated (are summarized in thousands,
except per share amounts) as follows:
<TABLE>
<CAPTION>
                                                                      1st               2nd              3rd              4th
                                                                      ---               ---              ---              ---
<S>                                                                 <C>                <C>              <C>              <C>
Year ended December 31, 1999
Operating revenues                                                  $168,201           $186,195         $219,779         $217,700
Operating income                                                      15,980             13,786           16,675           15,450
Net income                                                             9,035              7,763            9,725           10,544
Earnings per share                                                       .42               .36              .45              .50

Year Ended December 31, 1998
Operating revenues                                                  $153,837           $161,334         $170,158         $193,925
Operating income                                                      14,875             13,915           17,603            2,840*
Net income                                                             8,544              7,497            9,616              151*
Earnings per share                                                       .39               .35              .45              .01*
</TABLE>

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

<PAGE>

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

In light of the  Company's  expansion  over the past two years into the areas of
communications  and independent  energy,  during the fourth quarter of 1999, the
Company formally  reorganized its operations into three distinct business units,
as follows:

o    The electric  utility  business  unit,  consisting of Black Hills Power and
     Light  Company.  This business unit supplies  electric  utility  service in
     western South Dakota, northeastern Wyoming, and southeastern Montana.

o    The  independent  energy  business  unit,  consisting  of Wyodak  Resources
     Development  Corp.,  Black Hills Exploration and Production,  Inc., Enserco
     Energy, Inc., Black Hills Energy Resources, Inc., Black Hills Coal Network,
     Inc.,  Black Hills Energy Capital,  Inc. and Black Hills  Generation,  Inc.
     This business unit engages in the production  and marketing of coal,  crude
     oil and natural gas.  Beginning in 2000,  this business unit is expected to
     expand into the production and marketing of electricity through its pending
     acquisition of Indeck Capital,  Inc. and the development and acquisition of
     other independent power interests.

o    The  communications  business unit,  consisting of a majority  ownership of
     Black Hills FiberCom,  L.L.C.  Black Hills FiberCom markets  communications
     services in Rapid City and the Northern  Black Hills of South Dakota.  This
     business unit also includes  DAKSOFT,  Inc.,  which primarily  develops and
     markets  internally  generated  computer software programs and services for
     the utility and communications industries.


                         LIQUIDITY AND CAPITAL RESOURCES

In 1999,  the Company  generated  cash from  operations  sufficient  to meet its
operating  needs,  pay dividends on common stock,  pay long-term debt maturities
and provide financing for the investment in independent  power assets.  Property
additions were primarily  financed through  increased  short-term debt and notes
payable.  In 1998 and 1997, the Company generated  sufficient  operating cash to
meet its operating  needs,  pay dividends and finance its capital  requirements.
The 1999 property additions consisted of 1) the electric utility business unit's
construction of a 40 megawatt  gas-fired  combustion  turbine,  modernization of
facilities and  replacement of equipment;  2) the  independent  energy  business
unit's oil and natural gas drilling program,  reserve acquisitions,  replacement
and/or  refurbishment  of mining  equipment  and  investment  in a joint venture
pipeline;  and  3)  the  communications   business  unit's  additions  primarily
represent the  deployment  of the  state-of-the-art  fiber optic  communications
network in Rapid City and the northern Black Hills of South Dakota.  The primary
capital requirements of the Company for the past three years were as follows:
<TABLE>
<CAPTION>

                                                                1999                1998                1997
                                                                ----                ----                ----
                                                                               (in thousands)
        <S>                                                    <C>                 <C>                 <C>
        Property additions:
          Electric utility                                     $31,911             $11,451             $12,484
          Independent energy                                    21,337              12,040               8,412
          Communications and other                              50,977               1,774                 191
        Independent power investments                           52,319                   -                   -
        Common stock dividends                                  22,602              21,737              20,540
        Energy marketing assets                                      -               1,960               7,232
        Maturities/redemptions of long-term debt                 1,330               1,331               1,534
                                                             ---------           ---------           ---------
                                                              $180,476             $50,293             $50,393
                                                              ========             =======             =======
</TABLE>

<PAGE>

Capital   requirements  for  projected   construction,   capital   improvements,
independent  energy  investments,   communications   network   construction  and
corporate  development  activities  for  the  next  three  years  are  estimated
(excluding  any impact of future  capital  projects  resulting  from the pending
Indeck Capital, Inc. acquisition) to be as follows:

<TABLE>
                                                               2000                2001                 2002
                                                               ----                ----                 ----
                                                                              (in thousands)
        <S>                                                 <C>                   <C>                <C>
        Electric utility                                    $  27,696             $13,490            $  13,338
        Independent energy                                     82,457              10,171               14,336
        Communications                                         19,441               4,519                4,795
        Corporate development                                  10,000              10,000               10,000
                                                             --------            --------             --------
                                                             $139,594             $38,180              $42,469
                                                             ========             =======              =======
</TABLE>

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

The electric utility's forecasted capital requirements include completion of the
construction of the 40 megawatt  gas-fired  combustion  turbine,  replacement of
equipment and modernization of facilities.

Independent  energy's  forecasted capital  requirements  include the pending $40
million acquisition of Indeck Capital, Inc., additional investment in the 111 MW
independent power project in Colorado,  oil and natural gas drilling program and
reserve  acquisitions and replacement of mining  equipment and  modernization of
facilities.  In addition to the above noted  independent  energy  business  unit
capital  requirements,  the pending acquisition of Indeck Capital is expected to
provide growth  opportunities in independent  power production  assets currently
estimated  to be in the  $25  million  to $50  million  range  annually  and the
proposed construction of an 80 MW coal-fired electric generating facility at the
Company's  coal mine  (WYGEN).  Such  projects  will be  evaluated  based on the
economics of each project and are expected to be funded through the  appropriate
mix of  construction  financing,  long-term and  short-term  debt  financing and
equity financing.

The communications business unit forecast primarily represents the completion of
the initial fiber optic network  build-out in Rapid City and the northern  Black
Hills in 2000 and extension of the system thereafter. Excluded from the forecast
are any additional  market  build-outs  which will be evaluated at that time and
are expected to be funded with the  appropriate mix of short-term  debt,  vendor
financing, long-term debt and equity.

Forecasted investment in corporate development activities is dependent on market
conditions  at the time and the  Company's  ability  to  identify  opportunities
consistent with its corporate strategy.

At December 31, 1999,  electric  operations is the only segment of the Company's
business with long-term debt. Long-term debt sinking fund requirements are: $1.3
million in 2000, $3.0 million in 2001 and $18.0 million in 2002.

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  $0.7  million is charged to  operations  as  reclamation  expense
annually.  As of December 31, 1999, accrued reclamation costs were approximately
$17.3 million.

The Company has a Dividend  Reinvestment  and Stock Purchase  Plan,  under which
shareholders  may purchase  additional  shares of Common Stock through  dividend
reinvestment  or optional  cash  payments  at 100 percent of the recent  average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market.  The Company used the open market purchase option for
all of 1999, 1998 and 1997.

The debt component of the Company's  capital  structure at December 31, 1999 and
1998 was 43 percent and 44 percent, respectively.

The Company plans to place  long-term  non-recourse  project level  financing in
2000 to fund independent energy's combustion turbines in Colorado.  In addition,
upon satisfaction of the conditions of closing,  including  regulatory approval,
the Company will issue equity and  preferred  stock to acquire  Indeck  Capital,
Inc.  The  Company  will  issue $36  million  of common  stock and $4 million of
preferred stock to fund the acquisition.

<PAGE>

With  expected  growth in the  independent  energy and  communications  business
units,  the Company  anticipates its long-term debt ratio will increase to 50-55
percent  in the next  five  years.  (See  ITEM 7.  MANAGEMENT'S  DISCUSSION  AND
ANALYSIS  OF  FINANCIAL   CONDITION   AND  RESULTS  OF   OPERATIONS-RESULTS   OF
OPERATIONS-Independent Power Production; and BUSINESS OUTLOOK STATEMENTS.)

The Company had $115  million and $12 million of unsecured  short-term  lines of
credit at December 31, 1999 and 1998,  respectively,  which  provide for interim
borrowings  and the  opportunity  for timing of permanent  financing.  There was
$96.6 million  outstanding  under these lines of credit as of December 31, 1999.
There are no compensating  balance  requirements  associated with these lines of
credit.

In addition to the above lines of credit, Black Hills Energy Resources has a $25
million  uncommitted  line of credit  with a  national  bank to  provide  credit
support  for  purchases  and sales of crude oil.  The  Company  does not provide
credit support for this agreement.  At December 31, 1999, there were outstanding
letters  of  credit  totaling  approximately  $13  million,  which  reduced  the
available credit to $12 million.

In addition to the above lines of credit,  Wyodak Resources has guaranteed a $25
million  line of credit  for  Enserco  to use to  guarantee  letters  of credit.
Enserco pays a 0.125  percent  facility fee on this line of credit.  At December
31, 1999, there were no balances outstanding on this line of credit. At December
31, 1999  Enserco  Energy,  Inc.  had $19.9  million in  outstanding  letters of
credit.

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

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

                             MARKET RISK DISCLOSURES

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

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

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

Operating margins earned by wholesale gas and crude oil marketing are relatively
insensitive to commodity price fluctuations since most of the purchase and sales
contracts do not contain fixed-price provisions.  Generally, prices contained in
these contracts are tied to a current spot or index price and, therefore, adjust
directionally with changes in overall market  conditions.  The Company generally
attempts to balance its  fixed-price  physical and financial  purchase and sales
commitments  in terms of contract  volumes,  and the timing of  performance  and
delivery  obligations.  However,  the Company may, at times,  have a bias in the
market,  within  established  guidelines,   resulting  from  management  of  its
portfolio.  To the  extent a net open  position  exists,  fluctuating  commodity
market  prices  can  impact  the  Company's  financial  position  or  results of
operations, either favorably or unfavorably. The net open positions are actively
managed,  and the impact of changing prices on the Company's financial condition
at a  point  in  time is not  necessarily  indicative  of the  impact  of  price
movements throughout the year.

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

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

The derivatives are not held for speculative  purposes but rather serve to hedge
the Company's exposure related to commodity purchases or sale commitments. Under
Emerging  Issues Task Force Issue No. 98-10,  "Accounting for Energy Trading and
Risk Management  Activities" (EITF 98-10), these transactions qualify as trading
activities  which must be  accounted  for at fair value.  As such,  realized and
unrealized  gains (losses) are recorded as a component of income.  Additionally,
because of the Company's back-to-back transaction strategy, gains or losses only
exist to the extent that the transactions are not effectively  matched.  Because
the Company does not speculate with "open"  positions,  substantially all of its
trading  activities  are  back-to-back  positions  where a  commitment  to buy a
commodity is matched  with a committed  sale or a financial  instrument.  During
1999, gains or losses on trading activities were not significant. The quantities
and maximum terms of derivative financial  instruments held for trading purposes
at December 31, 1999 and 1998 are as follows:
                                                      Max.
                              Volume Covered          Term
December 31, 1999                (MMBtu's)           (Years)
-----------------             --------------         -------
Natural gas futures
contracts purchased                  860,000            1
Natural gas basis swaps
purchased                         17,741,500            4
Natural gas basis swaps sold      18,390,517            4
Natural gas fixed for
float swaps purchased              9,490,486            1
Natural gas fixed for
float swaps sold                  10,994,521            1
Natural gas collar
transactions; puts
purchased, calls sold               408,500             1
Natural gas collar
transactions; calls
purchased, puts sold                318,500             1

                                                      Max.
                              Volume Covered          Term
December 31, 1998                (MMBtu's)           (Years)
-----------------             --------------         -------
Natural gas futures
contracts purchased              1,470,000              2
Natural gas swap
contracts purchased              7,989,096              3
Natural gas swap
contracts sold                   1,473,000              1

Non-trading Activities
----------------------

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

At December 31, 1999,  the Company had fixed rate for floating  rate price swaps
sold for 20,000 barrels per month for the year 2000 to hedge its crude oil price
risk,  with a fair value of $(0.5) million at December 31, 1999. At December 31,
1998, the Company did not have material crude oil derivatives in its non-trading
activities.  At December 31, 1997,  the company had price collars and fixed rate
for floating  rate price swaps to hedge crude oil price risk for 15,000  barrels
of oil per month,  resulting in the  recognition of $0.9 million of gains during
1998.

Credit Risk
-----------

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

<PAGE>

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

The  Company's  exposure to market risk for  changes in interest  rates  relates
primarily  to  the  Company's   short-term   investments   and  long-term   debt
obligations.  As stated in its policy,  the Company is adverse to principal loss
and ensures the safety and  preservation of its investments by limiting  default
risk, market risk, and reinvestment risk.

The  Company  mitigates  default  risk  by  investing  in  high  credit  quality
securities  consisting  primarily of tax-exempt Federal,  state and local agency
obligations  and by constantly  monitoring  the credit rating of any  investment
issuer or  guarantor  and by limiting  the amount of exposure to any one issuer.
The portfolio  includes only securities with active  secondary or resale markets
to ensure portfolio liquidity.  All short-term investments mature, by policy, in
two years or less.

The effect of a 100 basis point (1 percent) increase in interest rates would not
have a material  effect to the  Company's  results of  operations  or  financial
condition, due to the short-term duration of the investment portfolio.

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

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

The table below presents  principal (or notional)  amounts and related  weighted
average  interest  rates  by  year of  maturity  for  the  Company's  short-term
investments and long-term debt  obligations,  including  current  maturities (in
thousands).
<TABLE>
<CAPTION>
                                      2000        2001        2002         2003          2004        Thereafter        Total
                                      ----        ----        ----         ----          ----        ----------        -----
<S>                                 <C>          <C>        <C>          <C>           <C>           <C>              <C>
Cash equivalents
    Fixed rate                      $  16,482   $    -      $    -       $    -        $    -        $       -        $ 16,482
    Average interest rate                5.60%       -           -            -             -                -            5.60%
Available for sale securities
    Fixed rate                      $   6,556   $ 1,030     $    -       $    -        $    -        $       -        $  7,586
    Average interest rate                4.14%     4.39%         -            -             -                -            4.18%
Total investment securities         $  23,038   $ 1,030     $    -       $    -        $    -        $       -        $ 24,068
    Average interest rate                5.19%     4.39%         -            -             -                -            5.15%

Long-term debt
    Fixed rate                      $   1,330   $ 3,029     $ 18,018     $ 3,068       $ 1,955       $  134,630       $162,030
    Average interest rate                9.11%     9.24%        6.96%       9.24%         9.37%            8.20%          8.12%
</TABLE>

<PAGE>


                                 RATE REGULATION

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

As of  January  1, 2000 the rate  freeze  period of the 1995  South  Dakota  and
Wyoming rate cases relating to the inclusion of NS#2 into rate base expired.  In
June of 1999, the SDPUC approved a settlement  between Black Hills Power and the
commission  staff,  which  extended  the rate freeze from  January 1, 2000,  for
another five years.

The South Dakota settlement  provides that absent an extraordinary event occurs,
Black Hills Power may not file for any  increase in its rates or invoke any fuel
and purchased  power  adjustment  tariff to take effect during the freeze period
ending January 1, 2005. The specified extraordinary events are: new governmental
impositions  increasing annual costs in South Dakota above $2.0 million,  forced
outages of both the Wyodak  Plant and NS #2  projected  to  continue at least 60
days,  forced outages occurring to either plant which are continued for a period
of three months and is  projected  to last at least nine months,  an increase in
the Consumers Price Index at a monthly rate for six months which would result in
a 10 percent or more annual  inflation rate, the loss of a South Dakota customer
or revenue from an existing South Dakota customer that would result in a loss of
$2.0 million or more during any  12-month  period,  Black Hills  Power's cost of
coal to its South  Dakota  customers  increases  and is projected to increase by
more than $2.0  million  over the cost for the most recent  calendar  year,  and
electric  deregulation  as a result of either  federal  or state  mandate  which
allows any customer of Black Hills Power to choose its  provider of  electricity
at any time during the freeze period.

During the freeze  period,  except as  identified  above,  Black  Hills Power is
undertaking  the  risks of  machinery  failure,  load  loss  caused by either an
economic downturn or changes in regulation, increased costs under existing power
purchase   contracts   over  which  the  Company  has  no  control,   government
interferences,  acts of nature and other  unexpected  events  that  could  cause
material losses of income or increases in costs of doing business.  However, the
settlement  anticipates that Black Hills Power will retain during that period of
time earnings realized from more efficient  operations,  sales from load growth,
and off-system sales of power and energy.

In 1998, Black Hills Power initiated an effort to enter into a new contract with
its largest  industrial  customers.  This effort was  expanded in 1999.  The new
contracts  contain "meet or release"  provisions which grant Black Hills Power a
five-year  right to continue  to serve a customer in the event of  deregulation.
Additionally,  Black Hills Power,  through a new General  Service Large Optional
Combined  Account  Billing  Tariff,  has allowed  general  service  customers to
aggregate their loads,  which also includes a provision for a five-year right to
continue  to serve  such  customer  in the event of  deregulation.  Black  Hills
Power's  "meet  or  release"  contracts  now  total  more  than  95 MW of  large
commercial and industrial  load.  These contracts  provide Black Hills Power the
assurance of a firm local market for its power  resources,  should  deregulation
occur.  These  industrial  and large  commercial  customers,  together  with the
wholesale  power  sale  agreements  with the  City of  Gillette  and MDU,  equal
approximately 40 percent of Black Hills Power's firm load.

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 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 $0.6 million 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.

<PAGE>

                              RESULTS OF OPERATIONS

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

Company-wide revenues were $791.9 million, $679.3 million, and $313.7 million in
1999, 1998, and 1997, respectively,  representing 17% and 117% increases in 1999
and 1998,  respectively.  These revenue  increases  resulted  primarily from the
acquisitions  and growth in the  energy  marketing  segment  of the  independent
energy business unit.

The Company  reported record earnings for 1999, due primarily to sales growth in
the electric utility business unit,  improved results in the independent  energy
business unit partially offset by expected start-up losses in the communications
business unit.  Consolidated  net income for 1999 was $37.1 million  compared to
$25.8  million  in 1998 and $32.4  million in 1997 or $1.73 per  average  common
share in 1999,  compared to $1.19 and $1.49 per average common share in 1998 and
1997,  respectively.  This  equates to a 17.1  percent,  12.5  percent  and 15.8
percent return on year-end common equity in 1999, 1998 and 1997, respectively.

In 1998, the Company  recorded an $8.8 million  (net-of-tax)  charge to earnings
related to a write down of certain oil and natural gas  properties.  Absent this
charge, the Company's earnings per average common share for 1998 would have been
$1.60, and a return on year-end common equity would have been 16.1 percent.  The
write down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties.  Absent other
factors impacting depletion expense,  the Company expects to continue to realize
the benefit of reduced future depletion  expense per unit of production  because
of this write down.

Dividends  paid on common stock totaled $1.04 per share in 1999.  This reflected
increases  approved by the Board of  Directors  from $1.00 per share in 1998 and
$0.95 per share in 1997.  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  maintain the  Company's  payout ratio in the low
60's.  Management believes this objective is attainable through earnings growth.
The  Company's  three year  dividend  growth rate was 4.1 percent and the payout
ratio for 1999 was 60 percent.

In January  2000 the Board of Directors  increased  the  quarterly  dividend 3.8
percent to 27 cents per share.  If this dividend is  maintained  during 2000, it
will be equivalent to $1.08 per share, an annual increase of 4 cents per share.

Revenue and net income (loss)  provided by each business unit as a percentage of
the Company's total revenue and net income, were as follows:

                                1999        1998        1997
                                ----        ----        ----
Revenue:
   Electric utility              17%        19%         40%
   Independent
     energy                      83         81          60
   Communications                 -          -           -
                                ----       ----        ----
                                100%       100%        100%
                                ====       ====        ====

                               1999        1998        1997
                               ----        ----        ----
Net Income (Loss):
   Electric utility             74%         96%         68%
   Independent
     energy                     31           5          33
   Communications               (5)         (1)         (1)
                               ----        ----        ----
                               100%        100%        100%
                               ====        ====        ====

The electric utility business unit has continued its stable growth both in terms
of revenue and earnings over the past two years.  Management believes this trend
is stable and, absent system  outages,  will continue for the next several years
due to the five-year  extension of the electric  utility's  rate freeze in 1999.
(See RATE REGULATION above.)

Management  believes that  opportunities  exist to continue the  improvement  of
results from the existing  operations of the  independent  energy business unit.
The coal mining and  exploration  and production  segments of this business unit
have  provided,  and are  expected to continue to provide,  stable cash flow and
operating  results.  Management  believes  that the refocused  energy  marketing
segments of this business unit will become  profitable in 2000.  Management also
believes the Company's entry into the independent  power generation  business in
2000, through the pending acquisition of Indeck Capital, Inc. and the completion
of the construction of the 111 MW of gas-fired  combustion  turbines in Colorado
will have a positive impact on the independent  energy business unit in terms of
future  growth  and  earnings.  (See  BUSINESS  OUTLOOK  STATEMENTS  SECTION  OF
MANAGEMENT'S DISCUSSION AND ANALYSIS.)

<PAGE>

While   management   expects   continued  losses  in  the  near  term  from  the
communications   business   unit  as  the   development   of  the  fiber  optics
communications  system in Rapid City and the  Northern  Black Hills  progresses,
management  believes the long-term  strategy  related to this business unit will
result in increasing earnings and cash flows. Growth opportunities also exist in
the deployment of this technology in other markets.

EBITDA represents the sum of earnings before interest,  taxes,  depreciation and
amortization.

EBITDA:
o    is not intended to be a  performance  measure that should be regarded as an
     alternative  either to  operating  income or net income as an  indicator of
     operating performance or to cash flows as a measure of liquidity;

o    is not intended to represent funds  available for debt service,  dividends,
     reinvestment,  or other  discretionary uses; and

o    should not be  considered  in isolation or as a substitute  for measures of
     performance  prepared in  accordance  with  generally  accepted  accounting
     principles.

EBITDA is included  because our management  believes that EBITDA is a meaningful
measurement commonly used by the investment community.  Our definition of EBITDA
may not be identical to similarly titled measures reported by other companies.

Electric Utility Business Unit
------------------------------

                             1999         1998         1997
                                     (in thousands)

Revenue                    $133,222      $129,236     $126,497
Operating expenses
                            80,936         79,340       81,886
                           --------      --------    ---------
Operating income           $ 52,286      $ 49,896    $  44,611
                           ========      ========    =========
Net income                 $ 27,286      $ 24,825    $  22,106
                           ========      ========    =========
EBITDA                     $ 68,299      $ 64,936    $  59,544
                           ========      ========    =========

Electric  revenue  increased  3.1  percent  in 1999  compared  to a 2.2  percent
increase in 1998. Firm kilowatthour sales decreased 0.1 percent in 1999 compared
to a 0.4 percent  decrease in 1998. The increase in electric revenue in 1999 was
primarily  due to stable  firm  sales  combined  with a 20 percent  increase  in
off-system sales. Degree days, a measure of weather trends, were 9 percent below
1998 and 13 percent below normal.  The increase in electric  revenue in 1998 was
primarily  due to a 60  percent  increase  in  non-firm  sales  and a 2  percent
increase  in  commercial  sales  partially  offset  by  4  percent  decrease  in
industrial sales primarily due to Homestake's  restructuring.  Firm kilowatthour
sales declined slightly due to Homestake but total  kilowatthour sales increased
4 percent  primarily due to a 33 percent  increase in off-system  sales.  Degree
days were 2 percent below 1997 and 4 percent below normal.

Revenue  per  kilowatthour  sold was 5.4 cents in 1999 and 1998  compared to 5.5
cents in 1997.  The number of customers in the service area  increased to 57,709
in 1999 from 56,856 in 1998 and 56,269 in 1997.  The  revenue  per  kilowatthour
sold in 1999 reflects the 20 percent  increase in wholesale  non-firm sales. The
revenue  per  kilowatthour  sold in 1998  reflects  the 33 percent  increase  in
wholesale non-firm sales to 371,100 megawatthours.  The revenue per kilowatthour
sold in 1997 reflects the increased  wholesale sales to MDU's Sheridan,  Wyoming
customers and 279,600 megawatthours of wholesale non-firm sales.

Operating  expenses  have  remained  fairly  stable  over the last three  years.
Operating  expenses  increased  2.0 percent in 1999,  primarily due to increased
purchase power expense,  operations and maintenance  expenses and  depreciation,
partially offset by lower fuel expense. Operating expenses decreased 3.1 percent
in 1998,  primarily due to lower purchased power costs and strong operating cost
management,  partially offset by increased property taxes and fuel expense. 1998
purchased  power costs  declined  due to the  renegotiated  Pacific  Power Sales
Agreement. (See ITEM 1. BUSINESS - ELECTRIC POWER SUPPLY - Pacific Power's Power
Sales Agreement.)

<PAGE>

Firm energy sales are forecasted to increase over the next 10 years at an annual
compound  growth  rate  of  approximately  1  percent  with  the  system  demand
forecasted to increase 2 percent. The Company currently has a winter peak of 344
MWs  established  in December 1998 and a summer peak of 361 MWs  established  in
July 1999.  These  forecasts are from studies  conducted by the Company with the
help of outside  consultants  whereby Black Hills Power's  service  territory is
examined and analyzed to estimate changes in the needs for electrical energy and
demand over a 20-year period. These forecasts are only estimates, and the actual
changes in electric sales may be substantially  different.  However, in the past
the forecasts tracked actual sales within a band of reasonableness over a period
of several  years.  Weather  deviations  can adversely  affect energy sales when
compared to forecasts based on normal weather.

Independent Energy Business Unit
--------------------------------

                              1999          1998         1997
                              ----          ----         ----
                                       (in thousands)
Revenue:
  Coal                       $ 31,095     $ 31,413      $ 31,080
  Gas and oil                  10,075        9,204         9,763
  Energy marketing            614,228      505,245       142,790
  Other                         2,977        4,156         3,532
                             --------     --------      --------
     Total revenue            658,375      550,018       187,165
Expenses                      644,196      536,048*      172,866
                             --------     --------      --------
Operating income             $ 14,179     $ 13,970*     $ 14,299
                             ========     ========      ========
Net income                   $ 11,882     $ 10,068*     $ 10,471
                             ========     ========      ========
EBITDA                       $ 25,016     $ 22,530      $ 21,672
                             ========     ========      ========

* Excludes $13.5 million  pre-tax  non-cash  charge relating to certain oil
and gas assets ($8.8 million net-of-tax)

Following  is a summary  of coal,  oil and gas  production  sales and  marketing
volumes:

                              1999          1998          1997
                              ----          ----          ----
Tons of coal sold          3,180,000    3,280,000     3,251,000
Barrels of oil sold          318,000      344,000       299,000
Mcf of natural gas sold
                           2,791,000    2,056,000     1,747,000
Equivalent barrels
  of oil sold                783,000      687,000       590,000
Daily volume (energy marketing):
   Natural gas - mmbtus      486,800      487,000       231,000*
   Crude oil - barrels        19,270       19,000        12,600*
   Coal - tons                 4,500        4,400*           -
* Since the acquisition date

The combined independent energy business unit's revenues increased 20 percent in
1999  and 194  percent  in  1998.  In  October  1998,  the  Company  acquired  a
controlling  interest  in  Enserco  Energy,  Inc.  (this  was an  equity  method
investment of the Company in 1997).  In September,  1998,  the Company  acquired
Black Hills Coal Network,  Inc. In July 1997,  the Company  acquired Black Hills
Energy Resources, Inc. The revenue increases in 1999 and 1998 were primarily the
result of consolidating these three energy marketing companies'  operations from
the time of the acquisitions.  Additionally, revenues increased in both years as
a result of increased volumes and increased product prices in 1999. The combined
independent  energy business unit's operating  income and EBITDA  (excluding the
non-cash  charge in 1998)  have been  stable  during  1999,  1998 and 1997.  The
combined  independent  energy  business unit's 1999 net income was improved over
1998 net income  (excluding the non-cash charge in 1998) primarily due to record
gas production,  improved oil prices,  lower  depletion  expense and the sale of
certain  retail  gas  marketing  books in 1999,  partially  offset by a non-cash
write-down of certain  intangible assets relating to the wholesale gas marketing
office in Houston.

Coal Mining
-----------

Wyodak  Resources'  coal mining  operation  has been very stable during the past
three years,  producing  operating  income of $12.6  million,  $12.7 million and
$12.2 million in 1999, 1998 and 1997, respectively;  net income of $9.7 million,
$9.6 million and $9.1 million in 1999, 1998 and 1997,  respectively;  and EBITDA
of $15.7  million,  $15.6  million  and $15.3  million  in 1999,  1998 and 1997,
respectively.  Wyodak Resources expects decreased sales in 2000 due to a planned
five-week  outage at the Wyodak Plant. The decrease in tons of coal produced and
sold in 1999 was primarily the result of a ten-day  planned outage at the Wyodak
Plant and a planned outage at one of Black Hills Power's plants.

<PAGE>

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

Black Hills Exploration and  Production's  operational  results were as follows
(excluding the non-cash charge in 1998 as discussed in the  introduction to this
section):  operating  income of $4.0  million,  $1.2 million and $2.9 million in
1999, 1998 and 1997, respectively;  net income of $2.5 million, $0.8 million and
$2.1 million in 1999, 1998 and 1997,  respectively;  and EBITDA of $6.9 million,
$6.4 million and $7.2 million in 1999, 1998 and 1997, respectively.  Black Hills
Exploration and Production's  record operating income and net income in 1999 are
primarily a result of record  natural gas  production,  higher crude oil prices,
and reduced  depletion due to the  combination  of higher  product  prices and a
reduced  depletable  basis  due to the  non-cash  charge  in 1998.  Black  Hills
Exploration and Production's 1998 operating results were decreased  primarily as
a result of  historically  low crude oil prices,  which not only reduced revenue
but also  increased  depletion  expense  (lower  oil and gas  prices  reduce the
economically  recoverable  reserve  amounts  causing an  increase  in  depletion
expense).  Black Hills Exploration and Production recognized  approximately $2.6
million,  $4.9  million and $3.9  million of depletion  expense  (excluding  the
write-down in 1998) in 1999, 1998, and 1997, respectively.

Following is a summary of Black Hills  Exploration and  Production's oil and gas
reserves at December 31:

                                     1999       1998       1997
                                     ----       ----       ----
Barrels of oil (in millions)          4.1        2.4        2.5
Mmcf of natural gas                  19.5       16.0        9.1

Black Hills Exploration and Production's  reserves are based on reports prepared
by Ralph E. Davis  Associates,  Inc., an independent  consulting and engineering
firm.  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.  The  increase in  reserves  at  December  31, 1999 was due to improved
drilling results, reserve acquisitions and improved product prices. The increase
in  reserves  at  December  31,  1998 was due to natural  gas  acquisitions  and
improved drilling results despite lower product prices.  Black Hills Exploration
and  Production  intends to  increase  its net proved  reserves  by  selectively
increasing  its  oil and  gas  exploration  and  development  activities  and by
acquiring producing properties.

Energy Marketing
----------------

The energy marketing  companies  (Black Hills Energy  Resources,  Inc.,  Enserco
Energy,  Inc.,  and Black Hills Coal Network,  Inc.) have produced the following
results:  operating  income  (loss) of $(2.4)  million,  $0.0 million and $(0.8)
million in 1999,  1998 and 1997,  respectively;  a net loss of $(0.3) million in
each  1999 and  1998 and a $(0.7)  million  loss in  1997;  and  EBITDA  of $2.5
million,  $0.6 million and $(0.7) million in 1999, 1998 and 1997,  respectively.
During 1999,  the energy  marketing  companies  sold certain of their retail gas
marketing  operations,  resulting  in  after-tax  gains  of  approximately  $1.8
million.  In 1999, revenue and the related cost of sales increased primarily due
to a full year of Black Hills Coal  Network  operations  (acquired  in September
1998),  increased  product  prices and  increased  oil  volumes  marketed.  1999
operating  income was  reduced by a non-cash  write-down  of certain  intangible
assets  relating to the wholesale gas marketing  office in Houston in the amount
of approximately $1.2 million (net-of-tax).

The  energy   marketing   companies   generate  large  amounts  of  revenue  and
corresponding  expense  related to buying and selling  energy  products.  Energy
marketing  is  extremely  competitive,  and  margins are  typically  very small.
Management  believes  that the  synergies the energy  marketing  companies  will
derive from the  independent  energy  business  unit's  continued  growth of its
exploration  and  production  business  and  expansion  into  independent  power
production  will allow the  energy  marketing  companies  to  generate  improved
operating results in future years.

<PAGE>

Independent Power Production
----------------------------

In 1999, 1998 and 1997 independent power production results were not significant
to the Company.  In 2000, the Company believes the independent  power production
segment will increase  revenues,  earnings and cash flow. (see BUSINESS  OUTLOOK
STATEMENTS SECTION OF MANAGEMENT'S DISCUSSION AND ANALYSIS.)

Communications Business Unit
----------------------------

                              1999         1998         1997
                              ----         ----         ----
                                      (in thousands)
Revenue                      $    278    $       -    $       -
Operating expenses              4,852        1,087          471
                             --------    ---------    ---------
Operating loss               $ (4,574)   $  (1,087)   $    (471)
                             =========   =========    =========
Net loss                     $ (1,262)   $    (280)   $    (218)
                             =========   =========    =========
EBITDA                       $ (2,626)      $ (570)   $    (238)
                             =========   =========    =========

In September 1998, Black Hills Capital Group formed Black Hills FiberCom,
Inc. to provide facilities-based communications services for Rapid City, and the
Northern Black Hills of South Dakota. The communications  business unit, through
Black Hills  FiberCom,  has invested  more than $52 million in  state-of-the-art
technology that will offer local and long distance telephone  service,  expanded
cable  television  service,  Internet  access,  and  high-speed  data and  video
services. Further capital expenditures of approximately $29 million are expected
over the next three years to complete  the build out of the fiber optic  network
and to acquire (for sale to customers) customer premise equipment.

The Company is  marketing  the  communications  services to schools,  hospitals,
cities, economic development groups, and business and residential customers, and
began  serving  customers  in late 1999.  In 1999,  the  operating  losses  were
primarily due to start-up  organizational costs,  increased depreciation expense
and increased  interest expense associated with the capital  deployment.  By the
end of 2000,  management expects to have passed 17,000 homes and serve more than
3,000 business access lines.  While continued  operating  losses are expected as
the build out is completed,  management expects that the communications business
unit will have positive cash flow from operating activities by 2001.  Management
expects to continue to build value through continued expansion of its network in
this market beyond 2000.

DAKSOFT,  Inc. was  incorporated  by the Company in 1994,  to develop and market
internally  generated  computer software  associated with the Company's business
segments. Additionally,  DAKSOFT has developed other products and services which
are currently being used internally and marketed to third parties.

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

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

Management had previously  formed a Year 2000 Committee to review and ensure the
Company's compliance with what is commonly known as the "Year 2000 problem".  In
addition,  consultants reviewed the Company's state of readiness.  The Company's
review encompassed supporting information technology systems, product generation
and distribution systems, and business supply chain systems and infrastructure.

The cost of either  repairing or replacing  certain  business  systems to ensure
business  continuance  beyond Year 2000 did not have a significant impact on the
results of  operations.  The cost of the Year 2000  project  was funded  through
operating cash flows. These costs are primarily  attributable to the purchase of
new  software  and  equipment  which  are  expensed  or  capitalized  on a basis
consistent with the Company's accounting policies for capital assets.

Other than  seeking  representations  and  assurances  from third  parties,  the
Company has not made an assessment as to whether any of its customers, suppliers
or  service  providers  will be  affected  by the  date  change.  The  Company's
business,  financial  condition  and  results  of  operations  may be  adversely
impacted should the efforts of customers, suppliers or service providers for the
Company to address the Year 2000 issue prove to be inadequate.

<PAGE>

The Company's risk management  program  includes  emergency  backup and recovery
procedures to be followed in the event of failure of a business-critical system.
These  procedures  were to include  specific  procedures for potential Year 2000
issues.  Contingency  plans to  protect  the  business  from  Year  2000-related
interruptions  are in place and  include,  for  example,  development  of backup
procedures,  identification  of alternate  suppliers  and possible  increases in
safety inventory levels.

Management  presently believes that with the modifications made to the Company's
existing  software and  conversions  to new software,  the Year 2000 problem has
been mitigated.

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

In June, 1999, FASB issued Statement of Financial  Accounting  Standards No. 137
"Accounting for Derivative  Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133." This statement  delayed the effective
date of FASB Statement No. 133 until fiscal years beginning after June 15, 2000.

                           BUSINESS OUTLOOK STATEMENTS

Recent Developments and Acquisitions
------------------------------------

Black Hills Generation,  Inc. and Black Hills Energy Capital, Inc. represent the
Company's  entry into the independent  power  generation  business.  In December
1999,  Black  Hills  Generation,  Inc.  acquired  a 50%  interest  in a  limited
liability  company  that is  constructing  three  gas-fired  combustion  turbine
peaking units that have a total capacity of approximately  111 megawatts.  These
facilities  are scheduled to become  operational  in the second quarter of 2000,
and the  production  has been sold to Public  Service of Colorado  under a seven
year tolling  arrangement.  Ultimately,  upon closure of the contemplated Indeck
Capital,  Inc. acquisition in 2000 (see next paragraph),  the independent energy
business  unit will control 100% of these three  facilities  as Indeck  Capital,
Inc.  currently  owns the other 50% interest.  At December 31, 1999, the Company
had  funded  approximately  $52  million of the  expected  $80  million  capital
requirements  associated with these three peaking units through notes receivable
from the limited liability company.  Management and Indeck Capital,  Inc. expect
to close on  non-recourse  project level  financing in the first quarter of 2000
related to these projects.

In  January  2000,  the  Company  announced  that it had  reached  a  definitive
agreement to acquire 100% of Indeck Capital,  Inc. a privately-held  independent
power company that owns and operates certain  independent power facilities,  and
has direct or indirect investments in other independent power facilities.  As of
January 1, 2000,  Indeck  Capital,  Inc.'s net  megawatt  interest in  operating
facilities or development  projects is  approximately  240 megawatts,  which are
primarily  concentrated in hydro-electric and gas-fired  generating  facilities.
The pending  acquisition is subject to certain conditions of closing,  including
regulatory approval, and management expects to close this acquisition during the
first six months of 2000.  Indeck Capital,  Inc. will be merged into Black Hills
Energy Capital,  Inc. upon closure of the acquisition.  Management believes this
acquisition,  when completed,  will have a positive impact on earnings, and will
enable  the  Company  to  further  its  expansion  into  the  independent  power
generation business in the future.

Black Hills  Generation has begun initial  engineering  and site  preparation to
build an 80 megawatt  coal-fired  electric  generating  plant to be known as the
WYGEN Project adjacent to the electric utility business unit's Neil Simpson Unit
#2.

Future Communications Activities
--------------------------------

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

<PAGE>


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

In  connection  with  the  safe  harbor  provisions  of the  Private  Securities
Litigation  Reform Act of 1995  ("Reform  Act"),  the  Company is hereby  filing
cautionary statements  identifying important factors that could cause our actual
results to differ materially from those projected in forward-looking  statements
(as such term is defined in the Reform  Act) made by or on behalf of the Company
in this Annual Report on Form 10K, Annual Report, quarterly report on Form 10-Q,
and presentations, or in response to questions or otherwise. Any statements that
express or involve discussions as to expectations,  beliefs, plans,  objectives,
assumptions or future events or performance (often, but not always,  through the
use  of  words  or  phrases  such  as  "anticipates,"  "believes,"  "estimates,"
"expects,"  "intends,"  "plans,"  "predicts,"  "projects," "will likely result,"
"will  continue," or similar  expressions) are not statements of historical fact
and may be forward-looking.

Forward-looking statements involve estimates, assumptions, and uncertainties and
are  qualified in their  entirety by reference to, and are  accompanied  by, the
following   important   factors,   which  are  difficult  to  predict,   contain
uncertainties,  are beyond our control,  and may cause actual  results to differ
materially from those contained in forward-looking statements:

o    Prevailing governmental policies and regulatory actions, including those of
     the Federal Energy Regulatory Commission, the South Dakota Public Utilities
     Commission,  the Wyoming Public  Service  Commission and the Montana Public
     Service Commission,  with respect to allowed rates of return,  industry and
     rate  structure,   acquisition  and  disposal  of  assets  and  facilities,
     operation and construction of plant facilities, recovery of purchased power
     and other capital  investments,  and present or  prospective  wholesale and
     resale  competition  (including  but not  limited  to retail  wheeling  and
     transmission costs);

o    Economic and geographic factors, including political and economic risk;

o    Changes in and compliance with environmental and safety laws and policies;

o    Weather conditions;

o    Population growth rates and demographic patterns;

o    Competition for retail and wholesale customers;

o    Pricing and transportation of commodities;

o    Market demand, including structural market changes;

o    Changes in tax rates or policies or in rates of inflation;

o    Changes in project costs;

o    Unanticipated changes in operating expenses and/or capital expenditures;

o    Capital market conditions;

o    Technological advances;

o    Competition for new energy development opportunities; and

o    Legal  and  administrative  proceedings  (whether  civil or  criminal)  and
     settlement that influence the business and profitability of the Company.

Any forward-looking statement speaks only as to the date on which that statement
is made, and the Company undertakes no obligation to update any  forward-looking
statement  to  reflect  events or  circumstances  after  the date on which  that
statement is made or to reflect the  occurrence  of an  anticipated  event.  New
factors  emerge from time to time,  and it is not  possible  for  management  to
predict all such factors, nor can it assess the impact of any such factor on the
business or the extent to which factor,  or  combination  of factors,  may cause
results  to  differ  materially  from  those  contained  in any  forward-looking
statement.


<PAGE>


ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

         Report of Independent Public Accountants                           33

         Consolidated Statements of Income and Retained Earnings
           for the three years ended December 31, 1999                      34

         Consolidated Statements of Cash Flows for
           the three years ended December 31, 1999                          35

         Consolidated Balance Sheets as of December 31, 1999 and 1998       36

         Consolidated Statements of Capitalization as of
           December 31, 1999 and 1998                                       37

         Notes to Consolidated Financial Statements                         38



                    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,
1999 and 1998,  and the  related  consolidated  statements  of income,  retained
earnings and cash flows for each of the three years in the period ended December
31, 1999.  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 auditing standards generally accepted
in the United States. 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,  1999  and  1998,  and the  results  of their
operations  and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting  principles  generally accepted
in the United States.

                                                        ARTHUR ANDERSEN LLP



Minneapolis, Minnesota,
January 26, 2000


<PAGE>



                             BLACK HILLS CORPORATION
                        CONSOLIDATED STATEMENTS OF INCOME


Years ended December 31              1999               1998               1997
                                     ----               ----               ----
                                      (in thousands, except per share amounts)
Operating revenues:
    Electric utility             $133,222           $129,236           $126,497
    Independent energy            658,375            550,018            187,165
    Communications                    278                  -                  -
                                ---------         ----------          ---------
                                  791,875            679,254            313,662
                                ---------         ----------          ---------
Operating expenses:
    Fuel and purchased power      637,302            531,518            177,071
    Operations and maintenance     36,463             32,701             31,743
    Administrative and general     18,272             15,747             12,113
    Depreciation, depletion and
     amortization                  25,067             24,037             22,311
    Oil and gas ceilings test
     write down                         -             13,546                  -
    Taxes, other than income
     taxes                         12,880             12,472             11,985
                                ---------          ---------          ---------
                                  729,984            630,021            255,223
                                ---------          ---------          ---------

Operating income                   61,891             49,233             58,439
                                ---------          ---------          ---------

Other income (expense):
    Interest expense              (15,460)           (14,707)           (14,123)
    Investment income               3,614              2,861              2,136
    Other, net                      2,811                129                233
                               ----------          ---------          ---------
                                   (9,035)           (11,717)           (11,754)
                               ----------          ---------          ---------
Income before income taxes         52,856             37,516             46,685
Income taxes                      (15,789)           (11,708)           (14,326)
                               ----------          ---------          ---------
          Net income            $  37,067           $ 25,808           $ 32,359
                               ==========          =========          =========

Earnings per share of common stock:
    Basic and diluted               $1.73              $1.19              $1.49
                               ==========          =========          =========

Weighted average common shares outstanding:
    Basic                          21,445             21,623             21,692
                               ==========          =========          =========
    Diluted                        21,482             21,665             21,706
                               ==========          =========          =========


                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

Years ended December 31           1999               1998               1997
                                  ----               ----               ----
                                               (in thousands)

Balance, beginning of year      $147,774           $143,703            $131,884
Net income                        37,067             25,808              32,359
Cash dividends on common stock
($1.04, $1.00 and $0.95  per
share, respectively)             (22,602)           (21,737)            (20,540)
                              ----------         ----------          ----------

Balance, end of year            $162,239           $147,774            $143,703
                              ==========         ==========          ==========

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


<PAGE>


                             BLACK HILLS CORPORATION
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>

Years ended December 31                                                  1999              1998               1997
                                                                         ----              ----               ----
                                                                                      (in thousands)
<S>                                                                     <C>               <C>                 <C>
Operating activities:
    Net income                                                          $37,067           $25,808             $32,359
    Principal non-cash items-
      Depreciation, depletion and amortization                           25,067            24,037              22,311
      Oil and gas ceilings test write down                                    -            13,546                   -
      Gain on sales of retail energy marketing assets                    (2,541)                -                   -
      Deferred income taxes and investment tax credits                    2,291            (2,535)              2,457
    Increase in receivables, inventories and other
      current assets                                                     (1,771)          (49,775)            (27,067)
    Increase in current liabilities                                      10,281            43,709              26,015
    Other, net                                                            5,284               (60)                (26)
                                                                     ----------       -----------          ----------
                                                                         75,678            54,730              56,049
                                                                      ---------          --------            --------

Investing activities:
    Property additions, excluding allowance for other
      funds used during construction                                   (104,225)          (25,265)            (21,087)
    Independent power investment                                        (52,319)                -                   -
    Energy marketing assets                                                   -            (1,960)             (7,232)
    Proceeds from sales of retail energy marketing                        3,463                 -                   -
    Available for sale securities purchased                              (7,870)          (22,361)            (31,944)
    Available for sale securities sold                                   22,959            13,655              29,433
                                                                      ---------         ---------           ---------
                                                                       (137,992)          (35,931)            (30,830)
                                                                     ----------         ---------           ---------

Financing activities:
    Dividends paid                                                      (22,602)          (21,737)            (20,540)
    Treasury stock purchased                                             (4,949)           (3,081)                  -
    Common stock issued                                                     424               273                 409
    Increase (decrease) in short-term borrowings                         92,489             5,067                (120)
    Long-term debt retired                                               (1,330)           (1,331)             (1,534)
                                                                     ----------        ----------           ---------
                                                                         64,032           (20,809)            (21,785)
                                                                      ---------         ---------            --------

      Increase (decrease) in cash and cash equivalents                    1,718            (2,010)              3,434

Cash and cash equivalents:
    Beginning of year                                                    14,764            16,774              13,340
                                                                      ---------         ---------            --------
    End of year                                                        $ 16,482          $ 14,764             $16,774
                                                                       ========          ========             =======

Supplemental disclosure of cash flow information:

    Cash paid during the period for-
      Interest                                                          $18,819           $14,742             $14,167
      Income taxes                                                      $13,173           $13,135             $11,840
</TABLE>

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


<PAGE>


                             BLACK HILLS CORPORATION
                           CONSOLIDATED BALANCE SHEETS

At December 31,                                1999                 1998
                                               ----                 ----
                                                    (in thousands)
    ASSETS
Current assets:
    Cash and cash equivalents                $  16,482            $  14,764
    Securities available for sale                7,586               22,675
    Receivables, net
      Customers                                 84,331               87,068
      Other                                     55,694                2,919
    Materials, supplies and fuel                14,278                9,733
    Prepaid expenses                             2,828                3,321
                                           -----------          -----------
                                               181,199              140,480
                                           -----------          -----------
Property and equipment:
    Electric utility                           526,945              501,164
    Independent energy                         132,331              116,000
    Communications                              50,621                2,209
    Other                                          591                  176
                                           ------------         ------------
                                                710,488              619,549
    Less accumulated depreciation
      and depletion                            (246,299)            (229,942)
                                           ------------         ------------
                                                464,189              389,607
                                           ------------         ------------
Deferred charges:
    Federal income taxes                         11,472               12,347
    Regulatory asset                              3,944                3,978
    Other                                        14,002               13,005
                                           ------------         ------------
                                                 29,418               29,330
                                           ------------         ------------
                                               $674,806             $559,417
                                           ============         ============
    LIABILITIES AND CAPITALIZATION
Current liabilities:
    Current maturities of long-term debt     $    1,330           $    1,330
    Notes payable                                97,579                5,090
    Accounts payable                             80,355               74,087
    Accrued liabilities-
      Taxes                                       8,357                9,950
      Interest                                    4,119                3,956
      Other                                      13,612                8,169
                                           ------------          -----------
                                                205,352              102,582
                                           ------------          -----------
Deferred credits:
    Federal income taxes                         59,140               55,107
    Investment tax credits                        3,022                3,514
    Reclamation liability                        17,315               17,000
    Regulatory liability                          5,179                5,661
    Other                                         7,492                6,857
                                           ------------          -----------
                                                 92,148               88,139
                                           ------------          -----------

Capitalization, per accompanying statements:
    Common stock equity                         216,606              206,666
    Long-term debt                              160,700              162,030
                                           ------------          -----------
                                                377,306              368,696
                                           ------------          -----------
                                               $674,806             $559,417
                                           ============          ===========

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

<PAGE>


                             BLACK HILLS CORPORATION
                    CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>

At December 31,                                                                      1999                 1998
                                                                                     ----                 ----
                                                                                          (in thousands)
<S>                                                                               <C>                  <C>
Common stock equity:
    Common stock $1 par value; 50,000,000 shares authorized;
      21,739,030 and 21,719,465 shares outstanding, respectively                  $  21,739            $  21,719
    Additional paid-in capital                                                       40,658               40,254
    Retained earnings                                                               162,239              147,774
    Treasury stock                                                                   (8,030)              (3,081)
                                                                                -----------          -----------
         Total common stock equity                                                  216,606              206,666
                                                                                -----------          -----------


Long-term debt:
    First mortgage bonds-
      6.50% due 2002                                                                 15,000               15,000
      9.00% due 2003                                                                  4,255                5,295
      8.06% due 2010                                                                 30,000               30,000
      9.49% due 2018                                                                  5,420                5,710
      9.35% due 2021                                                                 35,000               35,000
      8.30% due 2024                                                                 45,000               45,000
                                                                                -----------            ---------
                                                                                    134,675              136,005
                                                                                -----------            ---------

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

      Total long-term debt                                                          162,030              163,360

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

      Net long-term debt                                                            160,700              162,030
                                                                                -----------           ----------

      Total capitalization                                                         $377,306             $368,696
                                                                                ===========           ==========

</TABLE>

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


<PAGE>

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        December 31, 1999, 1998 and 1997


 (1)  BUSINESS DESCRIPTION AND SUMMARY
      OF SIGNIFICANT ACCOUNTING
      POLICIES

Business Description
--------------------

Black Hills  Corporation and its subsidiaries  operate in three primary business
segments:  electric utility,  independent  energy (includes coal mining, oil and
natural gas operations,  energy marketing and independent power production), and
communications.  The  Company's  electric  utility  operation  is engaged in the
generation, purchase, transmission,  distribution and sale of electric power and
energy in western South Dakota,  northeastern Wyoming and southeastern  Montana.
Sales of electric power to the three largest electric  customers  represented 16
percent of the  Company's  electric  revenue in 1999,  17 percent in 1998 and 18
percent  in  1997.  The  coal  mining  operation  of  the  Company,  located  in
northeastern  Wyoming,  mines  and sells  sub-bituminous  coal  primarily  under
long-term  coal supply  agreements.  As  discussed in Note 6,  approximately  80
percent of the coal mining  operation's sales are to the Wyodak Plant.  Sales of
coal to the  Company and to  PacifiCorp,  herein  referred to as Pacific  Power,
represent  97 percent of total coal  sales in 1999.  The  Company's  oil and gas
exploration  and  production  business  operates  and has working  interests  in
properties  located in the western and southern  United  States.  The  Company's
energy marketing  businesses  market natural gas, crude oil and coal and provide
related  energy  services  to  customers  in the West  Coast,  Northwest,  Rocky
Mountain,   Southwest,   Midwest   and  East  Coast   markets.   The   Company's
communications  operations provide communication  services to Rapid City and the
Northern  Black Hills of South Dakota and a software  development  and marketing
company.

Principles of Consolidation
---------------------------

The  consolidated  financial  statements  include  the  accounts  of Black Hills
Corporation and its wholly-owned and  majority-owned  subsidiaries.  The company
owns 51  percent of the voting  securities  of Black  Hills  FiberCom  LLC.  The
minority  interest  is shown in Other,  net in the  Consolidated  Statements  of
Income.

All significant  intercompany  balances and transactions have been eliminated in
consolidation except for revenues and expenses associated with intercompany coal
sales in accordance  with the  provisions  of Statement of Financial  Accounting
Standards  (SFAS)  No. 71,  "Accounting  for the  Effects  of  Certain  Types of
Regulation."  Total  intercompany  coal sales not  eliminated  were  $7,664,000,
$10,256,000 and $11,089,000 in 1999, 1998, and 1997, respectively.

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

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

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

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

<PAGE>

Property
--------

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

The Company  periodically  evaluates assets under SFAS No. 121,  "Accounting for
the Impairment of Long-Lived  Assets and  Long-Lived  Assets to Be Disposed Of,"
which  requires that such assets be probable of future  recovery at each balance
sheet date. As of December 31, 1999 and 1998, no write-down was required.

Depreciation and Depletion
--------------------------

Depreciation  is computed  using the  straight-line  method  over the  estimated
useful lives of the related  assets.  Depreciation  provisions  for the electric
property were  equivalent to annual  composite  rates of 3.1 percent in 1999 and
3.0 percent in 1998 and 1997.  Composite  depreciation  rates for other property
were  5.7  percent,  7.9  percent,  and 8.1  percent  in 1999,  1998  and  1997,
respectively. Depletion of coal and oil and gas properties is computed using the
cost method for financial reporting.

Available for Sale Securities
-----------------------------

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

Revenue Recognition
-------------------

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

Use of Estimates
----------------

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

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

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

Allowance for Funds Used During Construction
--------------------------------------------

Allowance for funds used during  construction  (AFDC) represents the approximate
composite  cost of  borrowed  funds  and a return  on  capital  used to  finance
construction  expenditures  and is  capitalized  as a component  of the electric
property.  The AFDC was computed at an annual  composite  rate of 8.3 percent in
1999, 10.1 percent in 1998 and 10.0 percent in 1997.

Income Taxes
------------

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

<PAGE>

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

Price Risk Management
---------------------

Effective January 1, 1999, the Company adopted the provisions of Emerging Issues
Task Force Issue No. 98-10,  "Accounting  for Energy Trading and Risk Management
Activities"  ("EITF 98-10") pursuant to the implementation  requirements  stated
therein. The resulting effect of adoption of the provisions of EITF 98-10 was to
alter the  Company's  comprehensive  method  of  accounting  for  energy-related
contracts,  as defined in that  statement.  The effect of the  adoption  of EITF
98-10 was not material to the 1999 results of operations.

The Company now accounts for all energy  trading  activities at fair value as of
the  balance  sheet  date and  recognizes  currently  the net  gains  or  losses
resulting from the  revaluation of these  contracts to fair value in its results
of operations. As a result, substantially all of the operations of the Company's
gas  marketing,  crude  oil  marketing  and coal  marketing  operations  are now
accounted  for under a fair value  accounting  methodology.  Generally,  revenue
recognition for the Company's  coal, oil and natural gas production  activities,
as  well  as  its  power  generation  businesses,  remain  on  an  accrual-based
accounting methodology.  Sales and purchases by these businesses are not trading
operations,  as defined  in the  statement,  and  therefore  not  subject to the
provisions of EITF 98-10.

For  their  non-trading  activities,   the  Company  utilizes  deferral  (hedge)
accounting in conjunction with such financial instruments;  gains or losses from
changes in the market value of the financial  instruments are deferred until the
gain or loss on the hedged item is recognized for non-trading activities.

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

The  Company  continues  to analyze  the  effects of  adoption of the rules
promulgated by Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments  and  Hedging  Activities"  ("Statement  No.  133").  Provisions  in
Statement  No. 133 will affect the  accounting  and  disclosure  of  contractual
arrangements and operations of the Company.

Management  believes the  adoption of the  provisions  of Statement  No. 133 may
affect the variability of future periodic  results  reported by the Company,  as
well as its competitors,  as market  conditions and resulting  valuations change
from  time to time.  Such  earnings  variability,  if any,  will  likely  result
principally  from valuation  issues arising from  imbalances  between supply and
demand created by illiquidity in certain commodity markets resulting from, among
other  things,  a  lack  of  mature  trading  and  price  discovery  mechanisms,
transmission  and/or  transportation  constraints  resulting from  regulation or
other  issues in certain  markets  and the need for a  representative  number of
market  participants  maintaining  the financial  liquidity and other  resources
necessary to compete effectively.  Management will monitor exposure to these and
other market and business risks and will adjust valuation factors accordingly as
indicated by changing circumstances.

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

In June, 1999, FASB issued Statement of Financial  Accounting Standards No.
137 "Accounting for Derivative  Instruments and Hedging Activities - Deferral of
the  Effective  Date of FASB  Statement  No.  133." This  statement  delayed the
effective date of SFAS No. 133 until fiscal years beginning after June 15, 2000.

Reclassifications
-----------------

Certain 1998 and 1997 amounts in the financial statements have been reclassified
to conform to the 1999  presentation.  These  reclassifications  did not have an
effect on the Company's stockholders' investment or results of operations.

<PAGE>

(2)  CAPITAL STOCK

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

Net Income Per Share
--------------------

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

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

                               1999        1998         1997
                               ----        ----         ----
Net income                    $37,067     $25,808      $32,359
                              =======     =======      =======
Weighted average
  common shares
  outstanding-basic            21,445      21,623       21,692
Dilutive effect of
  option plan                      37          42           14
                              -------     -------      -------
Common and
  potential common
  shares outstanding-
  diluted                      21,482      21,665       21,706
                               ======      ======       ======
Basic and diluted net
  income per share              $1.73       $1.19        $1.49
                                =====       =====        =====

Common Stock
------------

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

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

                                1999        1998        1997
                                ----        ----        ----
                                       (in thousands)
Net income:
   As reported                $37,067     $25,808     $32,359
   Proforma                   $36,877     $25,717     $32,308

Earnings per share (basic and diluted):
   As reported                  $1.73       $1.19       $1.49
   Proforma                     $1.72       $1.19       $1.49

The Company may grant  options for up to 1,000,000  shares of common stock under
the Stock Option  Plan.  The Company has granted  options on 431,950  shares and
292,700  shares  through  December  31,  1999 and 1998,  respectively.  In 1999,
options on 1,000 shares were  forfeited.  No options were  forfeited in 1998. No
options were  exercised in 1999.  Options on 3,000 shares were exercised in 1998
at $22.88  per share and an  exercise  price of $16.67  per  share.  The  option
exercise  price  equals  the fair  market  value of the  stock on the day of the
grant. The options granted have an exercise price range of $16.67 to $25.00. The
options  granted vest  one-third a year for three years and all expire after ten
years from the grant date. At December 31, 1999 182,400  options were  available
for  exercise at an exercise  price range of $16.67 to $25.00.  At December  31,
1998,  84,800  options were available for exercise at an exercise price range of
$16.67 to $22.50.  At December  31, 1997,  27,900  options  were  available  for
exercise at an exercise price of $16.67.

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

                                1999        1998       1997
                                ----        ----       ----

Risk free interest rate          5.92%       5.50%       6.09%
Expected dividend yield          4.50%       4.20%       5.00%
Expected life                  10 years    10 years    10 years
Expected volatility             17.66%      16.67%      16.71%
Weighted average
   fair value                   $1.17       $0.61       $1.09

<PAGE>

The Company  issued  19,565,  12,824 and 29,294 shares of common stock under the
ESPP Plan in 1999, 1998 and 1997,  respectively.  At December 31, 1999,  247,570
shares are reserved and available for issuance  under the ESPP Plan. The Company
sells the shares to employees  at 90 percent of the stock's  market price on the
offering date. The fair value per share of shares sold in 1999 was $24.07.

The  Company has a Dividend  Reinvestment  and Stock  Purchase  Plan under which
shareholders  may purchase  additional  shares of common stock through  dividend
reinvestment  and/or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market.  The Company  purchased  shares on the open market in
1999, 1998 and 1997. At December 31, 1999,  1,290,797  shares of unissued common
stock were available for future offerings under the Plan.

Additional Paid-in Capital
--------------------------

Changes in additional paid-in capital for the years indicated were:
                                   1999       1998        1997
                                   ----       ----        ----
                                         (in thousands)
Balance, beginning of year       $40,254     $39,995    $46,841
Stock Dividend for 3-for-2
   Common Stock split                  -           -     (7,235)
Premium, net of expenses
from sales of stock                  404         259        389
                               ---------   ---------  ---------
Balance, end of year             $40,658     $40,254    $39,995
                               =========   =========  =========

Treasury Stock

In April  1999,  the Board of  Directors  authorized  the  acquisition  of up to
700,000 shares of the Company's Common Stock on the open market to fund possible
future  acquisitions by the Company,  for its Employee Stock Option Plan and for
other general purposes.

A subsidiary of the Company was authorized to repurchase up to 600,000 shares of
common stock for similar  purposes.  At December  31, 1999, a subsidiary  of the
Company had reacquired 367,509 shares at an average price of $22.95 per share.


(3)     LONG-TERM DEBT

Substantially  all of the Company's  utility  property is subject to the lien of
the Indenture  securing its first  mortgage  bonds.  First mortgage bonds of the
Company  may be  issued in  amounts  limited  by  property,  earnings  and other
provisions of the mortgage  indentures.  Scheduled  maturities of long-term debt
for the next five years are: $1,330,000 in 2000, $3,029,000 in 2001, $18,018,000
in 2002, $3,068,000 in 2003 and $1,955,000 in 2004.

(4)     NOTES PAYABLE

The Company had  $115,000,000  and $12,000,000 of unsecured  short-term lines of
credit at December 31, 1999 and 1998  respectively.  There was  $96,640,000  and
$3,850,000 outstanding under these lines of credit at December 31, 1999 and 1998
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.

In addition to the above lines of credit, Black Hills Energy Resources, Inc. has
a $25,000,000,  uncommitted,  discretionary  credit facility.  The transactional
line of credit  provides  credit  support for the  purchases  of natural gas and
crude oil of Black Hills  Energy  Resources.  The  Company and its  subsidiaries
provide no guarantee to the Lender.  At December 31, 1999, and 1998, Black Hills
Energy   Resources  had  letters  of  credit   outstanding  of  $13,154,000  and
$27,990,000,  respectively,  and no balance outstanding on the overdraft line of
credit.

In addition to the above lines of credit,  Wyodak  Resources  has  guaranteed  a
$25,000,000  line of credit for Enserco to use to  guarantee  letters of credit.
Enserco pays a 0.125  percent  facility fee on this line of credit.  At December
31, 1999 and 1998, there were no balances outstanding on this line of credit. At
December 31, 1999,  Enserco Energy had  $19,900,000  in  outstanding  letters of
credit.

(5)     FAIR VALUE OF FINANCIAL
        INSTRUMENTS

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

<PAGE>

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, 1999 and 1998, and the fair
value approximates cost.

Long-Term Debt
--------------

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

                                                1999
                                                ----
                                            (in thousands)

                                        Carrying       Fair
                                         Amount        Value
                                        --------     --------
Cash and cash equivalents               $ 16,482     $ 16,482
Securities available for sale:
   Certificates of deposit                   550          550
   Federal, state and local
     agency obligations                    7,036        7,036
Long-term debt                           162,030      165,958

                                                 1998
                                                 ----
                                            (in thousands)

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

(6)     WYODAK PLANT

The Company owns a 20 percent  interest and Pacific Power an 80 percent interest
in the Wyodak Plant (the Plant), a 330 megawatt  coal-fired  electric generating
station located in Campbell  County,  Wyoming.  Pacific Power is the operator of
the Plant.  The  Company  receives  20 percent of the  Plant's  capacity  and is
committed to pay 20 percent of its  additions,  replacements  and  operating and
maintenance  expenses.  As of December 31, 1999, the Company's investment in the
Plant  included  $72,228,000  in electric  plant and  $24,028,000 in accumulated
depreciation.   The  Company's  share  of  direct  expenses  of  the  Plant  was
$4,940,000,  $5,835,000  and  $5,934,000  for the years ended December 31, 1999,
1998 and 1997, respectively,  and is included in the corresponding categories of
operating expenses in the accompanying consolidated statements of income. Wyodak
Resources  supplies coal to the Plant under an agreement expiring in 2013 with a
Pacific  Power  option to renew for 10 years.  This  coal  supply  agreement  is
collateralized  by a  mortgage  on and a  security  interest  in some of  Wyodak
Resources' coal reserves.  At December 31, 1999,  approximately  19,934,000 tons
were covered under this  agreement.  Wyodak  Resources'  sales to the Plant were
$24,883,000, $23,228,000 and $22,688,000, for the years ended December 31, 1999,
1998 and 1997, respectively.

(7)     COMMITMENTS AND CONTINGENT LIABILITIES

MDU Power Sale
--------------

On January 1, 1997,  the  Company  began  service  under a ten year  contract to
supply up to 55 megawatts of electric  power and associated  energy  required by
MDU for its Sheridan, Wyoming, service territory. The service area experienced a
44 megawatt peak in 1999 and a 47 megawatt peak in both 1998 and 1997.  The load
factor was approximately 57 percent for all three years.

<PAGE>

Coal Obligations
----------------

In addition to the 19,934,000  tons of coal reserved under the agreement to
supply coal to the Wyodak Plant,  Wyodak Resources has reserved  24,150,000 tons
of coal under existing contracts.

Coal Leases
-----------

Wyodak  Resources'  mining rights to its coal are based upon four federal leases
and one state lease. The federal leases provide for a royalty of 12.5 percent of
the selling price of the coal. The state lease provides for a royalty,  approved
in 1998,  currently at 9 percent.  Wyodak Resources paid royalties in the amount
of $3,968,000,  $4,009,000 and $3,969,000 in 1999, 1998, and 1997, respectively.
Each federal lease requires diligent development to produce at least one percent
of all recoverable  reserves within either 10 years from the respective dates of
the leases or 10 years from the date of  adjustment  of the  leases.  Each lease
further  requires a continuing  obligation  to mine,  thereafter,  at an average
annual  rate of at least one  percent of the  recoverable  reserves.  All of the
federal leases  constitute one logical mining unit which is treated as one lease
for the purpose of determining  diligent  development  and continuing  operation
requirements.

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

In 1983 the Company  entered into a 40 year power  agreement  with Pacific Power
providing  for the purchase by the Company of 75 megawatts of electric  capacity
and energy from  Pacific  Power's  system.  The price paid for the  capacity and
energy is based on the  operating  costs of one of  Pacific  Power's  coal-fired
electric   generating   plants.   Costs   incurred  under  this  agreement  were
$17,778,000, $17,458,000 and $20,251,000 in 1999, 1998 and 1997, 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 $700,000 is charged to operations as reclamation expense annually.
As  of  December  31,  1999,   accrued   reclamation  costs  were  approximately
$17,315,000.

Price Risk Management Activities
--------------------------------

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

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

The derivatives are not held for speculative  purposes but rather serve to hedge
the Company's exposure related to commodity purchases or sale commitments. Under
Emerging  Issues Task Force Issue No. 98-10,  "Accounting for Energy Trading and
Risk  Management  Activities"  ("EITF  98-10"),  these  transactions  qualify as
trading activities which must be accounted for at fair value. As such,  realized
and   unrealized   gains  (losses)  are  recorded  as  a  component  of  income.
Additionally,  because of the Company's back-to-back transaction strategy, gains
or losses only exist to the extent  that the  transactions  are not  effectively
matched.   Because  the  Company  does  not  speculate  with  "open"   positions
substantially all of its trading activities are "back-to-back" positions where a
commitment  to buy a commodity is matched  with a committed  sale or a financial
instrument.  During  1999,  gains  or  losses  on  trading  activities  were not
significant.

<PAGE>

The quantities and maximum terms of derivative  financial  instruments  held for
trading purposes at December 31, 1999 and 1998 are as follows:

                                                      Max.
                              Volume Covered          Term
December 31, 1999                (MMBtu's)           (Years)
-----------------             --------------         -------

Natural gas futures
contracts purchased                  860,000            1
Natural gas basis swaps
purchased                         17,741,500            4
Natural gas basis swaps
sold                              18,390,517            4
Natural gas fixed for
float swaps purchased              9,490,486            1
Natural gas fixed for
float swaps sold                  10,994,521            1
Natural gas collar
transactions; puts
purchased, calls sold               408,500             1
Natural gas collar
transactions; calls
purchased, puts sold                318,500             1


                                                      Max.
                              Volume Covered          Term
December 31, 1998                (MMBtu's)           (Years)
-----------------             --------------         -------

Natural gas futures
contracts purchased              1,470,000              2
Natural gas swap
contracts purchased              7,989,096              3
Natural gas swap
contracts sold                   1,473,000              1

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

At December 31, 1999,  the Company had fixed rate for floating  rate price swaps
sold for 20,000 barrels per month for the year 2000 to hedge its crude oil price
risk,  with a fair value of $(0.5) million at December 31, 1999. At December 31,
1998, the Company did not have material crude oil derivatives in its non-trading
activities.  At December 31, 1997,  the company had price collars and fixed rate
for floating  rate price swaps to hedge crude oil price risk for 15,000  barrels
of oil per month,  resulting in the  recognition of $0.9 million of gains during
1998.

Other
-----

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


(8)     EMPLOYEE BENEFIT PLANS

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

The Company has amended the plan to change the benefit  formula for  participant
service after February 1, 2000, in  conjunction  with a new Company match in the
401(k) plan. Additional amendments were made to increase retirement benefits for
pensioners who retired prior to January 1, 1995 and to adjust survivor benefits.
The combined impact of the amendments was to increase the net pension expense by
$170,000 and to increase the projected benefit obligation by $1,846,000.

<PAGE>

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

                                  1999        1998       1997
                                  ----        ----       ----
                                        (in thousands)

Service cost                   $   1,174     $   895    $    931
Interest cost                      2,598       2,406       2,383
Return on assets:
   Actual                        (12,477)     (2,007)    (10,278)
   Deferred                        8,314      (2,412)      7,022
                                --------     -------    --------
Net pension (income)
  expense                        $  (391)    $(1,118)   $     58
                                ========     =======    ========


Actuarial assumptions:
   Discount rate                    6.75%       7.5%        7.5%
   Expected long-term rate
     of return on assets           10.5%       10.5%       10.5%
   Rate of increase in
     compensation levels            5%          5%          5%


Funding  information  for the Plan as of October 1 each year was as follows (the
discount  rate  assumption  for  obligations  at 1999  was  7.5% and at 1998 was
6.75%):

                                          1999         1998
                                          ----         ----
                                            (in thousands)

Fair value of plan assets                $51,212     $40,638
Projected benefit obligation             (39,615)    (39,490)
                                        --------    --------
                                          11,597       1,148
Unrecognized:
   Net gain                              (12,105)       (200)
   Prior service cost                      2,285         528
   Transition asset                          (90)       (180)
                                        --------    --------
Prepaid pension cost                    $  1,687     $ 1,296
                                        ========    ========

Accumulated benefit obligation           $31,914     $31,323
                                        ========    ========

Vested benefit obligation                $29,214     $29,829
                                        ========    ========

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

                                  1999        1998       1997
                                  ----        ----       ----
                                        (in thousands)
Beginning projected
  benefit obligation             $39,490     $33,025     $32,722
Service cost                       1,174         895         931
Interest cost                      2,598       2,406       2,383
Actuarial gains (losses)          (3,590)      4,968      (1,215)
Benefits paid                     (1,903)     (1,804)     (1,796)
Plan amendments                    1,846           -           -
                                 -------     -------     -------
Net increase                         125       6,465         303
                                 -------     -------     -------
Ending projected
  benefit obligation             $39,615     $39,490     $33,025
                                 =======     =======     =======

<PAGE>

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

                                          1999         1998
                                          ----         ----
                                            (in thousands)
Beginning market value
  of plan assets                         $40,638     $40,435
Benefits paid                             (1,903)     (1,804)
Investment income                         12,477       2,007
                                         -------     -------
Ending market value
  of plan assets                         $51,212     $40,638
                                         =======     =======

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 $426,548, $395,000 and $94,000 in 1999,
1998,  and 1997,  respectively.  The Company  follows the provisions of SFAS No.
106,  "Employers'  Accounting for Postretirement  Benefits Other Than Pensions."
The standard  requires that the expected cost of these  benefits must be charged
to expense during the years that the employees render service. Prior to adopting
the standard in 1993, the Company expensed these benefits as they were paid. The
Company is amortizing  the  transition  obligation of $2,996,000  over a 20 year
period.

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

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

                                     1999       1998       1997
                                     ----       ----       ----
                                           (in thousands)

Service cost                         $225        $135       $168
Interest cost                         362         290        329
Amortization of transition
   obligation                         150         150        150
Amortization of (gain)/loss             1         (42)        (5)
                                     ----        ----       ----
                                     $738        $533       $642
                                     ====        ====       ====

Funding information as of October 1 was as follows:

                                              1999       1998
                                              ----       ----
                                               (in thousands)

Accumulated postretirement benefit
   obligation:
     Retirees                                 $2,608      $1,821
     Fully eligible active participants        1,195       1,033
     Other active participants                 3,278       2,576
                                             -------     -------
Unfunded accumulated postretirement
   benefit obligation                          7,081       5,430
Unrecognized net loss                         (1,667)       (301)
Unrecognized transition obligation            (1,947)     (2,097)
                                             -------     -------
                                              $3,467      $3,032
                                             =======     =======

For  measurement  purposes,  a 9.0 percent annual rate of increase in healthcare
benefits was assumed for 1999;  the rate was assumed to decrease  gradually to 6
percent in 2005 and remain at that level  thereafter.  The healthcare cost trend
rate assumption has a significant effect on the amounts reported.  A one percent
increase in the healthcare cost trend  assumption would increase the service and
interest  cost  $150,377  or  25.6%  and the net  periodic  postretirement  cost
$203,090 or 27.5%. A one percent  decrease would reduce the service and interest
cost by $113,659 or 19.3% and  decrease  the net  periodic  postretirement  cost
$122,663 or 16.6%.  The  weighted-average  discount rate used in determining the
accumulated postretirement benefit obligation was 7.5 percent.


<PAGE>

(9)      INCOME TAXES

Income tax expense for the years indicated was:
<TABLE>
<CAPTION>

                                                                               1999                 1998                 1997
                                                                               ----                 ----                 ----
                                                                                           (in thousands)
         <S>                                                                 <C>                   <C>                  <C>
         Current                                                             $13,498               $14,243              $11,869
         Deferred                                                              2,931                (1,886)               3,107
         Tax credits, net                                                       (640)                 (649)                (650)
                                                                             -------               -------              -------
                                                                             $15,789               $11,708              $14,326
                                                                             =======               =======              =======
</TABLE>

The temporary  differences  which gave rise to the net deferred tax liability at
December 31, 1999 and 1998 were as follows:
<TABLE>
<CAPTION>

                                                                                                                    Net Deferred
                                                                                                                       Income
                                                                                                                      Tax Asset
         December 31, 1999                                                   Assets             Liabilities          (Liability)
                                                                             ------             -----------          -----------
                                                                                                (in thousands)
         <S>                                                               <C>                    <C>                 <C>
         Accelerated depreciation and other plant-related differences      $       -              $48,223             $(48,223)
         Regulatory asset                                                      1,792                    -                1,792
         Regulatory liability                                                      -                1,380               (1,380)
         Unamortized investment tax credits                                    1,058                    -                1,058
         Mining development and oil exploration                                3,605                6,893               (3,288)
         Employee benefits                                                     2,833                  695                2,138
         Other                                                                 2,184                1,949                  235
                                                                           ---------            ---------            ---------
                                                                             $11,472              $59,140             $(47,668)
                                                                           =========            =========            =========

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

</TABLE>

<PAGE>

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

<TABLE>
<CAPTION>
                                                                            1999                  1998                 1997
                                                                            ----                  ----                 ----
         <S>                                                                <C>                   <C>                  <C>
         Federal statutory rate                                             35.0%                 35.0%                35.0%
         Regulatory asset recognition                                       (0.9)                 (0.7)                (1.3)
         Amortization of investment tax credits                             (1.1)                 (1.3)                (1.1)
         Tax-exempt interest income                                         (0.5)                 (1.1)                (0.9)
         Percentage depletion in excess of cost                             (1.6)                 (1.7)                (0.7)
         Other                                                              (1.0)                  1.0                 (0.3)
                                                                            ----                  ----                 ----
                                                                            29.9%                 31.2%                30.7%
                                                                            ====                  ====                 ====

</TABLE>

(10)       OIL AND GAS RESERVES  (Unaudited)

Black Hills  Exploration  and  Production has interests in 582 producing oil and
gas properties in seven states.  Black Hills  Exploration  and  Production  also
holds leases on approximately 132,162 net undeveloped acres.

The  following  table  summarizes  Black  Hills   Exploration  and  Production's
quantities  of proved  developed and  undeveloped  oil and natural gas reserves,
estimated using constant  year-end product prices, as of December 31, 1999, 1998
and 1997,  and a  reconciliation  of the  changes  between  these  dates.  These
estimates are based on reserve  reports by Ralph E. Davis  Associates,  Inc. (an
independent engineering company selected by the Company). Such reserve estimates
are based upon a number of  variable  factors  and  assumptions  which may cause
these estimates to differ from actual results.
<TABLE>
<CAPTION>
                                                          1999                          1998                        1997
                                                          ----                          ----                        ----
                                                    Oil           Gas            Oil            Gas           Oil           Gas
                                                                 (in thousands of barrels of oil and MMCF of gas)
<S>                                                  <C>          <C>             <C>          <C>              <C>         <C>
Proved developed and undeveloped reserves:
   Balance at beginning of year                      2,368        15,952          2,495         9,052           2,386       10,972
     Production                                       (309)       (2,801)          (353)       (2,068)           (299)      (1,747)
     Additions                                         376         7,718          1,149        10,721           1,146        3,498
     Property sales                                   (164)          (66)             -             -             (10)        (393)
     Revisions to previous estimates                 1,838        (1,343)          (923)       (1,753)           (728)      (3,278)
                                                   -------       -------        -------       -------         -------      -------

   Balance at end of year                            4,109        19,460          2,368        15,952           2,495        9,052
                                                   =======       =======        =======       =======         =======      =======

Proved developed reserves at end of
   year included above                               2,819        14,391          1,463        10,041           2,035        6,821
                                                   =======       =======        =======       =======         =======      =======

Year-end prices                                     $24.28         $1.99          $9.16         $1.93          $16.34        $2.32
                                                    ======         =====          =====         =====          ======        =====

</TABLE>


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

<PAGE>

(11)      BUSINESS SEGMENTS

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

Financial data for the business segments are as follows (in thousands):
<TABLE>
<CAPTION>

ASSETS                                     Independent Energy
                                --------------------------------------------
                                             Oil       Energy    Independent  Communications
At December 31, 1999 Electric    Mining    And Gas    Marketing     Power      & Others        Eliminations     Total
                    ---------   --------   --------   ---------  -----------  --------------   ------------   ----------
<S>                 <C>         <C>        <C>        <C>        <C>          <C>              <C>            <C>
Current assets      $  93,837   $ 57,393   $  1,988   $  79,709  $    52,471  $      9,732     $ (113,931)    $   181,199
Total assets          528,164    137,762     32,724      94,692       52,690        72,785       (244,011)        674,806

At December 31, 1998
Current assets      $  43,760   $ 25,538   $  1,335   $  77,397  $         4  $      6,406     $  (13,960)    $   140,480
Total assets          451,404     93,140     26,666      86,243           57        18,838       (116,931)        559,417
</TABLE>
<TABLE>
<CAPTION>
                                           Independent Energy
                                --------------------------------------------
YEAR TO DATE                                 Oil       Energy    Independent  Communications
December 31, 1999    Electric    Mining    And Gas    Marketing     Power      & Others        Eliminations      Total
                    ---------   --------   --------   ---------  -----------  --------------   ------------   -----------
<S>                 <C>         <C>        <C>        <C>        <C>          <C>              <C>            <C>
Electric revenues   $ 133,222   $      -   $      -   $       -  $         -  $            -   $          -   $   133,222
Coal revenues               -     31,095          -      39,212            -               -              -        70,307
Gas revenues                -          -      5,399     382,809            -               -              -       388,208
Oil revenues                -          -      4,676     192,207            -               -              -       196,883
Other revenues              -          -      2,977           -            -           3,423         (3,145)        3,255
                    ---------   --------   --------   ---------  -----------  --------------   ------------   -----------
Total revenues      $ 133,222   $ 31,095   $ 13,052   $ 614,228  $         -  $        3,423   $     (3,145)  $   791,875
                    ---------   --------   --------   ---------  -----------  --------------   ------------   -----------
Depreciation, depletion
 & amortization     $  15,552   $  3,259   $  2,953   $   2,757  $        -   $            -   $        546   $    25,067
Operating income
  (loss)               52,286     12,606      3,978      (2,248)       (157)          (4,574)             -        61,891
Interest expense       13,830        689        568         245         111               17              -        15,460
Income taxes           12,446      3,439        968          50         (58)          (1,056)             -        15,789
Net income (loss)      27,362      9,714      2,462        (185)       (109)          (1,262)          (915)       37,067
Property additions     31,911      5,422      9,968       5,947           -           50,977              -       104,225
</TABLE>

<TABLE>
<CAPTION>
                                           Independent Energy
                                --------------------------------------------
YEAR TO DATE                                 Oil       Energy    Independent  Communications
December 31, 1998    Electric    Mining    And Gas    Marketing     Power        & Others      Eliminations      Total
                    ---------   --------   --------   ---------  -----------  --------------   ------------   -----------
<S>                 <C>         <C>        <C>        <C>        <C>          <C>              <C>            <C>
Electric revenues   $ 129,236   $      -   $      -   $       -  $         -  $            -   $          -   $   129,236
Coal revenues               -     31,413          -      12,924            -               -              -        44,337
Gas revenues                -          -      4,073     375,136            -               -              -       379,209
Oil revenues                -          -      5,131     117,185            -               -              -       122,316
Other revenues              -          -      3,358         798            -           2,437         (2,437)        4,156
                    ---------   --------   --------   ---------- -----------  --------------   ------------   -----------
Total revenues      $ 129,236    $31,413   $ 12,562   $  506,043 $         -  $        2,437   $     (2,437)  $   679,254
                    ---------   --------   --------   ---------- -----------  --------------   ------------   -----------
Depreciation, depletion
 & amortization     $  14,881     $3,252   $ 18,760*  $      690 $         -  $           -    $          -   $    37,583
Operating income
  (loss)               49,896     12,723    (12,340)*         41           -         (1,087)              -        49,233
Interest expense       13,572          9        355          731           -             40               -        14,707
Income taxes           12,612      4,092     (4,689)*       (116)          -           (191)              -        11,708
Net income (loss)      24,825      9,585     (7,976)*       (346)          -           (280)              -        25,808
Property additions     11,451      1,447     10,169          424           -          1,774               -        25,265
Increase in goodwill        -          -          -        1,960           -              -               -         1,960
</TABLE>
*Includes the impact of a $13,546 million pretax write down of certain oil and
natural gas properties

<PAGE>

<TABLE>
<CAPTION>

                                           Independent Energy
                                --------------------------------------------
YEAR TO DATE                                 Oil       Energy    Independent  Communications
December 31, 1997    Electric    Mining    And Gas    Marketing     Power        & Others      Eliminations      Total
                    ---------   --------   --------   ---------  -----------  --------------   ------------   -----------
<S>                 <C>         <C>        <C>        <C>        <C>          <C>              <C>            <C>
Electric revenues   $ 126,497   $      -   $      -   $       -  $         -  $            -   $          -   $   126,497
Coal revenues               -     31,080          -           -            -               -              -        31,080
Gas revenues                -          -      4,223      95,980            -               -              -       100,203
Oil revenues                -          -      5,540      46,810            -               -              -        52,350
Other revenues              -          -      3,532           -            -             685           (685)        3,532
                    ---------   --------   --------   ---------  -----------  ---------------  ------------   -----------
Total revenues      $ 126,497   $ 31,080   $ 13,295   $ 142,790  $         -  $          685   $       (685)  $   313,662
                    ---------   --------   --------   ---------  -----------  ---------------  ------------   -----------

Depreciation, depletion
 & amortization     $  14,608   $  3,188   $  4,275   $     240  $         -  $            -   $          -   $    22,311
Operating income
  (loss)               44,611     12,217      2,907        (825)           -            (471)             -        58,439
Interest income        13,676          5        203         203            -              36              -        14,123
Income taxes            9,929      4,205        629        (347)           -             (90)             -        14,326
Net income (loss)      22,106      9,073      2,147        (749)           -            (218)             -        32,359
Property additions     12,484      1,336      7,076           -            -             191              -        21,087
Increase in goodwill        -          -          -       7,232            -               -              -         7,232

</TABLE>

(12)      SUPPLEMENTARY INCOME STATEMENT INFORMATION

Taxes Other than Income Taxes
                                           1999             1998         1997
                                           ----             ----         ----
                                                       (in thousands)
         Property                        $ 5,449           $ 4,993      $ 4,326
         Production and severance          3,264             3,437        3,654
         Payroll                           1,509             1,348        1,332
         Black lung                        1,311             1,324        1,310
         Federal reclamation               1,113             1,148        1,138
         Other                               234               222          225
                                         -------           -------      -------
                                         $12,880           $12,472      $11,985
                                         =======           =======      =======

(13)      QUARTERLY HISTORICAL DATA (Unaudited)

The company  operates on a calendar year basis.  The following  table sets forth
selected unaudited  historical  operating results for each quarter of 1999, 1998
and 1997.

                      First Quarter Second Quarter Third Quarter  Fourth Quarter
                      ------------- -------------- -------------  --------------
                                (in thousands, except per share amounts)
1999:
Total revenue          $   168,201   $    186,195   $   219,779     $   217,700
Income from operations      15,980         13,786        16,975          15,150
Net earnings                 9,035          7,763         9,725          10,544
Earnings per share            0.42           0.36          0.45            0.50

1998:
Total revenue          $   153,837   $    161,334   $   170,158     $   193,925
Income from operations      14,875         13,915        17,603           2,840*
Net earnings                 8,544          7,497         9,616             151*
Earnings per share            0.39           0.35          0.45            0.01*

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

<PAGE>
                      First Quarter Second Quarter Third Quarter  Fourth Quarter
                      ------------- -------------- -------------  --------------
                                (in thousands, except per share amounts)
1997:

Total revenue           $   43,879    $   40,259    $    98,182     $   131,342
Income from operations      15,629        12,742         15,573          14,495
Net earnings                 8,586         6,762          8,644           8,367
Earnings per share            0.39          0.31           0.40            0.39


(14)      SUBSEQUENT EVENTS

In  January  2000,  the  Company  announced  that it had  reached  a  definitive
agreement,  subject  to  certain  conditions  to  closing  including  regulatory
approval, to acquire 100% of Indeck Capital,  Inc. a privately-held  independent
power company that owns and operates certain  independent power facilities,  and
has direct or indirect  investments in other independent  power facilities.  The
proposed  purchase  price consists of $36 million of common stock and $4 million
of preferred stock. As of January 1, 2000,  Indeck Capital,  Inc.'s net megawatt
interest in operating  facilities or development  projects is approximately  240
megawatts,  which are primarily  concentrated  in  hydro-electric  and gas-fired
generating facilities.

In December  1999,  Black Hills  Generation,  Inc.  acquired a 50% interest in a
limited  liability  company  that is  constructing  three  gas-fired  combustion
turbine peaking units that have a total capacity of approximately 111 megawatts.
These  facilities  are scheduled to become  operational in the second quarter of
2000,  and the  production  has been sold to Public  Service of Colorado under a
seven year tolling  arrangement.  Ultimately,  upon closure of the  contemplated
Indeck Capital,  Inc.  acquisition in 2000, the independent energy business unit
will control 100% of these three  facilities as Indeck Capital,  Inc.  currently
owns the other 50%  interest.  At  December  31,  1999,  the  Company had funded
approximately  $52  million of the  expected  $80 million  capital  requirements
associated  with these three peaking units  through  notes  receivable  from the
limited   liability   company.   Such  notes  receivable  are  recorded  in  the
Consolidated  Balance  Sheets  in  Receivables,  Other.  Management  and  Indeck
Capital,  Inc.  expect to close on  non-recourse  project level financing in the
first quarter of 2000 related to these projects.



<PAGE>


FINANCIAL STATISTICS
<TABLE>
<CAPTION>

Years ended December 31,                                      1999             1998            1997            1996          1995
                                                              ----             ----            ----            ----          ----
<S>                                                         <C>              <C>             <C>             <C>           <C>
TOTAL ASSETS (in thousands)                                 $674,806         $559,417        $508,741        $467,354      $448,830

PROPERTY AND INVESTMENTS
     (in thousands)
    Total property and investments                          $710,488         $619,549        $598,306        $581,537      $557,642
    Accumulated depreciation and depletion                   246,299          229,942         197,179         181,103       164,383
    Capital expenditures (includes AFDC)                     104,225           27,225          28,319          24,388        51,895

CAPITALIZATION (in thousands)
    Long-term debt                                          $160,700         $162,030        $163,360        $164,691      $166,069
    Common stock equity                                      216,606          206,666         205,403         193,175       182,342
                                                           ---------        ---------       ---------       ---------     ---------

         Total capitalization                               $377,306         $368,696        $368,763        $357,866      $348,411
                                                            ========         ========        ========        ========      ========

CAPITALIZATION RATIOS
    Long-term debt                                            42.6%            43.9%           44.3%           46.0%         47.7%
    Common stock equity                                       57.4             56.1            55.7            54.0          52.3
                                                            ------           ------          ------          ------        ------
         Total                                               100.0%           100.0%          100.0%          100.0%        100.0%
                                                             =====            =====           =====           =====         =====

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

NET INCOME AVAILABLE FOR
    COMMON STOCK (in thousands)                              $37,067          $25,808*        $32,359         $30,252       $25,590

DIVIDENDS PAID IN COMMON STOCK
    (in thousands)                                           $22,602          $21,737         $20,540         $19,930       $19,312

COMMON STOCK DATA (in thousands)**

    Shares outstanding, average                               21,445           21,623          21,692          21,660        21,614
    Shares outstanding, end of year                           21,372           21,578          21,705          21,675        21,638

    Earnings per average share, in dollars                     $1.73            $1.19*          $1.49           $1.40         $1.19
    Dividends paid per share, in dollars                       $1.04            $1.00           $0.95           $0.92         $0.89
    Book value per share, end of year, in dollars             $10.14            $9.58           $9.46           $8.91         $8.43

RETURN ON COMMON STOCK EQUITY (year-end)
                                                               17.1%            12.5%*          15.8%           15.7%         14.0%

ALLOWANCE FOR FUNDS USED
    DURING CONSTRUCTION AS
    PERCENT OF NET INCOME                                       0.5%             0.9%            0.6%            1.2%         22.9%
</TABLE>

*Includes impact of $8.8 million,  or 41 cents per average share,  write down of
 certain oil and gas  properties.
**Common Stock Data reflects the 3-for-2 stock split on March 10, 1998.

<PAGE>


ELECTRIC OPERATION STATISTICS

<TABLE>
<CAPTION>
Years ended December 31,                                     1999           1998            1997           1996           1995
                                                             ----           ----            ----           ----           ----
<S>                                                      <C>              <C>             <C>             <C>            <C>
ELECTRIC ENERGY GENERATED AND
    PURCHASED (megawatt hours)
    Generated, net station output                          1,828,465       1,870,247      1,803,350       1,659,671      1,320,630
    Purchased and net interchange                            624,662         500,319        503,242         380,106        473,175
                                                         -----------     -----------     ----------      ----------     ----------
       Total generated and purchased                       2,453,127       2,370,566      2,306,592       2,039,777      1,793,805
    Company use and losses                                   (87,410)        (76,131)       (94,633)        (80,106)       (87,512)
                                                         -----------     -----------    -----------     -----------    -----------
       Total electric energy sales                         2,365,717       2,294,435      2,211,959       1,959,671      1,706,293
                                                           =========       =========      =========       =========      =========

ELECTRIC ENERGY SALES
    (megawatt hours)
    Residential                                              393,151         392,637        392,059         406,658        383,929
    General and commercial                                   564,286         561,292        547,624         541,463        513,854
    Industrial                                               521,073         527,157        556,554         555,601        552,829
    Public authorities                                        23,295          24,356         22,583          25,083         23,164
    Sales for resale                                         418,200         417,889        413,527         181,766        171,942
                                                          ----------      ----------     ----------      ----------     ----------
       Total firm electric energy sales                    1,920,005       1,923,331      1,932,347       1,710,571      1,645,718
    Non-firm sales                                           445,712         371,104        279,612         249,100         60,575
                                                          ----------      ----------     ----------     -----------    -----------
       Total electric energy sales                         2,365,717       2,294,435      2,211,959       1,959,671      1,706,293
                                                           =========       =========      =========       =========      =========

ELECTRIC REVENUE (in thousands)
    Residential                                           $   32,667      $   32,336     $   32,178       $  33,230      $  30,433
    General and commercial                                    42,619          42,221         41,452          41,307         37,663
    Industrial                                                25,043          25,713         26,802          26,915         26,495
    Public authorities                                         1,878           1,944          1,843           1,970          1,775
    Sales for resale                                          15,686          15,782         16,181           8,189          7,625
                                                          ----------      ----------     ----------      ----------     ----------
       Total firm electric revenue                           117,893         117,996        118,456         111,611        103,991
    Non-firm electric revenue                                  9,891           6,002          3,760           2,985            741
    Other electric revenue                                     5,438           5,238          4,281           4,122          4,051
                                                         -----------     -----------    -----------     -----------    -----------
       Total electric revenue                               $133,222        $129,236       $126,497        $118,718       $108,783
                                                            ========        ========       ========        ========       ========

ELECTRIC CUSTOMERS (end of year)
    Residential                                               47,571          46,967         46,656          46,146         45,886
    General and commercial                                     9,949           9,703          9,431           9,280          8,958
    Industrial                                                    43              44             39              37             35
    Public authorities                                           144             140            141             137            138
    Other electric utilities                                       2               2              2               1              1
                                                          ----------      ----------      ---------      ----------     ----------
        Total electric customers                              57,709          56,856         56,269          55,601         55,018
                                                          ==========      ==========      =========      ==========     ==========
</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
June 20, 2000.

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

Roxann R. Basham, 38, Vice President - Finance and Secretary/Treasurer
    Ms. Basham was elected to her present position in December 1997.
    She had served as Secretary/Treasurer since 1993.

David R. Emery, 37, Vice President - Fuel Resources
    Mr. Emery was elected to his present position in January 1997.  He had
    served as General Manager of Black Hills Exploration and Production since
    June 1993.

Gary R. Fish, 41, President and Chief Operating Officer of Independent Energy
    Business Unit
    Mr. Fish was elected to his present position in September 1999.  He had
    served as Vice President - Corporate Development since 1996 and as
    Controller since 1988.

Everett E. Hoyt, 60, President and Chief Operating Officer of Black Hills Power
    Mr. Hoyt was elected to his present position in October 1989.

James M. Mattern, 45, Senior Vice President - Corporate Administration and
    Assistant to the CEO
    Mr.  Mattern was elected to his present  position in September  1999. He had
    served as Vice President - Corporate Administration and Assistant to the CEO
    since 1997 and as Vice  President - Corporate  Administration  since January
    1994.

Thomas M. Ohlmacher, 48, Vice President - Power Supply
    Mr. Ohlmacher was elected to his present position in August 1994.  He had
    served as Director of Power Generation since 1993.

Ronald D. Schaible, 55, Senior Vice President and General Manager of
    Communications
    Mr. Schaible was elected to his present position in July 1999.  Previously,
    Mr. Schaible had served as Vice-President and General Manager for Brooks
    Fiber Properties, Inc. since 1995.

Mark T. Thies, 36, Controller
    Mr. Thies was elected to his present position in May 1997.  Previously,
    Mr. Thies had served in a number of accounting positions, most recently as
    Assistant Controller, at InterCoast Energy Company, a wholly owned
    subsidiary of MidAmerican Energy Holdings Company since 1990.

Kyle D. White, 40, Vice President - Marketing and Regulatory Affairs
    Mr. White was elected to his present position in July 1998. He had served as
    Vice  President  - Energy  Services  since  January  1998 and had  served as
    Director of Strategic Marketing and Sales since 1993.

<PAGE>

ITEM 11.       EXECUTIVE COMPENSATION

Information  regarding management  remuneration and transactions is incorporated
herein by reference to the Proxy Statement for the Annual Shareholders'  Meeting
to be held June 20, 2000.

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 June 20, 2000.

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 June 20, 2000.

PART IV

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

(a)      1.    Consolidated Financial Statements

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

         2.    Schedules

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

         3.    Exhibits

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

               *3(b)Bylaws dated  April 20,  1999.  (Exhibit  4(b) to Form S-8
                    dated July 13, 1999.)

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

<PAGE>

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

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

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

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

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

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

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

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

                10(t) Rate Freeze Extension

         21    Subsidiaries of the Registrant.

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

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

         27    Financial Data Schedule.

         99    Annual Report on Form 11-K of the Black Hills Corporation
               Employee Stock Purchase Plan for the year ended December 31,1999.


      *     Exhibits incorporated by reference.

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

<PAGE>


                                   SIGNATURES

         Pursuant to the  requirements  of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                         BLACK HILLS CORPORATION

                                         By    DANIEL P. LANDGUTH
                                         Daniel P. Landguth, Chairman,
                                         President and Chief Executive Officer
Dated:   March 10, 2000


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

       DANIEL P. LANDGUTH           Director and Principal        March 10, 2000
----------------------------------    Executive Officer
Daniel P. Landguth, Chairman,
President, and Chief Executive
Officer

       ROXANN R. BASHAM             Principal Financial Officer   March 10, 2000
----------------------------------
Roxann R. Basham, Vice President-Finance,
and Corporate Secretary/Treasurer

       MARK T. THIES                Principal Accounting Officer  March 10, 2000
----------------------------------
Mark T. Thies, Controller

       ADIL M. AMEER                Director                      March 10, 2000
----------------------------------
Adil M. Ameer

       BRUCE B. BRUNDAGE            Director                      March 10, 2000
----------------------------------
Bruce B. Brundage

       DAVID C. EBERTZ              Director                      March 10, 2000
----------------------------------
David C. Ebertz

       JOHN R. HOWARD               Director                      March 10, 2000
----------------------------------
John R. Howard

       EVERETT E. HOYT              Director and Officer          March 10, 2000
----------------------------------
Everett E. Hoyt (President and Chief
Operating Officer of Black Hills Power)

       KAY S. JORGENSEN             Director                      March 10, 2000
----------------------------------
Kay S. Jorgensen

       DAVID S. MANEY               Director                      March 10, 2000
----------------------------------
David S. Maney

       THOMAS J. ZELLER             Director                      March 10, 2000
----------------------------------
Thomas J. Zeller


<PAGE>


BOARD OF DIRECTORS AND OFFICERS


                               BOARD OF DIRECTORS

Daniel P. Landguth                       John R. Howard
  Chairman of the Board and                President
  Chief Executive Officer of the Company   Industrial Products, Inc.

Adil M. Ameer                            Everett E. Hoyt
  President and Chief Executive Officer    President and Chief Operating Officer
  Rapid City Regional Hospital             Black Hills Power and Light Company

Bruce B. Brundage                        Kay S. Jorgensen
  President and Director                   Owner - Jorgensen-Thompson
  Brundage & Company                       Creative Broadcast Services

David C. Ebertz                          David S. Maney
  President                                Co-founder
  Risk Management Consulting               Worldbridge Broadband Services

                                         Thomas J. Zeller
                                           President
                                           RE/SPEC Inc.


                               CORPORATE OFFICERS


Daniel P. Landguth                        James M. Mattern
  Chairman of the Board and                 Senior Vice President-Corporate
  Chief Executive Officer of the Company    Administration and Assistant to
                                            the CEO

Roxann R. Basham                          Thomas M. Ohlmacher
  Vice President - Finance and              Vice President-Power Supply
  Corporate Secretary/Treasurer

David R. Emery                            Ronald D. Schaible
  Vice President - Fuel Resources           Senior Vice President and General
                                            Manager-Communications Business Unit

Gary R. Fish                              Mark T. Thies
  President and Chief Operating Officer-    Controller
  Independent Energy Business Unit

Everett E. Hoyt                           Kyle D. White
  President and Chief Operating Officer     Vice President-Marketing and
  Black Hills Power and Light Company       Regulatory Affairs